10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)
☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended September 30, 2024
	or
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _________________ to _______________________

Commission file number: 001-41558

PERMEX PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

British Columbia, Canada	98-1384682
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1700 Post Oak Boulevard, 2 Blvd Place Suite 600

Houston Texas, 77056

(Address of principal executive offices)

Registrant’s telephone number, including area code: (346) 245-8981

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

None

(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act: Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act: Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files): Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:

Large accelerated filer ☐	Accelerated filer ☐	Non-accelerated filer ☒	Smaller reporting company ☒
	☒ Emerging Growth Company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☒

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act): Yes ☐ No ☒

The aggregate market value of common shares held by non-affiliates of the registrant as of March 28, 2024 was approximately $1,774,686.

The number of outstanding shares of the registrant’s common shares as of January 14, 2025 was 551,503.

DOCUMENTS INCORPORATED BY REFERENCE

None

PERMEX PETROLEUM CORPORATION

FORM 10-K

TABLE OF CONTENTS
		PAGE
PART I
Item 1	Business	6
Item 1A	Risk Factors	18
Item 1B	Unresolved Staff Comments	35
Item 2	Properties	35
Item 3	Legal Proceedings	35
Item 4	Mine Safety Disclosures	35
PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	36
Item 6	Selected Financial Data	36
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 7A	Quantitative and Qualitative Disclosures about Market Risk	42
Item 8	Financial Statements and Supplementary Data	F-1
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	43
Item 9A	Controls and Procedures	43
Item 9B	Other Information	43
PART III
Item 10	Directors, Executive Officers and Corporate Governance	44
Item 11	Executive Compensation	47
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	51
Item 13	Certain Relationships and Related Transactions, and Director Independence	53
Item 14	Principal Accounting Fees and Services	54
Item 15	Exhibits, Financial Statement Schedules	55

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PERMEX PETROLEUM CORPORATION

FORM 10-K

As used in this Annual Report on Form 10-K, references to “Permex,” “the Company,” “we,” “us” and “our” are to Permex Petroleum Corporation, a corporation organized under the laws of British Columbia, Canada, individually, or as the context requires, collectively with its subsidiaries. Certain operational terms used in this Annual Report are defined in the “Glossary of Terms” section below. All references to “U.S. Dollars,” “USD” or “$” are to the legal currency of the United States, and all references to “CAD$” and “C$” are to the legal currency of Canada. All references to “M$” are in thousands of dollars.

GLOSSARY OF TERMS

Unless otherwise indicated in this Annual Report, natural gas volumes are stated at the legal pressure base of the state or geographic area in which the reserves are located at 60 degrees Fahrenheit. Crude oil and natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.

The following definitions shall apply to the technical terms used in this Annual Report.

Terms used to describe quantities of crude oil and natural gas:

“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGLs.

“Boe.” A barrel of oil equivalent and is a standard convention used to express crude oil, NGL and natural gas volumes on a comparable crude oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil or NGL.

“MBbl.” One thousand barrels of crude oil, condensate or NGLs.

“MBoe” One thousand barrels of oil equivalent.

“Mcf.” One thousand cubic feet of natural gas.

“MMCF.” one million cubic feet.

“NGLs.” Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.

Terms used to describe our interests in wells and acreage:

“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil, NGLs, and/or natural gas.

“Developed acreage.” Acreage consisting of leased acres spaced or assignable to productive wells. Acreage included in spacing units of infill wells is classified as developed acreage at the time production commences from the initial well in the spacing unit. As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.

“Development well.” A well drilled within the proved area of a crude oil, NGL, or natural gas reservoir to the depth of a stratigraphic horizon (rock layer or formation) known to be productive for the purpose of extracting proved crude oil, NGL, or natural gas reserves.

“Differential.” The difference between a benchmark price of crude oil and natural gas, such as the NYMEX crude oil spot price, and the wellhead price received.

“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.

“Gross acres or Gross wells.” The total acres or wells, as the case may be, in which a working interest is owned.

“Held by operations.” A provision in an oil and gas lease that extends the stated term of the lease as long as drilling operations are ongoing on the property.

“Held by production” or “HBP” A provision in an oil and gas lease that extends the stated term of the lease as long as the property produces a minimum quantity of crude oil, NGLs, and natural gas.

“Hydraulic fracturing.” The technique of improving a well’s production by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

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“Infill well.” A subsequent well drilled in an established spacing unit of an already established productive well in the spacing unit. Acreage on which infill wells are drilled is considered developed commencing with the initial productive well established in the spacing unit. As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.

“Net acres.” The percentage ownership of gross acres. Net acres are deemed to exist when the sum of fractional ownership working interests in gross acres equals one (e.g., a 10% working interest in a lease covering 640 gross acres is equivalent to 64 net acres).

“NYMEX.” The New York Mercantile Exchange.

“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Recompletion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil, NGLs or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible crude oil, NGLs and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Undeveloped acreage.” Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil, NGLs, and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage includes net acres held by operations until a productive well is established in the spacing unit.

“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Wellbore.” The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

“Working interest.” The right granted to the lessee of a property to explore for and to produce and own crude oil, NGLs, natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

“Workover.” Operations on a producing well to restore or increase production.

Terms used to assign a present value to or to classify our reserves:

“Possible reserves.” The additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.

“Pre-tax PV-10% or PV-10.” The estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the SEC.

“Probable reserves.” The additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but which together with proved reserves, are as likely as not to be recovered.

“Proved reserves.” The quantities of crude oil, NGLs and natural gas, which, by analysis of geosciences 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.

“Proved undeveloped reserves” or “PUDs.” Proved Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

“SEC Pricing” means pricing calculated using oil and natural gas price parameters established by current guidelines of the United States Securities and Exchange Commission (the “SEC”) and accounting rules based on the unweighted arithmetic average of oil and natural gas prices as of the first day of each of the 12 months ended on the given date.

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MARKET AND INDUSTRY INFORMATION

This Annual Report contains market data and industry statistics and forecasts that are based on independent industry publications and other publicly available information. Although we believe that these sources are reliable, we do not guarantee the accuracy or completeness of this information and we have not independently verified this information. Although we are not aware of any misstatements regarding the market and industry data presented in this Annual Report, these estimates involve risks and uncertainties and are subject to change based on various factors, including those discussed under the heading “Risk Factors”. Accordingly, investors should not place undue reliance on this information.

FORWARD LOOKING STATEMENTS

This Annual Report on Form 10-K, including any information incorporated by reference, contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, referred to as the “Securities Act”, and Section 21E of the Securities Exchange Act of 1934, as amended, referred to as the “Exchange Act”. All statements, other than statements of historical fact included in this Annual Report, regarding our strategy, future operations, financial position, estimated revenue and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Risk Factors.” These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about:

● our business strategy;

● our reserves;

● our financial strategy, liquidity and capital requirements;

● our realized or expected natural gas prices;

● our timing and amount of future production of natural gas;

● our future drilling plans and cost estimates;

● our competition and government regulations;

● our ability to make acquisitions;

● general economic conditions;

● our future operating results;

● our expectations regarding having our securities listed on NYSE American; and

● our future plans, objectives, expectations and intentions.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under “Risk Factors.”

Reserve engineering is a method of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of previous estimates. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report.

5

PART I

ITEM 1. BUSINESS

Overview

We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas properties on private, state and federal land in the United States, primarily within the Permian Basin region of West Texas and Southeast New Mexico which includes the Midland and Delaware Basins as well as the Central Basin Platform. We focus on acquiring producing assets at a discount to market, increasing production and cash-flow through recompletion and re-entries, secondary recovery and reducing risk through infill drilling and development. Overall, we own and operate 97 oil and gas wells across more than 11,700 net acres including 66 shut-in opportunities, 17 saltwater disposal wells and two water supply wells allowing for waterflood secondary recovery. Additionally, we hold royalty interests in 73 wells and five permitted wells across 3,800 acres within the Permian Basin.

Corporate History

We were incorporated on April 24, 2017 under the laws of British Columbia, Canada. At September 30, 2024, we had one wholly-owned subsidiary, Permex Petroleum US Corporation, a corporation incorporated under the laws of New Mexico. We own and operate oil and gas properties in Texas (Breedlove “B” Property, Pittcock North Property, Pittcock South Property, and Mary Bullard Property), and Permex Petroleum US Corporation owns and operates oil and gas properties in New Mexico (Henshaw Property and the Oxy Yates Property).

Oil and Gas Properties

We hired MKM Engineering, who prepared for us an Appraisal of Certain Oil and Gas Interests owned by Permex Petroleum Corporation located in New Mexico and Texas as of September 30, 2024 (the “2024 Appraisal Report”) as well as an Appraisal of Certain Oil and Gas Interests owned by Permex Petroleum Corporation located in New Mexico and Texas as of September 30, 2023 (the “2023 Appraisal Report” and together with the 2024 Appraisal Report the “Appraisal Reports”). MKM Engineering is independent with respect to Permex Petroleum Corporation as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. MKM Engineering’s estimates of the Company’s proved and probable reserves in each of the Appraisal Reports were prepared according to generally accepted petroleum engineering and evaluation principles, and each of the Appraisal Reports conform to SEC Pricing. The Appraisal Reports are each filed as an exhibit to this Annual Report.

The Appraisal Reports were each specifically prepared by Michele Mudrone, an employee of MKM Engineering, a registered Professional Engineer in the State of Texas, and a member of the Society of Petroleum Engineers. Ms. Mudrone graduated from the Colorado School of Mines with a Bachelor of Science degree in Petroleum Engineering in 1976 and has been employed in the petroleum industry and directly involved in reservoir engineering, petrophysical analysis, reservoir simulation and property evaluation since that time. Ms. Mudrone certified in each Appraisal Report that she did not receive, nor expects to receive, any direct or indirect interest in the holdings discussed in the report or in the securities of the Company. Because the Company’s current size, the Company does not have any technical person at the Company responsible for overseeing the preparation of the reserve estimates presented herein (or have any internal control policies pertaining to estimates of oil and gas reserves), and consequently, the Company relies exclusively on the Appraisal Reports in the preparation of the reserve estimates present in this Annual Report.

Since all of the Company’s reserves are from conventional reservoirs, MKM Engineering assumed for the purposes of its appraisal reports that the technology to be used to develop the Company’s reserves would include horizontally drilled wells, fracturing, and acidizing.

6

The following tables show a summary of our reserves as of September 30, 2024 and 2023 which have been derived from the Appraisal Reports and conform to SEC Pricing.

Composite Proved Reserve Estimates and Economic Forecasts for the year ended September 30, 2024

	Proved			Proved Developed Producing		Proved Non-Producing		Proved Undeveloped
Net Reserves
Oil/Condensate		MBbl	1,695.4		46.4		462.3		1,186.7
Gas		MMcf	1,138.2		54.4		225.2		858.6
Revenue
Oil/Condensate		M$	133,265.3		3,642.4		36,020.7		93,602.2
Gas		M$	815.7		81.4		132.0		602.3
Severance and Ad Valorem Taxes		M$	10,020.0		267.8		3,036.0		6,716.2
Operating Expenses		M$	21,731.8		1,753.9		9,977.4		10,000.5
Investments		M$	17,496.5		255.0		1,621.5		15,620.0
Operating Income (BFIT)		M$	84,832.5		1,447.0		21,517.7		61,867.8
Discounted @ 10%		M$	36,137.4		907.7		11,258.8		23,970.9

Composite Proved Reserve Estimates and Economic Forecasts for the year ended September 30, 2023

	Proved		Proved Developed Producing		Proved Non-Producing		Proved Undeveloped
Net Reserves
Oil/Condensate	MBbl	2,636.8		372.2		654.9		1,609.7
Natural Gas	MMcf	2,042.4		241.2		524.1		1,277.1
Revenue
Oil/Condensate	M$	207,269.9		29,035.8		51,407.8		126,826.3
Natural Gas	M$	4,558.1		585.1		1,138.5		2,834.5
Severance and Ad Valorem Taxes	M$	15,674.3		2,601.4		3,770.8		9,302.1
Operating Expenses	M$	24,386.7		9,882.4		5,313.9		9,190.4
Investments	M$	17,241.5		806.9		724.6		15,710.0
Operating Income (BFIT)	M$	154,525.5		16,330.2		42,736.9		95,458.4
Discounted @ 10%	M$	74,000.6		8,510.2		25,158.9		40,331.5

Composite Probable Reserve Estimates and Economic Forecasts for the year ended September 30, 2024

	Probable		Probable Developed Producing		Probable Non-Producing		Probable Undeveloped
Net Reserves
Oil/Condensate	MBbl	12,306.5		-		93.8		12,212.7
Gas	MMcf	15,437.0		-		9.8		15,427.2
Revenue
Oil/Condensate	M$	965,699.9		-		7,259.7		958,440.2
Gas	M$	21,957.0		-		21.5		21,935.5
Severance and Ad Valorem Taxes	M$	51,196.1		-		531.8		50,664.3
Operating Expenses	M$	74,958.9		-		1,137.3		73,821.6
Investments	M$	134,328.5		-		-		134.328.5
Operating Income (BFIT)	M$	727,173.4		-		5,612.1		721,561.3
Discounted @ 10%	M$	192,718.9		-		2,161.2		190,557.7

Composite Probable Reserve Estimates and Economic Forecasts for the year ended September 30, 2023

	Probable		Probable Developed Producing		Probable Non-Producing		Probable Undeveloped
Net Reserves
Oil/Condensate	MBbl	9,443.2		2.0		150.8		9,290.4
Gas	MMcf	10,892.4		3.4		6.2		10,882.8
Revenue
Oil/Condensate	M$	738,808.9		150.6		11,660.7		726,997.6
Gas	M$	33,254.8		11.7		21.4		33,221.7
Severance and Ad Valorem Taxes	M$	55,231.2		19.8		832.3		54,379.1
Operating Expenses	M$	55,531.2		55.0		1,172.2		54,304.0
Investments	M$	134,428.5		—		—		134,428.5
Operating Income (BFIT)	M$	526,872.9		87.6		9,677.6		517,107.7
Discounted @ 10%	M$	122,796.7		37.3		4,026.0		118,733.4

Probable reserves are unproven reserves that geologic and engineering analyses suggest are more likely than not to be recoverable. They are not comparable to proved reserves and estimates of oil, condensate, and gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Such reserve and revenue estimates are based on the information currently available, the interpretation of which is subject to uncertainties inherent in applying judgmental factors.

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Conversion of Undeveloped Acreage

The Company’s process for converting undeveloped acreage to developed acreage is tied to whether there is any drilling being conducted on the acreage in question. Management expects to restart its drilling and development program in the first quarter of 2025, subject to receipt of additional funding.

An aggregate of 1,186 MBO and 858 MMCF, of the Company’s proved undeveloped reserves as of September 30, 2024, are part of a development plan that has been adopted by management that calls for these undeveloped reserves to be drilled within the next five years, thus resulting in the conversion of such proved undeveloped reserves to developed status within five years of initial disclosure at September 30, 2024. Management currently anticipates spending approximately $6 million in capital expenditures towards developing the Company’s proved undeveloped reserves during the 2025 fiscal year, subject to the Company acquiring the necessary financing.

Proved Undeveloped Reserves Additions

From September 30, 2023 to September 30, 2024, the Company had no proved undeveloped reserve additions. The specific changes to the Company’s proved undeveloped reserves from September 30, 2023 to September 30, 2024 were as follows:

	Breedlove			Pittcock & Mary Bullard		Henshaw		Royalty Wells		Total
Beginning balance at September 30, 2023 (MBoe)(1)		1,822.54			-		-		-		1,822.54
Production (MBoe)(1)		-			-		-		-		-
Revisions or reclassifications of previous estimates (MBoe)(1)		(500.8	)		-		-		-		(500.8	)
Improved Recovery (MBoe)(1)		-			-		-		-		-
Extensions and Discoveries (MBoe)(1)		-			-		-		-		-
Acquisitions/Purchases (MBoe)(1)		-			-		-		-		-
Sales (MBoe)(1)		-			-		-		-		-
Price Change (MBoe)		8.06			-		-		-		8.06
Ending balance as of September 30, 2024 (MBoe)(1)		1,329.8			-		-		-		1,329.8

(1) Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended September 30, 2024, the average prices of WTI (Cushing) oil and NYMEX Henry Hub natural gas were $78.64 per Bbl and $2.206 per Mcf, respectively, resulting in an oil-to-gas ratio of just under 36 to 1.

Financing of Proved and Probable Undeveloped Reserves

The Company currently estimates that the total cost to develop the Company’s proved undeveloped reserves of 1,186.7 MBbl of oil and 858.6 MMcf of natural gas as of September 30, 2024 is $15,620,000. The Company expects to finance these capital costs through a combination of current cash on hand, debt financing through a line of credit or similar debt instrument, one or more offerings of debt or equity, and from cash generated from estimated revenues from sales of oil and natural gas produced at the Company’s wells.

The Company currently estimates that the total cost to develop the Company’s probable undeveloped reserves of 12,212.7 MBbl of oil and 15,427.2 MMcf of natural gas as of September 30, 2024 is $134,328,500. The Company expects to finance these capital costs through a combination of joint ventures, farm-in agreements, direct participation programs, one or more offerings of equity, a debt offering or entering into a line of credit, and from cash generated from estimated revenues from sales of oil and natural gas produced at the Company’s wells.

8

Drilling Activities

The Company drilled one well during the last three fiscal years. As at September 30, 2024, the Company had 78 gross wells and 5 net productive wells. The Company’s gross developed acreage totaled 5,177 and net developed acreage totaled 3,942 with the following property breakdown:

Property	Gross Developed Acreage		Net Developed Acreage		Gross Productive Wells		Net Productive Wells
Pittcock		818		664.63		0		0
Henshaw		1,880		1,353.60		0		0
Oxy Yates		680		489.60		0		0
Bullard		241		187.98		0		0
Breedlove		1,558		1,246.40		5		4.00
Royalty Interest Properties		-		-		73		0.01

The Company has 6,000 gross undeveloped acres and 4,800 net undeveloped acres. All of the Company’s undeveloped acreage is on the Company’s Breedlove property.

The Company’s leases are nearly entirely held by production in perpetuity. If a field/lease is undeveloped it typically has a 2, 3 or 5 year term of expiry. The Company has over 340 leases covering undeveloped acreage and less than 5% of these leases have an active expiry date that is less than two years from the date of this Annual Report.

Sales and Production

The average sales prices of the Company’s oil and gas products sold in the fiscal years ended September 30, 2024, 2023, and 2022 were $70.53/Boe, $71.45/Boe, and $89.14/Boe, respectively.

The Company’s net production quantities by final product sold in the fiscal years ended September 30, 2024, 2023, and 2022, were 1,963.82 Boe, 12,979.36 Boe, and 12,597.45 Boe, respectively.

The Company’s average production costs per unit for the fiscal years ended September 30, 2024, 2023, and 2022, were $100.02/Boe, $67.76/Boe, and $65.82/Boe, respectively.

The breakdown of production and prices between oil/condensate and natural gas was as follows:

Net Production Volumes	Fiscal Year Ended September 30, 2024		Fiscal Year Ended September 30, 2023		Fiscal Year Ended September 30, 2022
Oil/Condensate (Bbl)		1,964		11,729		10,670
Natural Gas (Mcf)		-		7,500		11,567

Average Sales Price	Fiscal Year Ended September 30, 2024		Fiscal Year Ended September 30, 2023		Fiscal Year Ended September 30, 2022
Oil/Condensate ($/Bbl)		70.53		76.17		96.18
Natural Gas ($/Mcf)		-		4.53		8.36

The breakdown of the Company’s production quantities by individual product type for each of the Company’s fields that contain 15% or more of the Company’s total proved reserves expressed on an oil-equivalent-barrels basis was as follows:

Breedlove

Net Production Volumes	Fiscal Year Ended September 30, 2024		Fiscal Year Ended September 30, 2023		Fiscal Year Ended September 30, 2022
Oil/Condensate (Bbl)		1,229		7,628		6,998
Natural Gas (Mcf)		-		6,362		11,567

Henshaw

Net Production Volumes	Fiscal Year Ended September 30, 2024		Fiscal Year Ended September 30, 2023		Fiscal Year Ended September 30, 2022
Oil/Condensate (Bbl)		735		3,098		2,189
Natural Gas (Mcf)		-		1,138		-

Pittcock & Mary Bullard

Net Production Volumes	Fiscal Year Ended September 30, 2024		Fiscal Year Ended September 30, 2023		Fiscal Year Ended September 30, 2022
Oil/Condensate (Bbl)		-		1,003		1,483
Natural Gas (Mcf)		-		-		-

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Texas Properties

Breedlove “B” Clearfork Leases

In September 2021, the Company, through its wholly-owned subsidiary, Permex Petroleum US Corporation, acquired a 100% Working Interest and an 81.75% Net Revenue Interest in the Breedlove “B” Clearfork leases located in Martin County, Texas. The Breedlove “B” Clearfork properties situated in Martin County, Texas are over 12 contiguous sections for a total of 7,870.23 gross and 7,741.67 net acres, of which 98% is held by production in the core of the Permian Basin. There is a total of 27 vertical wells of which 12 are producers, 4 are saltwater disposal wells and 11 that are shut-in opportunities. The Company is currently evaluating a number of re-entry opportunities across this asset including production optimization of the producing wells as well as the 11 currently shut-in wells. These assets were shut-in in April 2024 due to financial constraints. As of September 2024, the Company has resumed efforts to return these assets to production including limited recompletion activity based on available capital and full management technical review.

In addition to the significant recompletion and re-entry opportunities across the existing wellbores, the Breedlove property includes substantial undeveloped opportunities and is the focus of the Company’s proved undeveloped reserves development program, pending sufficient and successful capital raising efforts by the Company.

Pittcock Leases

The Pittcock Leases are situated in Stonewall County. Stonewall County is in Northwest Texas, in the central part of the North Central Plains and consists of the Pittcock North property, the Pittcock South property and the Windy Jones Property. It is bounded on the north by King County, on the east by Haskell County, on the south by Fisher and Jones Counties, and on the west by Kent County. The Pittcock North property covers 320 acres held by production. There is currently one producing well, ten shut-in wells, two saltwater disposal wells, and a water supply well. The Company holds a 100% working interest in the Pittcock North Property and an 81.25% net revenue interest. The Pittcock South property covers 498 acres in four tracts. There are currently 19 shut-in wells and two saltwater disposal wells. The Company holds a 100% working interest in the lease and a 71.90% net revenue interest. The Windy Jones Property consists of 40 acres and includes two injection wells and two suspended oil wells. The sole purpose of the Windy Jones property is to provide waterflood assistance to the offset wells being the Pittcock wells located east boundary of the Windy Jones Property. The Company holds a 100% working interest in the Windy Jones Property and a 78.9% net revenue interest. These assets became shut-in commencing in October 2023 due to the Company having insufficient funds to operate them and they are expected to remain shut-in until the Company is able to acquire sufficient funds to restart these assets.

Mary Bullard Property

The Company acquired the Mary Bullard Property in August 2017 for a cash consideration of approximately $50,000. The Mary Bullard Property is located in Stonewall County, about 5 ½ miles southwest of Aspermont, Texas. It is bounded on the north by King County, on the east by Haskell County, on the south by Fisher and Jones Counties, and on the west by Kent County. The asset is situated on the Eastern Shelf of the Midland Basin in the central part of the North Central Plains. The Mary Bullard Property covers 241 acres held by production and is productive in the Clearfork formation at a depth of approximately 3,200 feet. There is currently one producing well, four shut-in wells, and two water injection wells. The Company holds a 100% working interest in the Mary Bullard Property and a 78.625% net revenue interest. These assets were shut-in in December 2023 and remain shut in pending successful capital raising of the Company.

New Mexico Properties

West Henshaw Property - New Mexico

The West Henshaw Property is located in Eddy County, New Mexico, 12 miles northeast of Loco Hills in the Delaware Basin. Eddy County is in Southeast New Mexico. It is bounded by Chaves County to the north, Otero County to the east, Loving County, Texas to the south, and Lea County to the west. The West Henshaw Property covers 1,880 acres held by production. There are two producing wells, seven shut-in wells and four saltwater disposal wells. The Company holds a 100% working interest in the West Henshaw Property and a 72% net revenue interest. Throughout 2023, the Company completed a number of re-entry and basic workover efforts to try and establish more steady production from the West Henshaw assets. These assets were shut-in in March 2024 due to financial constraints and remain shut in pending successful capital raising of the Company.

Oxy Yates Property

The Oxy Yates Property is located in Eddy County, approximately eight miles north of Carlsbad, New Mexico in the Delaware Basin. It is bounded by Chaves County to the north, Otero County to the east, Loving County, Texas to the south, and Lea County to the west. The Oxy Yates Property covers 680 acres held by production. There is one producing well and nine shut-in wells. The Yates formation is located at an average depth of 1,200 feet and overlies the Seven River formation and underlies the Tansill formation. The Company holds a 100% working interest in the Oxy Yates Property and a 77% net revenue interest. These assets were shut-in in March 2024 due to financial constraints and remain shut in pending successful capital raising of the Company.

Royalty Interest Properties

The Company holds royalty interests in 73 producing oil and gas wells located in Texas and New Mexico.

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Business Strategy

The principal elements of our business strategy include the following:

● Grow production and reserves in a capital efficient manner using internally generated levered free cash flow. We intend to allocate capital in a disciplined manner to projects that we anticipate will produce predictable and attractive rates of return. We plan to direct capital to our oil-oriented and reduced-risk development opportunities while focusing on driving cost efficiencies across our asset base with the primary objective of internally funding our capital budget and growth plan. We may also use our capital flexibility to pursue value-enhancing, bolt-on acquisitions to opportunistically improve our positions in existing basins.

● Maximize ultimate hydrocarbon recovery from our assets by optimizing drilling, completion and production techniques and investigating deeper reservoirs and areas beyond our known productive areas. While we intend to utilize proven techniques and technologies, we will also continuously seek efficiencies in our drilling, completion and production techniques in order to optimize ultimate resource recoveries, rates of return and cash flows. We will explore innovative enhanced oil recovery (“EOR”) techniques to unlock additional value and have allocated capital towards next generation technologies. For example, we have already completed extensive waterflood EOR studies in Pittcock North and Pittcock South. Through these studies, we will seek to expand our development beyond our known productive areas in order to add probable and possible reserves to our inventory at attractive all-in costs as of the time of our studies.

● Pursue operational excellence with a sense of urgency. We plan to deliver low cost, consistent, timely and efficient execution of our drilling campaigns, work programs and operations. We intend to execute our operations in a safe and environmentally responsible manner, focus on reducing our emissions, apply advanced technologies, and continuously seek ways to reduce our operating cash costs on a per barrel basis.

● Pursue strategic acquisitions that maintain or reduce our break-even costs. We intend to actively pursue accretive acquisitions, mergers and dispositions that are intended to improve our margins, returns, and break-even costs of our investment portfolio. Financial strategies associated with these efforts will focus on delivering competitive adjusted per share returns.

Industry Operating Environment

The oil and natural gas industry is a global market impacted by many factors, such as government regulations, particularly in the areas of taxation, energy, climate change and the environment, political and social developments in the Middle East, demand in Asian and European markets, and the extent to which members of The Organization of Petroleum Exporting Countries and other oil exporting nations manage oil supply through export quotas. Natural gas prices are generally determined by North American supply and demand and are also affected by imports and exports of liquefied natural gas. Weather also has a significant impact on demand for natural gas since it is a primary heating source, and a major fuel for electric generation to power air conditioning.

Oil and natural gas prices have been, and we expect may continue to be, volatile. Lower oil and gas prices not only decrease our revenues, but an extended decline in oil or gas prices may affect planned capital expenditures and the oil and natural gas reserves that we can economically produce. While lower commodity prices may reduce our future net cash flow from operations, we expect to have sufficient liquidity to continue development of our oil and gas properties.

Development

We believe that there is significant value to be created by drilling the identified undeveloped opportunities on our properties in conjunction with the stimulation and rework of our shut-in wells. While our near-term plans are focused towards drilling wells on our existing acreage to develop the potential contained therein, our long-term plans also include continuing to evaluate acquisition and leasing opportunities that can earn attractive rates of return on capital employed.

Competition

The oil and natural gas industry is intensely competitive and we compete with numerous other oil and natural gas exploration and production companies, many of which have substantially larger technical teams and greater financial and operational resources than we do and may be able to pay more for exploratory prospects and productive oil and natural gas properties. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and gas reserves, but also have gathering, processing or refining operations, market refined products, provide, dispose of and transport fresh and produced water, own drilling rigs or production equipment, or generate electricity, all of which, individually or in the aggregate, could provide such companies with a competitive advantage. We also compete with other oil and gas companies in securing drilling rigs and other equipment and services necessary for the drilling, completion, and maintenance of wells, as well as for the gathering, transporting, and processing of oil, gas, natural gas liquids, and water. Consequently, we may face shortages, delays, or increased costs in securing these services from time to time. The oil and gas industry also faces competition from alternative fuel sources, including renewable energy sources such as solar and wind-generated energy, and other fossil fuels such as coal. Competitive conditions may also be affected by future energy, environmental, climate-related, financial, or other policies, legislation, and regulations. Our larger or integrated competitors may be better able to absorb the burden of existing, and any changes to federal, state, and local laws and regulations than we can, which would adversely affect our competitive position. Our ability to discover reserves and acquire additional properties in the future is dependent upon our ability and resources to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

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Marketing and Customers

The market for oil and natural gas that will be produced from our properties depends on many factors, including the extent of domestic production and imports of oil and natural gas, the proximity and availability of capacity and rates and terms of service of pipelines and other transportation and storage facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Our oil production is being sold to Dorado Transportation, LLC, Energy Transfer Partners and HollyFrontier at prices tied to West Texas Intermediate oil prices. Our natural gas production is being sold to DCP Operating Company LP under Henry Hub gas spot prices.

For the years ended September 30, 2024 and 2023, we had two significant purchasers that accounted for approximately 100% and 99%, respectively, of our total oil, and natural gas revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows.

Title to Properties

Our oil and natural gas properties are subject to customary royalty and other interests, liens under indebtedness, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with the use of our properties or the operation of our business. We believe that we have satisfactory title to or rights in our producing properties. As is customary in the oil and gas industry, minimal investigation of title is made at the time of acquisition of undeveloped properties. In most cases, we investigate title only when we acquire producing properties or before commencement of drilling operations.

Seasonality

Winter weather conditions and lease stipulations can limit or temporarily halt the drilling and producing activities of our operating partners and other oil and natural gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt the operations of our operating partners and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting well drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operating partners’ operations.

The demand and price for gas frequently increases during winter months and decreases during summer months. To lessen the impact of seasonal gas demand and price fluctuations, pipelines, utilities, local distribution companies, and industrial users regularly utilize gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can divert gas that is traditionally placed into storage which, in turn, may increase the typical winter seasonal price. Seasonal anomalies, such as mild winters, or other unexpected impacts, such as the COVID-19 pandemic, sometimes lessen or exacerbate these fluctuations.

Principal Agreements Affecting Our Ordinary Business

We generally do not own physical real estate, but, instead, our acreage is primarily comprised of leasehold interests subject to the terms and provisions of lease agreements that provide us the right to participate in drilling and maintenance of wells in specific geographic areas. Lease arrangements that comprise our acreage positions are generally established using industry-standard terms that have been established and used in the oil and natural gas industry for many years. Many of our leases are or were acquired from other parties that obtained the original leasehold interest prior to our acquisition of the leasehold interest.

In general, our lease agreements stipulate three-to-five year terms. Bonuses and royalty rates are negotiated on a case-by-case basis consistent with industry standard pricing. Once a well is drilled and production established, the leased acreage in the applicable spacing unit is considered developed acreage and is held by production. Other locations within the drilling unit created for a well may also be drilled at any time with no time limit as long as the lease is held by production. Given the current pace of drilling in the areas of our operations, we do not believe lease expiration issues will materially affect our acreage position.

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Governmental Regulation and Environmental Matters

Our operations are subject to various rules, regulations and limitations impacting the oil and natural gas exploration and production industry as whole.

Regulation of Oil and Natural Gas Production

Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, certain states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. Texas and New Mexico also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, and several states regulate the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the process of drilling, completion and abandonment, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. Moreover, the U.S. presidential administration transition may have an impact on our operations, including the possibility of additional federal regulations limiting access to and production from federal lands. The effect of these regulations could be to limit the amount of oil and natural gas that registrant can produce from wells and to limit the number of wells or the locations at which drilling can occur. Moreover, many states impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions, and the current federal Administration has proposed increasing royalties payable for production on Federal land. Failure to comply with any such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry may increase our cost of doing business and may affect our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”), Pipeline and Hazardous Materials Safety Administration (“PHMSA”), U.S. Department of the Interior and the courts. We cannot predict when or whether any such proposals may become effective.

Regulation of Transportation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil by common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Interstate oil pipeline rates may be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil pipelines that allows a pipeline to increase its rates annually up to a prescribed ceiling, without making a cost of service filing. Every five years, the FERC reviews the appropriateness of the index level in relation to changes in industry costs. On January 20, 2022, the FERC established a new price index for the five-year period which commenced on July 1, 2021. Oil pipelines may also seek market-based rates.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors in the same state who are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is generally governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

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Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future.

Onshore gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states. Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is done on a case-by-case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of state regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any state in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors in that state. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Environmental Matters

Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may:

● require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;

● limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and

● impose substantial liabilities for pollution resulting from operations.

The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are in compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry in general.

The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. Recent regulation and litigation that has been brought against others in the industry under RCRA concern liability for earthquakes that were allegedly caused by injection of oil field wastes.

The Endangered Species Act (“ESA”) seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. ESA provides for criminal penalties for willful violations of ESA. Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations are in compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject us (directly or indirectly through our operating partners) to significant expenses to modify our operations or could force discontinuation of certain operations altogether.

The Clean Air Act (“CAA”) controls air emissions from oil and natural gas production and natural gas processing operations, among other sources. CAA regulations include New Source Performance Standards (“NSPS”) for the oil and natural gas source category to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities.

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Effective May 7, 2024, the EPA adopted a Final Rule containing revisions and additions to the NSPS program rules (the “Final Methane Rule”). The Final Methane Rule could have a significant impact on the upstream and midstream oil and gas sectors. The Final Methane Rule formally reinstates emission limitations on methane, a greenhouse gas, for existing and modified facilities in the oil and gas sector. The Final Methane Rule regulates, for the first time under the NSPS program, existing oil and gas facilities. Specifically, the Final Methane Rule requires states to implement plans that meet or exceed federally established emission reduction guidelines for oil and natural gas facilities. The Final Methane Rule also requires, among other things, monitoring of small, high-polluting wells, tracking of “super-emitters”, inspection of abandoned wells until their closure, further reduction in flaring, and use of zero-emissions control equipment on hydrocarbon equipment. Several states and industry groups have filed suit before the D.C. Circuit challenging the EPA’s implementation of, and legal authority to issue, the Final Methane Rule. Texas et al. v. EPA et al., No. 24-1054 (D.C. Cir). On October 4, 2024, the U.S. Supreme Court denied applications for an immediate stay of the Final Methane Rule pending review by the D.C. Circuit Court of Appeals. Though the final outcome is uncertain, the rule, as written, establishes standards of performance for sources that commence construction, modification or reconstruction after March 8, 2024, and establishes emissions guidelines that will inform state plans to establish standards for existing sources.

On August 16, 2022, the IRA was signed into law. The IRA imposes an escalating charge on methane emissions from inter alia onshore petroleum and natural gas production, and natural gas processing, gathering, transmission, underground storage, and LNG storage/ import/export equipment. The charges apply only to facilities emitting 25,000 metric tons of CO2 annually The IRA also funds grants to facilities subject to the methane charge and “marginal conventional wells” to improve equipment and processes. The IRA also creates generous tax credits, benefitting even non-profit entities, that likely will create more supply and demand for alternative non-hydrocarbon energy which may diminish demand, or prices obtained, for natural gas and oil. These statutory provisions have been subject to legal challenge. The cumulative effect upon our business’ results of the IRA’s grants, charges, and incentives to non-hydrocarbon energy assets and fuels, is uncertain.

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there exists the United Nations-sponsored Paris Agreement, which is a non-binding agreement for nations to limit their greenhouse gas emissions through individually-determined reduction goals every five years after 2020. While the United States withdrew from the Paris Agreement effective November 4, 2020, President Biden recommitted the United States to the Paris Agreement on January 20, 2021.

These regulations and proposals and any other new regulations requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations and financial condition.

The Federal Water Pollution Control Act of 1972, or the Clean Water Act (the “CWA”), imposes restrictions and controls on the discharge of produced waters and other pollutants into waters of the United States (“WOTUS”). Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands.

The CWA and certain state regulations prohibit the discharge of produced water, sand, drilling fluids, drill cuttings, sediment and certain other substances related to the oil and gas industry into certain coastal and offshore waters without an individual or general National Pollutant Discharge Elimination System discharge permit. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. CWA jurisdiction depends on the definition of WOTUS. In August 2023, EPA and the Corps of Engineers issued a final rule to revise the definition of WOTUS, that expands CWA jurisdiction to include more features in areas where oil and gas operations are conducted and conforms the definition of WOTUS to recent U.S. Supreme Court precedent. The WOTUS rule is the subject of ongoing litigation. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Costs may be associated with the treatment of wastewater and/or developing and implementing storm water pollution prevention plans.

The CAA, CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants and impose liability on parties responsible for those discharges, for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.

New Mexico implemented in 2021 new standards mandating 98% of natural gas emissions be captured, and a prohibition on natural gas flaring to take effect in 2026. In addition, New Mexico in 2022 implemented restrictions, that are more stringent than federal rules, on emissions of volatile organic compounds and oxides of nitrogen, commonly occurring in connection with production of hydrocarbons. The State of New Mexico characterized the new rules as addressing outsized emissions from smaller, leak-prone wells.

The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Substantially all of the oil and natural gas production in which we have interest is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act to address hydraulic fracturing operations.

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Scrutiny of hydraulic fracturing activities continues in other ways. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts. Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities in other states have enacted bans on hydraulic fracturing. We cannot predict whether any other legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, it could lead to delays, increased operating costs and process prohibitions that would materially adversely affect our revenue and results of operations.

The National Environmental Policy Act (“NEPA”) establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA. In 2021, the Biden Administration proposed a rule to undue changes to NEPA enacted under the Trump Administration that had streamlined NEPA review. In April 2024, the White House Council on Environmental Quality (“CEQ”) finalized the revised NEPA rules. The changes emphasize the need to review federal actions for climate change and environmental justice impacts, among other factors. These changes, are likely to affect the assessment of projects ranging from oil and gas leasing to development on public and Indian lands.

Climate Change

Significant studies and research have been devoted to climate change, and climate change has developed into a major political issue in the United States and globally. Opponents of hydrocarbon production and consumption contend that greenhouse gas emissions contribute to climate change and pose a threat to the environment. Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production.

In the United States, no comprehensive federal climate change legislation has been implemented to date but the current administration has indicated willingness to pursue new climate change legislation, executive actions, rulemakings or other regulatory initiatives to limit GHG emissions. Interpretation/implementation of existing statutes and common law is evolving. These include rejoining the Paris Agreement treaty on climate change, several executive orders to address climate change, the U.S. Methane Emissions Reduction Action Plan, and a commitment to cut greenhouse gas emissions 50-52 percent of 2005 levels by 2030. Further, legislative and regulatory initiatives are underway to that purpose. The U.S. Congress has considered legislation that would control GHG emissions through a “cap and trade” program and several states have already implemented programs to reduce GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the CAA definition of an “air pollutant.” Recent litigation has held that if a source was subject to Prevention of Significant Deterioration or Title V based on emissions of conventional pollutants like sulfur dioxide, particulates, nitrogen dioxide, carbon monoxide, ozone or lead, then the EPA could also require the source to control GHG emissions and the source would have to install Best Available Control Technology to do so. As a result, a source may still have to control GHG emissions if it is an otherwise regulated source.

In March 2024, the SEC adopted final rules requiring disclosure of how climate-related risks are likely to materially impact publicly-traded enterprises’ finances, strategies and outlook and the impact of climate-related events upon a company’s consolidated financial statements’ line items. Companies must also identify “transition” strategies. Compliance with this rule is likely to increase our costs.

In 2014, Colorado was the first state in the nation to adopt rules to control methane emissions from oil and gas facilities. In 2016, the EPA revised and expanded NSPS to include final rules to curb emissions of methane, a greenhouse gas, from new, reconstructed and modified oil and gas sources. Previously, already existing NSPS regulated VOCs, and controlling VOCs also had the effect of controlling methane, because natural gas leaks emit both compounds. However, by explicitly regulating methane as a separate air pollutant, the 2016 regulations were a statutory predicate to propose regulating emissions from existing oil and gas facilities. In September 2020, EPA made technical and policy changes to the methane rules that limited the scope of the rules. In 2021, President Biden issued Executive Order 13990, Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis. In furtherance of this Executive Order, the EPA, on November 2, 2021, proposed rules to regulate methane emissions from the oil and natural gas industry, including, for the first time, reductions from certain upstream and midstream existing oil and gas sources. These regulations also expanded controls to reduce methane emissions, such as enhancement of leak detection and repair provisions. The PHMSA and the Department of Interior continue to focus on regulatory initiatives to control methane emissions from upstream and midstream equipment. To the extent that these regulations or initiatives remain in place and to the extent that our third-party operating partners are required to further control methane emissions, such controls could impact our business.

In addition, some of our third-party operating partners are required to report their GHG emissions under CAA rules. Because regulation of GHG emissions continues to evolve, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact us. Moreover, while the U.S. Supreme Court held in its 2011 decision American Electric Power Co. v. Connecticut that, with respect to claims concerning GHG emissions, the federal common law of nuisance was displaced by the CAA, the Court left open the question of whether tort claims against sources of GHG emissions alleging property damage may proceed under state common law. There thus remains litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us.

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The FERC has issued draft policy statements articulating how it will quantify natural GHG emissions, departing from past practices, but has not taken action to finalize such policy statements to date.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources, our products would become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

Depending on the outcome of future carbon emission rulemakings under the CAA targeting new and existing power plants, and demand for hydrocarbons may be reduced. In addition, we anticipate that such regulations will be challenged in federal court prior to their implementation. Depending on the outcome of such judicial review, the hydrocarbon production industry may face alternative efforts from private parties seeking to establish alternative GHG emission limitations from power plants. Alternative GHG emission limitations may arise from litigation under either federal or state common laws or citizen suit provisions of federal environmental statutes that attempt to force federal agency rulemaking or imposing emission limitations. Such lawsuits may also see damages from harm alleged to have resulted from GHG emissions.

Physical and Operational Risks. Weather extremes such as drought and high temperature variations are common occurrences in the southwest United States. Large increases in ambient temperatures could require evaluation of certain materials used within its system and may represent a greater challenge. As part of conducting our business, we recognize that the southwestern United States is particularly susceptible to the risks posed by climate change, which over time is projected to exacerbate high temperature extremes and prolong drought in the area. Texas has recently experienced extended droughts. Prolonged and extreme drought conditions can also affect our long-term ability to access water resources. Reductions in the availability of water for injections could negatively impact our financial condition, results of operations or cash flows.

Effects of Energy Conservation Measures and Distributed Energy Resources. Some state legislatures and agencies have established rules regarding energy efficiency that mandate energy savings requirements which in turn will impact the demand for electricity.

In addition to these rules and requirements, energy efficiency technologies and distributed energy resources continue to evolve, which may have similar impacts on demand for electricity. Reduced demand due to these energy efficiency requirements, distributed energy requirements and other emerging technologies, could have a material adverse impact on the financial condition results of operations and cash flow of our indirect customers.

Operational Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, well blow-outs, pipe failures, industrial accidents, and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil releases, chemical releases, natural gas leaks and the discharge of toxic gases. Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us, for example, as a result of damage to our property or equipment or injury to our personnel. These operational risks could also result in the spill or release of hazardous materials such as drilling fluids or other chemicals, which may result in pollution, natural resource damages, or other environmental damage and necessitate investigation and remediation costs. As a result, we could be subject to liability under environmental law or common law theories. In addition, these operational risks could result in the suspension or delay of our operations, which could have significant adverse consequences on our business.

In accordance with customary industry practices, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We cannot provide assurance that any insurance we obtain will be adequate to cover our losses or liabilities. Pollution and environmental risks generally are not fully insurable. Under certain circumstances, we may be liable for environmental damage caused by previous owners or operators of properties or repairs/decommissioning of assets that we own, lease or operate. As a result, we may incur substantial liabilities to third parties or governmental entities for environmental matters for which we do not have insurance coverage, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses.

The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

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Employees

As of January 14, 2025, we had one full time and one part time employee. We may hire additional personnel as appropriate. We also use the services of independent consultants and contractors to perform various professional services.

Facilities

Our executive offices are located at 1700 Post Oak Boulevard, 2 Blvd Place Suite 600, Houston Texas, 77056 and consists of one office leased space. We believe our current office space is sufficient to meet our needs and that additional office space can be obtained if necessary.

Additional Information

The Company files Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and proxy statements with the Securities and Exchange Commission (“SEC”). The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers, including the Company, that file electronically with the SEC at www.sec.gov. You may learn more about the Company by visiting the Company’s website at www.permexpetroleum.com. All of the reports we file with the SEC are available from this website. All websites referred to herein are inactive textual references only, meaning that the information contained in such websites is not incorporated by reference herein.

ITEM 1A. RISK FACTORS

The following disclosures should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report on Form 10-K. These disclosures are intended to discuss certain material risks of the Company’s business as they appear to Management at this time. However, this list is not exhaustive. Other risks may, and likely will, arise from time to time.

Summary of Risk Factors

Below is a summary of the principal factors that make an investment in our securities speculative or risky. This summary does not address all of the risks that we face. Additional discussion of the risks summarized in this risk factor summary, and other risks that we face, can be found below under the heading “Risk Factors” and should be carefully considered, together with other information in this Form 10-K and our other filings with the SEC, before making an investment decision regarding our securities.

● If we fail to obtain the capital necessary to fund our operations, we will be unable to continue our operations and you will likely lose your entire investment.

● Even if we can raise additional funding, we may be required to do so on terms that are dilutive to you.

● Our independent registered public accounting firm has expressed substantial doubt about our ability to continue as a going concern, which may hinder our ability to obtain future financing.

● Oil and gas prices are volatile, and declines in prices may adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

● The actual quantities and present value of our proved oil, gas, and NGL reserves may be less than we have estimated.

● Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations.

● Our future success depends on our ability to replace reserves.

● We conduct business in a highly competitive industry.

● Our operations are concentrated in the Permian and Delaware Basins, making us vulnerable to risks associated with operating in a limited geographic area.

● If we are unable to acquire adequate supplies of water for our future drilling and operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired.

● Our business is highly regulated and governmental authorities can delay or deny permits and approvals or change legal requirements governing our operations, including well stimulation, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and delay our implementation of, or cause us to change, our business strategy.

● Failure to comply with environmental laws and regulations could result in substantial penalties and adversely affect our business.

● Some of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions we or other operators may take when drilling, completing, or operating wells that we or they own.

● The market price of our securities is volatile and may not accurately reflect the long term value of our Company.

● There is currently a limited U.S. public market for our common shares, the stock price of our common shares may be volatile or may decline regardless of our operating performance and you may not be able to resell your common shares at or above the price you acquired such common shares.

● We have issued convertible debentures, options and warrants and may continue to issue additional securities in the future. The exercise or conversion of these securities and the sale of the common shares issuable thereunder may dilute your percentage ownership interest and may also result in downward pressure on the price of our common shares.

● Our principal shareholders and management own a significant percentage of our shares and may be able to exert significant control over matters subject to shareholder approval.

● We are a British Columbia company and it may be difficult for you to enforce judgments against us or certain of our directors or officers.

Risk Factors

Risks Related to Our Financial Position and Need for Capital

If we fail to obtain the capital necessary to fund our operations, we will be unable to continue our operations and you will likely lose your entire investment.

We are in the early stages of our operations and have not generated revenue in excess of our expenses. We will likely operate at a loss until our business becomes established, and we will require additional financing in order to fund future operations and expansion plans. Our ability to secure any required financing to sustain operations will depend in part upon prevailing capital market conditions and the success of our operations. There can be no assurance that we will be successful in our efforts to secure any additional financing or additional financing on terms satisfactory to us. If adequate funds are not available, or are not available on acceptable terms, we may be required to scale back our current business plan or cease operations.

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Even if we can raise additional funding, we may be required to do so on terms that are dilutive to you.

The capital markets have been unpredictable in the recent past. In addition, it is generally difficult for early stage companies to raise capital under current market conditions. The amount of capital that a company such as ours is able to raise often depends on variables that are beyond our control. As a result, we may not be able to secure financing on terms attractive to us, or at all. If we are able to consummate a financing arrangement, the amount raised may not be sufficient to meet our future needs and may be dilutive to our current shareholders. If adequate funds are not available on acceptable terms, or at all, our business, including our results of operations, financial condition and our continued viability will be materially adversely affected.

We have a limited operating history.

We have a limited operating history and our business is subject to all of the risks inherent in the establishment of a new business enterprise. Our likelihood of success must be considered in light of the problems, expenses, difficulties, complications and delays frequently encountered in connection with development and expansion of a new business enterprise. If we are unable to achieve profitability, we may be unable to continue our operations.

Our independent registered public accounting firm has expressed substantial doubt about our ability to continue as a going concern, which may hinder our ability to obtain future financing.

Our financial statements as of September 30, 2024 have been prepared under the assumption that we will continue as a going concern. Our independent registered public accounting firm included in its opinion for the year ended September 30, 2024 an explanatory paragraph referring to our significant losses from operations and working capital deficiency, and expressing substantial doubt in our ability to continue as a going concern for the next twelve months following the issuance of these financial statements. Our ability to continue as a going concern is dependent upon our ability to obtain additional equity or debt financing, reduce expenditures and to generate significant revenue. Our financial statements as of September 30, 2024 did not include any adjustments that might result from the outcome of this uncertainty. The reaction of investors to the inclusion of an explanatory paragraph regarding our ability to continue as a going concern for the twelve months following the issuance of our audited financial statements as of September 30, 2024 could materially adversely affect the price of our securities and our ability to raise new capital.

Risks Related to Our Business

Oil and gas prices are volatile, and declines in prices may adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

The prices we receive for our oil and natural gas production heavily influence our revenue, operating results, profitability, access to capital, future rate of growth and carrying value of our properties. Oil and natural gas are commodities, and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand, as well as costs and terms of transport to downstream markets.

Historically, the commodities markets had volatile prices, and these markets will likely continue to be volatile in the future. If the prices of oil and natural gas experience a substantial decline, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control and include the following:

● changes in global supply and demand for oil and natural gas;

● the actions of the Organization of Petroleum Exporting Countries;

● political conditions, including embargoes, in or affecting other oil-producing activity;

● the level of global oil and natural gas exploration and production activity;

● the level of global oil and natural gas inventories;

● weather conditions;

● technological advances affecting energy consumption; and

● the price and availability of alternative fuels.

Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.

Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for oil and, to a lesser extent, natural gas that we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In addition, we may need to record asset carrying value write-downs if prices fall. A significant decline in the prices of natural gas or oil could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

The actual quantities and present value of our proved oil, gas, and NGL reserves may be less than we have estimated.

There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their value. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Because of the high degree of judgment involved, the accuracy of any reserve estimate is inherently imprecise, and a function of the quality of available data and the engineering and geological interpretation. Our reserves estimates are based on 12-month average prices, except where contractual arrangements exist; therefore, reserves quantities will change when actual prices increase or decrease. In addition, results of drilling, testing, and production may substantially change the reserve estimates for a given reservoir over time. The estimates of our proved reserves and estimated future net revenues also depend on a number of factors and assumptions that may vary considerably from actual results, including:

● historical production from the area compared with production from other areas;

● the effects of regulations by governmental agencies, including changes to severance and excise taxes;

● future operating costs and capital expenditures; and

● workover and remediation costs.

For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of those reserves and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserves estimates may be subject to upward or downward adjustment, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates.

Additionally, because some of our reserves estimates are calculated using volumetric analysis, those estimates are less reliable than the estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure. In addition, realization or recognition of proved undeveloped reserves will depend on our development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.

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Our acquisition strategy may subject us to certain risks associated with the inherent uncertainty in evaluating properties.

Although we perform a review of properties that we acquire that we believe is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in-depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher-value properties and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us as a buyer to become sufficiently familiar with the properties to assess fully and accurately their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future production rates and costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates. In addition, there can be no assurance that acquisitions will not have an adverse effect upon our operating results, particularly during the periods in which the operations of acquired businesses are being integrated into our ongoing operations.

We may be unable to successfully integrate any assets we may acquire in the future into our business or achieve the anticipated benefits of such acquisitions.

Our ability to achieve the anticipated benefits of future acquisitions will depend in part on whether we can integrate the acquired assets into our existing business in an efficient and effective manner. We may not be able to accomplish this integration process successfully. The successful acquisition of producing properties requires an assessment of several factors, including:

● recoverable reserves;

● future oil and natural gas prices and their appropriate differentials;

● availability and cost of transportation of production to markets;

● availability and cost of drilling equipment and of skilled personnel;

● development and operating costs including access to water and potential environmental and other liabilities; and

● regulatory, permitting and similar matters.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we will perform reviews of the subject properties that we believe to be generally consistent with industry practices. These reviews will be based on our analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines without review by an independent petroleum engineering firm. Data used in such reviews will typically be furnished by the seller or obtained from publicly available sources. Our review may not reveal all existing or potential problems or permit us to fully assess the deficiencies and potential recoverable reserves for all acquired properties, and the reserves and production related to the acquired properties may differ materially after such data is reviewed by an independent petroleum engineering firm or further by us. Inspections will not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or a portion of the underlying deficiencies. The integration process may be subject to delays or changed circumstances, and we can give no assurance that our acquired assets will perform in accordance with our expectations or that our expectations with respect to integration or cost savings as a result of such acquisitions will materialize.

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Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations.

Our drilling activities are subject to many risks, including the risk that they will not discover commercially productive reservoirs. Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, drilling and producing operations on our acreage may be curtailed, delayed or canceled as a result of other factors, including:

● declines in oil or natural gas prices, as occurred in 2020 in connection with the COVID-19 pandemic;

● infrastructure limitations;

● the high cost, shortages or delays of equipment, materials and services;

● unexpected operational events, pipeline ruptures or spills, adverse weather conditions, facility malfunctions or title problems;

● compliance with environmental and other governmental requirements;

● regulations, restrictions, moratoria and bans on injection wells and water disposal;

● unusual or unexpected geological formations;

● environmental hazards, such as oil, natural gas or well fluids spills or releases, pipeline or tank ruptures and discharges of toxic gas;

● fires, blowouts, craterings and explosions and other physical accidents;

● uncontrollable flows of oil, natural gas or well fluids;

● changes in the cost of decommissioning or plugging wells;

● maintenance of quality, purity and thermal quality standards both for commodity sales and purposes of transportation;

● members of the public have engaged in physical confrontations or acts of sabotage to impede or prevent transportation of hydrocarbons; and

● pipeline capacity curtailments.

In addition to causing curtailments, delays and cancellations of drilling and producing operations, many of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

Our future success depends on our ability to replace reserves.

Because the rate of production from oil and natural gas properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional oil and natural gas reserves. Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as our reserves are produced. Future oil and natural gas production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot assure you that we will be able to find or acquire and develop additional reserves at an acceptable cost. We may acquire significant amounts of unproved property to further our development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We seek to acquire both proved and producing properties as well as undeveloped acreage that we believe will enhance growth potential and increase our earnings over time. However, we cannot assure you that all of these properties will contain economically viable reserves or that we will not abandon our initial investments. Additionally, we cannot assure you that unproved reserves or undeveloped acreage that we acquire will be profitably developed, that new wells drilled on our properties will be productive or that we will recover all or any portion of our investments in our properties and reserves.

Our business depends on third-party transportation and processing facilities and other assets that are owned by third parties.

The marketability of our oil and natural gas depends in part on the availability, proximity, capacity and cost of pipeline and gathering systems, processing facilities, oil trucking and barging fleets and rail transportation assets as well as storage facilities owned by third parties. The lack of available capacity on these systems and facilities, whether as a result of proration, growth in demand outpacing growth in capacity, physical damage, scheduled maintenance or other reasons could result in a substantial increase in costs, declines in realized commodity prices, the shut-in of producing wells or the delay or discontinuance of development plans for our properties. In addition, our wells may be drilled in locations that are serviced to a limited extent, if at all, by gathering and transportation pipelines, which may or may not have sufficient capacity to transport production from all of the wells in the area. As a result, we rely on third-party oil trucking to transport a significant portion of our production to third-party transportation pipelines, rail loading facilities and other market access points. In addition, concerns about the safety and security of oil and gas transportation by pipeline may result in public opposition to pipeline development or continued operation and increased regulation of pipelines by the Pipeline and Hazardous Materials Safety Administration, and therefore less capacity to transport our products by pipeline. Any significant curtailment in gathering system or pipeline capacity, or the unavailability of sufficient third-party trucking or rail capacity, could adversely affect our business, results of operations and financial condition. Our contracts for downstream transportation service include those that may be adjusted on a month-to-month basis, impacting underlying economics of our production. Our downstream contract transportation counterparties include entities that are far larger than we are and have greater market share in their markets than is the case for us in our markets.

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The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.

Approximately 70.5% of our estimated net proved reserves volumes were classified as proved undeveloped as of September 30, 2024. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

Weather conditions, which could become more frequent or severe due to climate change, could adversely affect our ability to conduct drilling, completion and production activities in the areas where we operate.

Our exploration and development activities and equipment can be adversely affected by severe weather such as well freeze-offs, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. Our planning for normal climatic variation, insurance programs, and emergency recovery plans may inadequately mitigate the effects of such weather conditions, and not all such effects can be predicted, eliminated, or insured against. In addition, demand for oil and gas are, to a degree, dependent on weather and climate, which impact the price we receive for the commodities we produce. These constraints could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

We may incur losses as a result of title defects in the properties in which we invest.

The existence of a material title deficiency can render a lease worthless. In the course of acquiring the rights to develop natural gas, we typically execute a lease agreement with payment to the lessor subject to title verification. In many cases, we incur the expense of retaining lawyers to verify the rightful owners of the gas interests prior to payment of such lease bonus to the lessor. There is no certainty, however, that a lessor has valid title to their lease’s gas interests. In those cases, such leases are generally voided and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. Prior to the drilling of a natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Accordingly, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss. Additionally, hydrocarbons or other fluids in one reservoir may migrate to another stratum or reservoir, resulting in disputes regarding ownership, the entitlement to produce, and responsibility for consequences of such migration of the fluids.

We conduct business in a highly competitive industry.

The oil and natural gas industry is highly competitive. The key areas in respect of which we face competition include: acquisition of assets offered for sale by other companies; access to capital (debt and equity) for financing and operational purposes; purchasing, leasing, hiring, chartering or other procuring of equipment and contractors that may be scarce; and employment of qualified and experienced skilled management and oil and natural gas professionals. Competition in our markets is intense and depends, among other things, on the number of competitors in the market, their financial resources, their degree of geological, geophysical, engineering and management expertise and capabilities, their pricing policies, their ability to develop properties on time and on budget, their ability to select, acquire and develop reserves and their ability to foster and maintain relationships with the relevant authorities. Our competitors also include those entities with greater technical, physical and financial resources. In some markets, our products compete with other sources of energy, or other fuels (e.g., hydroelectricity) that may from time to time become more abundant or experience decreased prices. Finally, companies and certain private equity firms not previously investing in oil and natural gas may choose to acquire reserves to establish a firm supply or simply as an investment. Any such companies will also increase market competition which may directly affect us. If we are unsuccessful in competing against other companies, our business, results of operations, financial condition or prospects could be materially adversely affected.

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Decommissioning costs are unknown and may be substantial. Unplanned costs could divert resources from other projects.

We may become responsible for costs associated with plugging, repairing, abandoning and reclaiming wells, pipelines and other facilities that we use for production of oil and natural gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We accrue a liability for decommissioning costs associated with our wells, but have not established any cash reserve account for these potential costs in respect of any of our properties. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business. Decommissioning costs’ predictability is challenging as more focus and demand is placed on decommissioning activities in the future than was previously the case, and because we do not have lengthy operating experience with our wells.

Fuel conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices, and the increased competitiveness of alternative energy sources could reduce demand for oil and natural gas. Additionally, the increased competitiveness of alternative energy sources (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells and biofuels) could reduce demand for oil and natural gas and, therefore, our revenues.

Additionally, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Furthermore, certain other stakeholders have pressured commercial and investment banks to stop funding oil and gas projects. With the continued volatility in oil and natural gas prices, and the possibility that interest rates will rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially shale producers. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results. Some states attorneys general have accused large legacy exploration and production companies of purposefully obscuring consequences of combusting hydrocarbons.

The impact of the changing demand for oil and natural gas services and products, together with a change in investor sentiment, may have a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, if we are unable to achieve the desired level of capital efficiency or free cash flow within the timeframe expected by the market, our share price may be adversely affected.

Major utilities, sometimes at the instigation of states or investors, have announced plans to radically reduce emissions, or goals to achieve “net-zero” carbon emissions by deadlines as early as 2035.

Diminution of available markets (for instance by bans on the consumption of natural gas as a fuel for power plants) or prohibitions on use of natural gas in new construction as early as 2027 also may affect our markets, profitability and cash flow.

Our operations are concentrated in the Permian and Delaware Basins, making us vulnerable to risks associated with operating in a limited geographic area.

All of our producing properties are geographically concentrated in the Permian and Delaware Basins. As a result, we may be disproportionately exposed to various factors, including, among others: (i) the impact of regional supply and demand factors, (ii) delays or interruptions of production from wells in such areas caused by governmental regulation, (iii) processing, gathering or transportation capacity constraints, (iv) market limitations, (v) availability of equipment and personnel, (vi) fluid shortages or other drought related conditions or (vii) interruption of the processing, gathering or transportation of natural gas. This concentration in a limited geographic area also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife and unexpected events that may occur in the regions such as natural disasters, seismic events, industrial accidents or labor difficulties. Any one of these factors has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expirations. Any of the risks described above could have a material adverse effect on our business, financial condition, results of operations and cash flow.

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Increasing scrutiny and changing expectations from investors, lenders and other market participants with respect to our Environmental, Social and Governance (“ESG”) policies may impose additional costs on us or expose us to additional risks.

Companies across all industries are facing increasing scrutiny relating to their ESG policies. Investor advocacy groups, certain institutional investors, investment funds, lenders and other market participants are increasingly focused on ESG practices and in recent years have placed increasing importance on the implications and social cost of their investments. The increased focus and activism related to ESG and similar matters may hinder access to capital, as investors and lenders may decide to reallocate capital or not to commit capital as a result of their assessment of a company’s ESG practices. Companies that do not adapt to or comply with investor, lender or other industry shareholder expectations and standards, which are evolving, or which are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and the business, financial condition or stock price of such a company could be materially and adversely affected.

We may face increasing pressures from investors, lenders and other market participants, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability. As a result, we may be required to implement more stringent ESG procedures or standards so that our existing and future investors and lenders remain invested in us and make further investments in us. If we do not meet these standards, our business or our ability to access capital could be harmed.

Additionally, certain investors and lenders have and may continue to exclude companies engaged in exploration and production activity, such as us, from their investing portfolios altogether due to ESG factors. These limitations in both the debt and equity capital markets may affect our ability to grow as our plans for growth may include accessing those markets. If those markets are unavailable, or if we are unable to access alternative means of financing on acceptable terms, or at all, we may be unable to implement our business strategy, which would have a material adverse effect on our financial condition and results of operations. At the same time, some stakeholders and regulators have increasingly expressed or pursued opposing views, legislation, and investment expectations with respect to ESG, including the enactment or proposal of “anti-ESG” legislation or policies.

Further, it is likely that we will incur additional costs and require additional resources to monitor, report and comply with wide ranging ESG requirements, including the SEC climate change disclosure rules. Similarly, these policies may negatively impact the ability of our customers to access debt and capital markets. The occurrence of any of the foregoing could have a material adverse effect on our business and financial condition.

Our business could be negatively affected by security threats, including cybersecurity threats and other disruptions.

As an oil and gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for operators related to developing and operating our properties.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly water and sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, our operators rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells. If our operators are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. Shortages of drilling rigs, equipment, raw materials, supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our operators’ exploration and development operations, which in turn could have a material adverse effect on our financial condition, results of operations and free cash flow.

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If we are unable to acquire adequate supplies of water for our future drilling and operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired.

We will be using a substantial amount of water in future drilling programs and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as (i) hydraulic fracturing, including, but not limited to, the use of fresh water in such operations, or (ii) disposal of waste, including, but not limited to, the disposal of produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas. Opponents of hydraulic fracturing contend that either the drilling process or the sub-surface injection of fluids, such as water and drilling fluids, as part of accessing hydrocarbons, or disposing of used injection fluids, creates or magnifies seismic disturbances, and should such contentions be given credence with regard to our Company, our operations could experience more regulation, higher costs or greater delays in accessing hydrocarbon resources, or claims of parties asserting damage arising from seismic activity. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, and all of which could have an adverse effect on our business, financial condition, results of operations and cash flows. While we intend to conduct our operations with the level of care necessary to avoid such claims, if the structural integrity of non-producing subsurface strata are impaired by hydraulic fracturing, we could face claims for damages (e.g., claims that we are producing from other geologic strata to which we do not have production rights).

Risks Related to Legal and Regulatory Matters

Our business is highly regulated and governmental authorities can delay or deny permits and approvals or change legal requirements governing our operations, including well stimulation, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and delay our implementation of, or cause us to change, our business strategy.

Our operations are subject to complex and stringent federal, state, local and other laws and regulations relating to environmental protection and the exploration and development of our properties, as well as the production, transportation, marketing and sale of our products. See “Business—Governmental Regulation and Environmental Matters” for a further discussion of the laws and regulations related to our operations. Federal, state and local agencies may assert overlapping authority to regulate in these areas. In addition, certain of these laws and regulations may apply retroactively and may impose strict or joint and several liability on us for events or conditions over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.

To operate in compliance with these laws and regulations, we must obtain and maintain permits, approvals and certificates from federal, state and local government authorities for a variety of activities including siting, drilling, completion, stimulation, operation, maintenance, transportation, marketing, site remediation, decommissioning, abandonment, fluid injection and disposal and water recycling and reuse. These permits are generally subject to protest, appeal or litigation, which could in certain cases delay or halt projects, production of wells and other operations. Additionally, failure to comply may result in the assessment of administrative, civil and criminal fines and penalties and liability for noncompliance, costs of corrective action, cleanup or restoration, compensation for personal injury, property damage or other losses, and the imposition of injunctive or declaratory relief restricting or limiting our operations. Under certain environmental laws and regulations, we could be subject to strict or joint and several liability for the removal or remediation of contamination, including on properties over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.

Our operations may also be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Such restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. Permanent restrictions imposed to protect threatened or endangered species or their habitat could prohibit drilling in certain areas or require the implementation of expensive mitigation measures.

Costs of compliance may increase, and operational delays or restrictions may occur as existing laws and regulations are revised or reinterpreted, or as new laws and regulations become applicable to our operations. Government authorities and other organizations continue to study health, safety and environmental aspects of oil and natural gas operations, including those related to air, soil and water quality, ground movement or seismicity and natural resources. Government authorities have also adopted or proposed new or more stringent requirements for permitting, well construction and public disclosure or environmental review of, or restrictions on, oil and natural gas operations. Such requirements or associated litigation could result in potentially significant added costs to comply, delay or curtail our exploration, development, fluid injection and disposal or production activities, and preclude us from drilling, completing or stimulating wells, or venting excess production of methane which could have an adverse effect on our expected production, other operations and financial condition.

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Failure to comply with environmental laws and regulations could result in substantial penalties and adversely affect our business.

As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, local, and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. See “Business—Governmental Regulation and Environmental Matters”. Changing law or regulations may impact market demand for our product. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up and other remediation activities resulting from operations, subject the lessee to liability for pollution and other damages, limit or constrain operations in affected areas, and require suspension or cessation of operations in affected areas. Our efforts to limit our exposure to such liability and cost may prove inadequate and result in significant adverse effects to our results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require us to make significant capital expenditures. Such capital expenditures could adversely impact our free cash flows and our financial condition.

Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.

From time to time, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for natural gas and oil properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although these provisions were largely unchanged in the most recent federal tax legislation, Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. Moreover, other more general features of any additional tax reform legislation, including changes to cost recovery rules, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted in future legislation and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

Our business involves the selling and shipping by rail of crude oil, which involves risks of derailment, accidents and liabilities associated with cleanup and damages, as well as potential regulatory changes that may adversely impact our business, financial condition or results of operations.

A portion of our crude oil production is transported to market centers by rail. Derailments in North America of trains transporting crude oil have caused various regulatory agencies and industry organizations, as well as federal, state and municipal governments, to focus attention on transportation by rail of flammable liquids. Any changes to existing laws and regulations, or promulgation of new laws and regulations, including any voluntary measures by the rail industry, that result in new requirements for the design, construction or operation of tank cars used to transport crude oil could increase our costs of doing business and limit our ability to transport and sell our crude oil at favorable prices at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, any derailment of crude oil involving crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities. Furthermore, some rail lines are not subject to material competitive pressure which would act as a brake on rates for rail transportation service.

Federal and state legislative and regulatory initiatives could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Any federal or state legislative or regulatory changes with respect to hydraulic fracturing could cause us to incur substantial compliance costs or result in operational delays, and the consequences of any failure to comply could have a material adverse effect on our financial condition and results of operations.

In addition, in response to concerns relating to recent seismic events near underground disposal wells used for the disposal by injection of flowback and produced water or certain other oilfield fluids resulting from oil and natural gas activities (so-called “induced seismicity”), regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. States may, from time to time, develop and implement plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. These developments could result in additional regulation and restrictions on the use of injection wells by our operators to dispose of flowback and produced water and certain other oilfield fluids. Increased regulation and attention given to induced seismicity also could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing injection wells for waste disposal. Until such pending or threatened legislation or regulations are finalized and implemented, it is not possible to estimate their impact on our business.

Any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.

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The adoption of climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas we produce.

Shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change and requiring agencies to review environmental actions taken by the Trump administration, as well as a memorandum to departments and agencies to refrain from proposing or issuing rules until a departmental or agency head appointed or designated by the Biden administration has reviewed and approved the rule. In November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-carbon dioxide greenhouse gas (“GHG”) emissions, such as methane and nitrous oxide. These executive orders and policy priorities may result in the development of additional regulations or changes to existing regulations, certain of which could negatively impact our financial position, results of operations and cash flows. In addition, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will take to achieve its GHG emissions targets. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. In 2022 and 2023, the 27th and 28th Conferences to the Parties on the UN Framework Convention on Climate Change were held where additional commitments were made by member nations with respect to climate action plans and the reduction of GHG emissions in support of Paris Agreement goals. In addition, several states and geographic regions in the United States have also adopted legislation and regulations regarding climate change-related matters, and additional legislation or regulation by these states and regions, U.S. federal agencies, including the Environmental Protection Agency (“EPA”), and/or international agreements to which the United States may become a party could result in increased compliance costs for us and our customers. Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, administrative, civil or criminal fines or penalties or injunctions limiting our operations in affected areas. Moreover, multiple environmental laws provide for citizen suits which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. We consider the responsibility and costs of environmental protection and safety and health compliance fundamental, manageable parts of our business. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.

Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure and/or well construction requirements on hydraulic fracturing operations. We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and potential bans. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.

Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and potentially reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. See “Business—Governmental Regulation and Environmental Matters” and “—Climate Change” for a further discussion of the laws and regulations related to GHGs and of climate change.

We may be involved in legal proceedings that could result in substantial liabilities.

Similar to many oil and natural gas companies, we may be involved in various legal and other proceedings from time to time, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have a material adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, resolution of one or more such proceedings could result in liability, loss of contractual or other rights, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

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Legislation or regulatory initiatives intended to address seismic activity could restrict our operators’ drilling and production activities, which could have a material adverse effect on our business.

State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. For example, in 2015, the United States Geological Study identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction.

In addition, a number of lawsuits have been filed alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, in October 2014, the Texas Railroad Commission published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Texas Railroad Commission has used this authority to deny permits for waste disposal wells. In some instances, regulators may also order that disposal wells be shut in.

The adoption and implementation of any new laws or regulations that restrict our operators’ ability to use hydraulic fracturing or dispose of produced water gathered from drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring them to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

Continuing political and social discussion of the issue of climate change has resulted in legislative, regulatory and other initiatives to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers at both the U.S. federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases through inventories, limitations and/or taxes on GHG emissions. The EPA has issued regulations for the control of methane emissions, which also include leak detection and repair requirements, for the oil and gas industry and are likely to create additional regulations regarding such matters. On November 15, 2021, the EPA proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound (“VOC”) emissions from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. Effective May 7, 2024, the EPA adopted the Final Methane Rule containing revisions and additions to the NSPS program rules. The Final Methane Rule formally reinstates methane emission limitations for existing and modified facilities in the oil and gas sector. The Final Methane Rule regulates, for the first time under the NSPS program, existing oil and gas facilities. Specifically, the Final Methane Rule requires states to implement plans that meet or exceed federally established emission reduction guidelines for oil and natural gas facilities. The Final Methane Rule also requires, among other things, monitoring of small, high-polluting wells, tracking of “super-emitters”, inspection of abandoned wells until their closure, further reduction in flaring, and use of zero-emissions control equipment on hydrocarbon equipment. Several states and industry groups have filed suit before the D.C. Circuit challenging the EPA’s implementation of, and legal authority to issue, the Final Methane Rule. Texas et al. v. EPA et al., No. 24-1054 (D.C. Cir). On October 4, 2024, the U.S. Supreme Court denied applications for an immediate stay of the Final Methane Rule pending review by the D.C. Circuit Court of Appeals. Though the final outcome is uncertain, the Final Methane Rule, as written, establishes standards of performance for sources that commence construction, modification or reconstruction after March 8, 2024, and establishes emissions guidelines that will inform state plans to establish standards for existing sources. If implemented as currently drafted, these increasingly stringent methane and VOC requirements on new facilities, or the application of new requirements to existing facilities, could result in additional restrictions on our operations and increase compliance costs, which could be significant.

The Inflation Reduction Act of 2022 (the “IRA”), which was signed into law in August 2022, imposes an escalating charge on methane emissions from inter alia onshore petroleum and natural gas production, and natural gas processing, gathering, transmission, underground storage, and LNG storage/ import/export equipment. The charges apply only to facilities emitting 25,000 metric tons of CO2 annually The IRA also funds grants to facilities subject to the methane charge and “marginal conventional wells” to improve equipment and processes. The IRA also creates generous tax credits, benefitting even non-profit entities, that likely will create more supply and demand for alternative non-hydrocarbon energy which may diminish demand, or prices obtained, for natural gas and oil. These statutory provisions will also be subject to legal challenge. The cumulative effect upon our business’ results of the IRA’s grants, charges, and incentives to non-hydrocarbon energy assets and fuels, is uncertain.

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Future additional federal GHG regulations of the oil and gas industry remain a significant possibility. Some states have imposed limitations designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state initiatives to date have generally focused on the development of renewable energy standards and/or cap-and-trade and/or carbon tax programs. Renewable energy standards (also referred to as renewable portfolio standards) require electric utilities to provide a specified minimum percentage of electricity from eligible renewable resources, with potential increases to the required percentage over time. The development of a federal renewable energy standard, or the development of additional or more stringent renewable energy standards at the state level, or continuing implementation of increasingly disadvantageous (from our industry’s perspective) renewable energy requirements embedded in existing legislation could reduce the demand for oil and gas, thereby adversely impacting our earnings, cash flows and financial position. A cap-and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. A federal cap and trade program or expanded use of cap and trade programs at the state level could impose direct costs on us through the purchase of allowances and could impose indirect costs by incentivizing consumers to shift away from fossil fuels. In addition, federal or state carbon taxes could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels.

In addition, opponents of fossil fuels claiming concern about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in an increasing number of financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this would make it more difficult and expensive to secure funding for exploration and production activities. Members of the investment community have also begun to screen companies such as ours for sustainability performance, including practices related to GHGs and climate change, before investing in our securities. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable in order to improve our sustainability performance and to meet the specific requirements to perform services for certain customers.

These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations, which could require us to incur costs to reduce emissions of GHGs associated with our operations. Limitations on GHG emissions could also adversely affect demand for oil and gas, which could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity.

Some of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions we or other operators may take when drilling, completing, or operating wells that we or they own.

Some of our properties are in reservoirs that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations by us or other operators could cause depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells by us or other operators could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.

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Risks Related to our Common Shares

The market price of our securities is volatile and may not accurately reflect the long term value of our Company.

Securities markets have a high level of price and volume volatility, and the market price of securities of many companies has experienced substantial volatility in the past. This volatility may affect the ability of holders of our securities to sell their securities at an advantageous price. Market price fluctuations in our securities may be due to our operating results, failing to meet expectations of securities analysts or investors in any period, downward revision in securities analysts’ estimates, adverse changes in general market conditions or economic trends, acquisitions, dispositions, or other material public announcements by us or our competitors, along with a variety of additional factors. These broad market fluctuations may adversely affect the market price of our securities.

In addition, financial markets have historically, at times, experienced significant price and volume fluctuations that have particularly affected the market prices of equity securities of companies and that have often been unrelated to the operating performance, underlying asset values, or prospects of such companies. If there is extreme market volatility and trading patterns in our securities, it may create several risks for investors, including the following:

● the market price of our securities may experience rapid and substantial increases or decreases unrelated to our actual or expected operating performance, financial condition or prospects, which may make it more difficult for prospective investors to assess the rapidly changing value of our securities;

● if our future market capitalization reflects trading dynamics unrelated to our actual or expected operating performance, financial performance or prospects, purchasers of our securities stock could incur substantial losses as prices decline once the level of market volatility has abated; and

● if the future market price of securities declines, investors may be unable to resell their securities at or above the price at which they acquired them. We cannot assure you that the market of our securities will not fluctuate or decline significantly in the future, in which case you could incur substantial losses.

Accordingly, the market price of our securities may decline even if our operating results, underlying asset values, or prospects have not changed. Additionally, these factors as well as other related factors may cause decreases in asset values that are deemed to be other than temporary, which may result in impairment losses. There can be no assurance that continuing fluctuations in the price and volume of our securities will not occur. If such increased levels of volatility and market turmoil continue, our operations could be adversely impacted and the trading price of our securities may be materially adversely affected. In addition, our securities may be more thinly traded than securities of larger, more established energy companies and, as a result of this lack of liquidity, sales of relatively small quantities of our securities by our shareholders may disproportionately influence the price of our securities. The market price of our securities may decline below the initial public offering price, and you may lose some or all of your investment.

There is currently a limited U.S. public market for our common shares, the stock price of our common shares may be volatile or may decline regardless of our operating performance and you may not be able to resell your common shares at or above the price you acquired such common shares.

Due to our prior delinquency in filing our periodic reports, the Form 211 originally filed with, and cleared by, the Financial Industry Regulatory Authority (“FINRA”) pursuant to Rule 15c2-11 of the Exchange Act covering our common shares was revoked by FINRA. Consequently, until a new Form 211 is filed with, and cleared by FINRA, our common shares will not be eligible for proprietary broker-dealer quotations on the OTC Pink Sheets and all quotes in our common shares on the OTC Pink Sheets will only reflect unsolicited customer orders. Unsolicited-Only stocks have a higher risk of wider spreads, increased volatility, and price dislocations. You may have difficulty selling your common shares in the United States and you may not be able to sell your common shares quickly or at the market price you feel our common shares are worth until a new Form 211 is filed with and cleared by FINRA under Rule 15c2-11 of the Exchange Act.

Further, having a limited trading market in the United States may also impair our ability to raise capital by selling our common shares and may impair our ability to enter into strategic collaborations or acquire companies or products by using our common shares as consideration.

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The price of our common shares may be volatile, and you could lose all or part of your investment.

The trading price of our common shares has historically been highly volatile and could continue to be subject to wide fluctuations in response to various factors, some of which are beyond our control, including limited trading volume. We cannot predict the prices at which our common shares will trade. The market price of our common shares following this offering will depend on a number of factors, including those described in this “Risk Factors” section, many of which are beyond our control and may not be related to our operating performance. In addition, the limited public float of our common shares may increase the volatility of the trading price of our common shares. In addition to the factors discussed in this “Risk Factors” section and elsewhere in this report, factors that could cause fluctuations in the market price of our common shares include.

● our ability to effectively manage our growth;

● actual or anticipated variations in quarterly operating results;

● our cash position;

● our failure to meet the estimates and projections of the investment community or that we may otherwise provide to the public;

● publication of research reports about us or our industry, or positive or negative recommendations or withdrawal of research coverage by securities analysts;

● changes in the market valuations of similar companies;

● overall performance of the equity markets;

● sales of our common shares by us or our stockholders in the future;

● trading volume of our common shares;

● changes in accounting practices;

● ineffectiveness of our internal controls;

● significant lawsuits, including intellectual property infringement or stockholder litigation;

● general political and economic conditions; and

● other events or factors, many of which are beyond our control.

In addition, the stock market in general, and the market for small oil and gas companies in particular, have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of these companies. Broad market and industry factors may negatively affect the market price of our common shares, regardless of our actual operating performance. In the past, securities class action litigation has often been instituted against companies following periods of volatility in the market price of a company’s securities. This type of litigation, if instituted, could result in substantial costs and a diversion of management’s attention and resources.

There is no assurance that an investment in our securities will earn any positive return.

There is no assurance that an investment in our securities will earn any positive return. An investment in our securities involves a high degree of risk and should be undertaken only by investors whose financial resources are sufficient to enable them to assume such risks and who have no need for immediate liquidity in their investment. An investment in our securities is appropriate only for investors who have the capacity to absorb a loss of some or all of their investment.

We have never paid cash dividends and have no plans to pay cash dividends in the future.

Holders of our common shares are entitled to receive such dividends as may be declared by our board of directors. To date, we have paid no cash dividends on our capital stock and we do not expect to pay cash dividends in the foreseeable future. We intend to retain future earnings, if any, to provide funds for operations of our business. Therefore, any return investors in our capital stock may have will be in the form of appreciation, if any, in the market value of their common shares.

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We may need to raise additional funds to support our business operations or to finance future acquisitions, including through the issuance of equity or debt securities, which could have a material adverse effect on our ability to grow our business, and may dilute your ownership in us.

If we do not generate sufficient cash from operations or do not otherwise have sufficient cash and cash equivalents to support our business operations or to finance future acquisitions, we may need raise addition capital through the issuance of debt or equity securities. We do not have any arrangements for any credit facility, or any other sources of capital. We may not be able to raise cash in future financing on terms acceptable to us, or at all.

Financings, if available, may be on terms that are dilutive to our shareholders, and the prices at which new investors would be willing to purchase our securities may be lower than the current price of our common shares. The holders of new securities may also receive rights, preferences or privileges that are senior to those of existing holders of our common shares. If new sources of financing are required but are insufficient or unavailable, we would be required to modify our plans to the extent of available funding, which could harm our ability to grow our business.

We have issued convertible debentures, options and warrants and may continue to issue additional securities in the future. The exercise or conversion of these securities and the sale of the common shares issuable thereunder may dilute your percentage ownership interest and may also result in downward pressure on the price of our common shares.

As of January 14, 2025, we have issued and outstanding options to purchase 69,167 common shares with a weighted average exercise price of $4.50 per share and warrants to purchase 2,511,904 common shares with a weighted average exercise price of $5.96 per share. In addition, we have 41,134 common shares available for future issuance under our Long-Term Incentive Plan. Because the market for our common shares may be thinly traded, the sales and/or the perception that those sales may occur, could adversely affect the market price of our common shares. Additionally, we have $4,276,389 in aggregate principal amount convertible into an aggregate of 2,238,947 common shares upon either the completion of an offering to investors for aggregate gross proceeds of at least $7.5 million or upon the election of the holders of the debentures. Furthermore, the mere existence of a significant number of common shares issuable upon exercise of our outstanding securities may be perceived by the market as having a potential dilutive effect, which could lead to a decrease in the price of our common shares.

Our principal shareholders and management own a significant percentage of our shares and may be able to exert significant control over matters subject to shareholder approval.

Our executive officers, directors and principal securityholders and their affiliates beneficially hold, in the aggregate, approximately 86% of our outstanding common shares on a partially diluted basis. These shareholders, acting together, would be able to significantly influence all matters requiring shareholder approval. For example, these shareholders would be able to significantly influence elections of directors, amendments of our organizational documents, or approval of any merger, sale of assets, or other major corporate transaction. This may prevent or discourage unsolicited acquisition proposals or offers for our common shares that you may feel are in your best interest as one of our shareholders.

We are a British Columbia company and it may be difficult for you to enforce judgments against us or certain of our directors or officers.

As a corporation organized under the provincial laws of British Columbia, Canada, it may be difficult to bring actions under U.S. federal securities law against us. Some of our directors and officers reside principally in Canada or outside of the United States. Because a portion of our assets and the assets of these persons are located outside of the United States, it may not be possible for investors to effect service of process within the United States upon us or those persons. Furthermore, it may not be possible for investors to enforce against us, or those persons not in the United States, judgments obtained in U.S. courts based upon the civil liability provisions of the U.S. federal securities laws or other laws of the United States. There is doubt as to the enforceability, in original actions in Canadian courts, of liabilities based upon U.S. federal securities laws and as to the enforceability in Canadian courts of judgments of U.S. courts obtained in actions based upon the civil liability provisions of the U.S. federal securities laws. Therefore, it may not be possible to enforce those actions against us or certain of our directors and officers.

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If securities or industry analysts do not publish research or publish inaccurate or unfavorable research about our business, our share price and trading volume could decline.

The trading market for our common shares will depend in part on the research and reports that securities or industry analysts publish about us or our business. Securities and industry analysts may never publish research on our Company. If no securities or industry analysts cover our Company, the trading price for our common shares and Warrants would likely be negatively impacted. In the event securities or industry analysts cover our Company, if one or more of the analysts who covers us downgrades our shares or publishes inaccurate or unfavorable research about our business, our share price may decline. If one or more of these analysts ceases coverage of our Company or fails to publish reports on us regularly, demand for our shares could decrease, which might cause our share price and trading volume to decline.

Unstable market and economic conditions and adverse developments with respect to financial institutions and associated liquidity risk may have serious adverse consequences on our business, financial condition and stock price.

The global credit and financial markets have recently experienced extreme volatility and disruptions, including severely diminished liquidity and credit availability, declines in consumer confidence, declines in economic growth, inflationary pressure and interest rate changes, increases in unemployment rates and uncertainty about economic stability. The financial markets and the global economy may also be adversely affected by the current or anticipated impact of military conflict, terrorism or other geopolitical events. Sanctions imposed by the United States and other countries in response to such conflicts may also adversely impact the financial markets and the global economy, and any economic countermeasures by the affected countries or others could exacerbate market and economic instability. More recently, the closures of Silicon Valley Bank and Signature Bank and their placement into receivership with the Federal Deposit Insurance Corporation (“FDIC”) created bank-specific and broader financial institution liquidity risk and concerns. Although the Department of the Treasury, the Federal Reserve, and the FDIC jointly confirmed that depositors at SVB and Signature Bank would continue to have access to their funds, even those in excess of the standard FDIC insurance limits, under a systemic risk exception, future adverse developments with respect to specific financial institutions or the broader financial services industry may lead to market-wide liquidity shortages, impair the ability of companies to access near-term working capital needs, and create additional market and economic uncertainty. There can be no assurance that future credit and financial market instability and a deterioration in confidence in economic conditions will not occur. Our general business strategy may be adversely affected by any such economic downturn, liquidity shortages, volatile business environment or continued unpredictable and unstable market conditions. If the equity and credit markets deteriorate, or if adverse developments are experienced by financial institutions, it may cause short-term liquidity risk and also make any necessary debt or equity financing more difficult, more costly and more dilutive. Failure to secure any necessary financing in a timely manner and on favorable terms could have a material adverse effect on our growth strategy, financial performance and stock price and could require us to delay or abandon our business plans.

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General Risk Factors

We are an “emerging growth company” and a “smaller reporting company” and will be able to avail ourselves of reduced disclosure requirements applicable to emerging growth companies and/or smaller reporting companies, which could make our securities less attractive to investors.

We are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act (the “JOBS Act”) and we intend to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “emerging growth companies” including not being required to comply with the auditor attestation requirements of Section 404(b) of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. In addition, Section 107 of the JOBS Act also provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act, for complying with new or revised accounting standards. In other words, an “emerging growth company” can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We may take advantage of these reporting exemptions until we are no longer an “emerging growth company.” We will remain an “emerging growth company” until the earliest of (i) the last day of the fiscal year in which we have total annual gross revenues of $1.07 billion or more; (ii) the last day of our fiscal year following the fifth anniversary of the date of the completion of our initial public offering; (iii) the date on which we have issued more than $1 billion in nonconvertible debt during the previous three years; or (iv) the date on which we are deemed to be a large accelerated filer under the rules of the SEC.

In addition, even if we no longer qualify as an “emerging growth company,” we may still take advantage of certain reduced reporting requirements as a “smaller reporting company.” If we are a smaller reporting company at the time we cease to be an emerging growth company, we may continue to rely on exemptions from certain disclosure requirements that are available to smaller reporting companies. Specifically, as a smaller reporting company, we may choose to present only the two most recent fiscal years of audited financial statements in our Annual Report on Form 10-K and have reduced disclosure obligations regarding executive compensation, and, similar to emerging growth companies, if we are a smaller reporting company, we may not be required to obtain an attestation report on internal control over financial reporting issued by our independent registered public accounting firm.

We cannot predict if investors will find our securities attractive because we may rely on these exemptions. If some investors find our securities less attractive as a result, there may be a less active trading market for our securities and our share price may be more volatile.

Failure to maintain effective internal control over our financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act could cause our financial reports to be inaccurate.

We are required pursuant to Section 404 of the Sarbanes-Oxley Act to maintain internal control over financial reporting and to assess and report on the effectiveness of those controls. This assessment includes disclosure of any material weaknesses identified by our management in our internal control over financial reporting. Although we prepare our financial statements in accordance with accounting principles generally accepted in the United States (“US GAAP”), our internal accounting controls may not meet all standards applicable to companies with publicly traded securities. If we fail to implement any required improvements to our disclosure controls and procedures, we may be obligated to report control deficiencies in which case, we could become subject to regulatory sanction or investigation. Further, these outcomes could damage investor confidence in the accuracy and reliability of our financial statements.

As of September 30, 2024, management assessed the effectiveness of our internal control over financial reporting and concluded that such internal controls and procedures were not effective. Management determined that this was due to the following deficiencies:

● insufficient resources resulting in inadequate segregation of duties in certain accounting functions, the processing and approval of transactions, due to the size of the accounting department;

● ineffective controls over inputs used in the valuation of the asset retirement obligation;

● Ineffective controls over the depletion calculation and the preparation of the oil and gas reserve report;

● ineffective controls on the accounting and the valuation of complex financial instruments;

● ineffective review of the financial statements due to the limited financial and reporting resources; and

● ineffective information technology general controls in the areas of user access and program change-management over certain information technology systems that support our financial reporting processes.

Although management has taken steps to address the deficiencies in our internal controls, we currently do not have sufficient internal controls over financial reporting which could limit investment in our securities and expose the us to SEC fines or administrative sanctions. Additionally, if we fail to implement required improvements to our disclosure controls and procedures, we may be obligated to continue to report control deficiencies in which case, we could become subject to regulatory sanction or investigation. Further, these outcomes could damage investor confidence in the accuracy and reliability of our financial statements.

Additionally, we failed to timely file with the SEC and the applicable Canadian regulatory authorities each of our Annual Report on Form 10- K for the year ended September 30, 2023, as well as our Quarterly Reports on Form 10-Q for the quarterly periods ended December 31, 2023, March 31, 2024 and June 30, 2024. Due to these late filings, on April 16, 2024, we received a failure to file cease trade order (the “FFCTO”) issued by the British Columbia Securities Commission (the “BCSC”) due to our failure to file our annual financial statements with the BCSC. The trading of our common shares was halted on the Canadian Securities Exchange (“CSE”) effective April 17, 2024. Subsequently, we brought all filings required by the BCSC up to date and on September 6, 2024, the FFCTO was revoked by the BCSC, and our common shares were reinstated for trading on the CSE effective September 9, 2024. Although our late periodic filings did not material impact the effectiveness of our internal controls over financial reporting, failure to timely file our future periodic reports could result in a future FFCTO from the BCSC on the CSE, which could have a material impact on the effectiveness of our internal controls.

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Financial reporting obligations of being a public company in the U.S. are expensive and time-consuming, and our management will be required to devote substantial time to compliance matters.

As a publicly traded company we incur significant legal, accounting and other expenses. The obligations of being a public company in the U.S. requires significant expenditures and may place significant demands on our management and other personnel, including costs resulting from public company reporting obligations under the Exchange Act and the rules and regulations regarding corporate governance practices, including those under the Sarbanes-Oxley Act, the Dodd-Frank Wall Street Reform and Consumer Protection Act, and the listing requirements of the stock exchange on which our securities are listed. These rules require the establishment and maintenance of effective disclosure and financial controls and procedures, internal control over financial reporting and changes in corporate governance practices, among many other complex rules that are often difficult to implement, monitor and maintain compliance with. Moreover, despite recent reforms made possible by the JOBS Act, the reporting requirements, rules, and regulations will make some activities more time-consuming and costly, particularly after we are no longer an “emerging growth company” or a “smaller reporting company.” In addition, these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance. Our management and other personnel will need to devote a substantial amount of time to ensure that we comply with all of these requirements and to keep pace with new regulations, otherwise we may fall out of compliance and risk becoming subject to litigation or being delisted, among other potential problems.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

The Company has not adopted any formal cybersecurity risk management program or formal processes for assessing, identifying, and managing material risks from cybersecurity threats. At the management level, our Chief Executive Officer and Chief Financial Officer are responsible for addressing cybersecurity incidents, while our full board of directors (the “Board of Directors” or “Board”) has oversight responsibility for the Company’s overall risk management, including cybersecurity risk, and has not delegated oversight authority for cybersecurity risks to any committee. In the event a cybersecurity incident occurs, the Company’s Chief Executive Officer and the Chief Financial Officer are expected to inform our Board of Directors of the details of such incident as well as the measures taken in response to such incident. In fiscal year 2024, we did not identify any cybersecurity threats that have materially affected or are reasonably likely to materially affect our business strategy, results of operations, or financial condition.

ITEM 2. PROPERTIES

Executive Office

Our executive office is located at 1700 Post Oak Boulevard, 2 Blvd Place Suite 600, Houston Texas, 77056 and consists of one office leased space. We believe our current office space is sufficient to meet our needs and that additional office space can be obtained if necessary.

Oil and Gas Properties

Information concerning proved and probable reserves, production, wells, acreage and related matters are contained in Item 1. “Business.”

ITEM 3. LEGAL PROCEEDINGS

The Company from time to time may be involved with disputes, claims and litigation related to the conduct of its business. The following are the material legal proceedings pending to which the Company is a party or to which any of its property is subject.

1. Atlas Tubular, LLC filed a suit against the Company on October 10, 2023 in the 14th Judicial District Court of Dallas, County, Texas, seeking damages of at least $172,981 for unpaid invoices. This amount is included in the Company’s trade payables as at September 30, 2024. The Company made a payment of $100,000 to Atlas Tubular in June 2024 towards this alleged debt.

2. Foundation Energy Services, LLC filed a suit against the Company on September 7, 2023 in the 160th Judicial District Court, Dallas County, Texas, seeking damages of at least $66,074 for unpaid invoices. This amount is included in the Company’s trade payables as at September 30, 2024. Foundation Energy Services, LLC was awarded a judgment for the amount owed, plus attorney’s fees of $11,055, court costs of $485, 5% interest, and $10,000 in post judgment attorney’s fees for collection efforts.

3. Premier Energy Services, LLC filed a suit against the Company on August 7, 2023 in the 118th Judicial District Court of Martin County, Texas, seeking damages of at least $104,205 for unpaid invoices. Of this amount, $95,541 is included in the Company’s trade payables as at September 30, 2024. The Company disputes the remaining $8,664 of the claimed damages.

4. BJ Pipe & Supply LLC filed a suit against the Company on September 11, 2024 in the 5^th Judicial District, Eddy County New Mexico seeking damages of at least $75,951 for unpaid invoices. Of this amount, $52,520.65 is included in the Company’s trade payable as of September 30, 2024. The Company and BJ Pipe & Supply LLC have reached an agreement to settle the lawsuit.

5. Hudson Pumping Inc. filed a suit against the Company on December 2, 2024 in the 118th Judicial District Court of Martin County, Texas, seeking damages of at least $60,050 for unpaid invoices. This amount is included in the Company’s trade payables as at September 30, 2024.

6. Cudd Energy Services, Inc. filed a suit against the Company and Mehran Ehsan on July 17, 2024, in the 118th Judicial District Court of Martin County, Texas, seeking damages of at least $130,224 for unpaid invoices. Of this amount, $115,936 is included in the Company’s loan payable as at September 30, 2024.

7. R&B Oilfield Services, LLC. filed a suit against the Company on November 6, 2024, in the Judicial District Court of Midland County, Texas, seeking damages of at least $36,020 for unpaid invoices. This amount is included in the Company’s trade payables as at September 30, 2024.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our common shares currently trade on the CSE in Canada under the symbol “OIL” and under the Frankfurt Stock Exchange under the symbol “75P”.

In addition, our common shares currently trade on the OTC Pink Sheets in the United States under the symbol “OILCF”. However, due to prior failure to timely file our Annual Report on Form 10-K for the year ended September 30, 2023, the Form 211 filed with FINRA pursuant to Rule 15c2-11 of the Exchange Act relating to our common shares was revoked by FINRA. Accordingly, our common shares are not eligible for proprietary broker-dealer quotations on the OTC Pink Sheets. All quotes in our common shares on the OTC Pink Sheets currently reflect unsolicited customer orders only.

Shareholders

As of January 14, 2025, there were 551,503 common shares issued and outstanding, held by approximately 49 holders of record, although there are a much larger number of beneficial owners.

Dividend Policy

Our Board of Directors has discretion as to whether we will pay dividends in the future, subject to restrictions under the Business Corporations Act (British Columbia) (the “BCBCA”) and our charter documents. Under the BCBCA, we may not declare or pay dividends if our Company is insolvent or where the payment of the dividend would render our Company insolvent. See “Description of Share Capital.”

We have never paid or declared any cash dividends on our common shares, and we do not anticipate paying any cash dividends on our common shares in the foreseeable future. We intend to retain all available funds and any future earnings to fund the development and expansion of our business. Any future determination to pay dividends will be at the discretion of our Board of Directors and will depend upon a number of factors, including our results of operations, financial condition, future prospects, contractual restrictions, restrictions imposed by applicable law and other factors our Board of Directors deems relevant.

Recent Sales of Unregistered Securities

Information concerning recent sales of unregistered securities can be found under Items 1.01 and 3.02 of our Form 8-K filed with the SEC on November 7, 2024.

Equity Compensation Plans

Information required with respect to Equity Compensation Plans in this Item 5 is included in Item 12 on page 53 of this Annual Report on Form 10-K.

Issuer Purchases of Equity Securities

None.

ITEM 6. [Reserved]

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis of our financial condition and results of operations together with the Company’s consolidated financial statements and the related notes thereto and other financial information included elsewhere in this Annual Report. Some of the information contained in this discussion and analysis or set forth elsewhere in this Annual Report, including information with respect to our plans and strategy for our business, includes forward-looking statements that involve risks and uncertainties. You should review the “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” sections of this Annual Report for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis. All amounts in this discussion and analysis of our financial condition and results of operations are in U.S. dollars, unless otherwise noted.

Reserve engineering is a method of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of previous estimates. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas and oil that are ultimately recovered.

Company Overview

The Company was incorporated on April 24, 2017 under the laws of British Columbia, Canada. The Company is an independent energy company engaged in the acquisition, exploration, development and production of oil and gas properties on private, state and federal land in the United States, primarily in the Permian Basin which includes the Midland Basin and Delaware Basin. The Company focuses on acquiring producing assets at a discount to market, increasing production and cash-flow through recompletion and re-entries, secondary recovery and lower risk infill drilling and development. Currently, the Company owns and operates 97 oil and gas wells across more than 11,700 net acres including 66 shut-in opportunities, 17 saltwater disposal wells and two water supply wells allowing for waterflood secondary recovery. Additionally, the Company holds royalty interests in 73 wells and five permitted wells across 3,800 acres within the Permian Basin.

The Company’s common shares are listed on the Canadian Securities Exchange (“CSE”) under the symbol “OIL” and on the Frankfurt Stock Exchange under the symbol “75P”.

Key Activities:

● On October 23, 2023, the Company effected a 1-for-4 reverse split of the Company’s outstanding common shares.

● On February 28, 2024, the Company announced the commencement of a private placement of convertible debenture units (the “Initial Units”) of the Company for gross proceeds of up to $20,000,000 (the “Original Private Placement”). Under the terms of the Original Private Placement, each Initial Unit consisted of one convertible debenture (an “Initial Unit Debenture”) in the principal amount of $1,000 and one common share purchase warrant, that was to be exercisable for a period of five years from the date of issuance for one common share at an exercise price of $4.08 (the “Initial Unit Warrants”). The maturity date for the Initial Unit Debentures (the “Initial Unit Debenture Maturity Date”) was the earlier of: (i) one-year from the date of issuance or (ii) three-months from the date of issuance if the Company does not enter into a securities exchange, unit purchase or merger agreement with a third party to the reasonable satisfaction of a majority of the holders of Initial Unit Debentures. The Initial Unit Debentures bore simple interest at a rate of 10% per annum, payable on the Maturity Date or the date on which all or any portion of the Initial Unit Debenture is repaid, and had a conversion price of $3.40 per common share. Interest will be paid on the Initial Unit Debenture in cash or common shares at the holder’s option based on a conversion price of $3.40. The Initial Unit Debentures will rank senior to all other existing and future indebtedness of the Company and are secured by a general security agreement over certain assets of the Company.

● On April 16, 2024, the Company announced the closing of the first tranche of the Original Private Placement, consisting of 500 Units for gross proceeds of $500,000.

● On May 1, 2024, the Company announced the appointment of Bradley Taillon as the President and Chief Executive Officer of the Company, replacing. Mehran Ehsan, the former President and Chief Executive Officer of the Company, who continued to work with the Company as the Company’s Vice President of Business Development until August 30, 2024.

● On May 29, 2024, the Company announced that it had applied to the BCSC for a partial revocation of the FFCTO. The Company also announced that all Initial Units previously issued and to be issued in future tranches under the Original Private Placement would consist of one Initial Unit Debenture and 294 Initial Unit Warrants. Pursuant to this amendment, the number of outstanding Initial Unit Warrants issued with the first tranche was increased from 500 to 147,000.

● On June 18, 2024, the Company announced the closing of the second tranche of the Original Private Placement, consisting of 865 Initial Units for gross proceeds of $865,000. As a result, the Company issued an Initial Unit Debenture with a principal amount of $865,000 and 254,310 Initial Unit Warrants, exercisable for a period of five years at an exercise price of $4.08 per share. The second tranche was conducted pursuant to a partial revocation of the FFCTO which was issued by the BCSC on June 5, 2024. The Company used the proceeds of the second tranche to prepare and file all outstanding financial statements and continuous disclosure records, pay all outstanding related fees and penalties, pay certain outstanding amounts owing pursuant to summary judgments and to continue operations until it could apply for and receive a full revocation of the FFCTO.

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● On June 18, 2024, the Company announced the appointment of Brad Taillon, the Company’s President and Chief Executive Officer, as a director, and that each of Melissa Folz, Barry Whelan, James Perry Bryan and Mehran Ehsan had resigned from the Company’s Board of Directors for personal reasons. Subsequently, on June 26, 2024, the Company announced that each of John Lendrum, and Douglas Urch resigned from the Company’s Board of Directors for personal reasons and on August 27, 2024, the Company announced that Richard Little and Kevin Nanke had been appointed to serve as directors on the Company’s Board of Directors. These changes to the Company’s Board of Directors were a result of resignations by the then current directors for personal reasons, including the time commitment associated with serving as a director on the Company’s Board of Directors, and were not part of any strategic reconstitution and expansion initiative.

● On August 29, 2024, the Company filed all required outstanding financial statements and continuous disclosure with the CSE.

● On September 9, 2024, the Company announced the revocation of the FFCTO issued by the BCSC and the reinstatement of trading of its common shares on the CSE effective September 9, 2024. The Company also announced the termination of the Original Private Placement and the commencement of a new non-brokered private placement of units (the “Subsequent Units”) of the Company for gross proceeds of up to $18,635,000 (the “Subsequent Private Placement”) and on September 18, 2024, the Company announced a repricing of the Subsequent Private Placement. Under the terms of the Subsequent Private Placement, each Subsequent Unit consists of one convertible debenture (a “Subsequent Unit Debenture”) in the principal amount of $1,000 and originally included 245 common share purchase warrants but were subsequently repriced to include 523 common share purchase warrants (each, a “Subsequent Unit Warrant”). Each Subsequent Unit Warrant is exercisable for a period of five years from the date of issuance for one Common Share and originally had an exercise price of $4.90 per share, but was subsequently repriced so that the Subsequent Unit Warrants now have an exercise price of $1.91 per share. The Subsequent Debentures will mature one-year from the date of issuance. Upon issuance, the Subsequent Unit Debentures are expected to rank pari passu with the Initial Unit Debentures and rank senior to all other existing and future indebtedness of the Company and will be secured by a general security agreement over certain assets of the Company. The Subsequent Debentures originally bore simple interest at a rate of 15% per annum, but such interest rate was subsequently reduced to 10% per annum, payable on the maturity date or the date on which all or any portion of the Subsequent Debenture is repaid. Interest will be paid in cash or common shares at the holder’s option based on a conversion price of $1.91 per share (the conversion price was originally $4.08, but was subsequently reduced). As of the date of this quarterly report, the Company has received subscription proceeds totaling $2,400,000.

● On November 1, 2024, the Company closed the first tranche of the Subsequent Private Placement for gross proceeds of $4,276,389. As a result, the Company issued Subsequent Unit Debentures with an aggregate principal amount of $4,276,389 and 2,236,551 Subsequent Unit Warrants. Concurrently with the completion of the first tranche of the Subsequent Private Placement, the Company retired the outstanding Initial Unit Debentures, consisting of $1,365,000 in aggregate principal amount and $59,788 in accrued interest in exchange for the Subsequent Unit Debentures. The holders of the Original Unit Debentures also agreed to cancel a total of 401,310 Initial Unit Warrants.

● On January 13, 2025, the Company announced an agreement with a private oil and gas operator concerning assets owned by such operator in the Permian Basin. This arrangement grants Permex operating rights over 19 wells in the Permian Basin in exchange for a monthly operating fee of up to $75,000 per month based on production volumes and commodity prices.

Selected Annual Information

The following table sets out selected financial information for the Company which has been derived from the Company’s audited financial statements for the fiscal years ended September 30, 2024, 2023 and 2022.

	Fiscal 2024 ($)			Fiscal 2023 ($)			Fiscal 2022 ($)
Revenues		116,033			688,827			878,459
Net loss		(3,989,276	)		(4,483,195	)		(2,714,616	)
Net loss per share - basic and diluted		(7.23	)		(8.81	)		(7.04	)
Total assets		12,061,223			10,941,747			12,567,558
Total non-current liabilities		392,977			341,623			400,594
Dividends		-			-			-

Factors That Affect the Comparability of the Annual Financial Data Disclosed Above

Net losses for the years ended September 30, 2024 and 2023 were mainly attributable to operating expenses (2024 - $3,034,410, 2023 - $4,668,466, 2022 - $3,783,122) and other income (2024 - $1,070,899, 2023 - $39,678, 2022 - $193,047), partially offset by revenue from oil and gas sales and royalty income (2024 - $116,033, 2023 - $688,827, 2022 - $878,459). The decrease in total assets during fiscal 2023 was mainly due to cash used for operating expenses. The increase in total assets in fiscal 2024 resulted from cash raised through debt financings. Changes in non-current liabilities were mainly driven by decreases in lease liability and change in estimates in asset retirement obligations.

38

Results of Operations

Selected Operating Data

Annual Sales and Production Results

The average sales prices of the Company’s oil and gas products sold in the fiscal years ended September 30, 2024, 2023, and 2022 were $70.53/Boe, $71.45/Boe, and $89.14/Boe, respectively.

The Company’s net production quantities by final product sold in the fiscal years ended September 30, 2024, 2023, and 2022, were 1,963.82 Boe, 12,979.36 Boe, and 12,597.45 Boe, respectively.

The Company’s average production costs per unit for the fiscal years ended September 30, 2024, 2023, and 2022, were $100.02/Boe, $67.76/Boe, and $65.82/Boe, respectively.

The breakdown of production and prices between oil/condensate and natural gas was as follows:

Net Production Volumes	Fiscal Year Ended September 30, 2024		Fiscal Year Ended September 30, 2023		Fiscal Year Ended September 30, 2022
Oil/Condensate (Bbl)		1,964		11,729		10,670
Natural Gas (Mcf)		-		7,500		11,567

Average Sales Price	Fiscal Year Ended September 30, 2024		Fiscal Year Ended September 30, 2023		Fiscal Year Ended September 30, 2022
Oil/Condensate ($/Bbl)		70.53		76.17		96.18
Natural Gas ($/Mcf)		-		4.53		8.36

The breakdown of the Company’s production quantities by individual product type for each of the Company’s fields that contain 15% or more of the Company’s total proved reserves expressed on an oil-equivalent-barrels basis was as follows:

Breedlove

Net Production Volumes	Fiscal Year Ended September 30, 2024		Fiscal Year Ended September 30, 2023		Fiscal Year Ended September 30, 2022
Oil/Condensate (Bbl)		1,229		7,628		6,998
Natural Gas (Mcf)		-		6,362		11,567

Henshaw

Net Production Volumes	Fiscal Year Ended September 30, 2024		Fiscal Year Ended September 30, 2023		Fiscal Year Ended September 30, 2022
Oil/Condensate (Bbl)		735		3,098		2,189
Natural Gas (Mcf)		-		1,138		-

Pittcock & Mary Bullard

Net Production Volumes	Fiscal Year Ended September 30, 2024		Fiscal Year Ended September 30, 2023		Fiscal Year Ended September 30, 2022
Oil/Condensate (Bbl)		-		1,003		1,483
Natural Gas (Mcf)		-		-		-

39

Operating Results

During the year ended September 30, 2024, the Company reported a net loss of $3,989,276 compared to a net loss of $4,483,195 for the year ended September 30, 2023. The reduction in net loss for fiscal 2024 compared to fiscal 2023 was mainly attributable to operating expenses of $3,135,281 in fiscal 2024 compared to operating expenses of $4,672,137 in the previous fiscal year, and other expenses of $970,028, compared to other income of $39,678 in fiscal 2023, being partially offset by revenue from oil and gas sales and royalty income totaling $116,033 in fiscal 2024, compared to $688,827 in fiscal 2023. Other expense for fiscal 2024 mainly consisted of a non-cash loss on debt extinguishment of $495,051 (2023 - $nil), due to the modification in the number of outstanding share purchase warrants in fiscal 2024, and interest and debt expenses of $483,110 (2023 - $4,259) associated with the issuance of the Initial United Debentures. Of this amount, $430,834 represents a non-cash debt discount and $50,004 is accrued interest.

The Company reported oil and gas sales revenue of $100,220 in fiscal 2024 compared to $665,623 in fiscal 2023. Net oil-equivalent production by final product sold averaged 5.38 barrels per day in fiscal 2024, down from 35.56 barrels per day in fiscal 2023. The Company faced significant financial constraints during the fiscal year ended September 30,2024, which limited available funds for field operations. Production across all fields was reduced in the early months of the fiscal year before all fields were shut down in February 2024 for nearly eight months until September 2024, when the Company began bringing the Breedlove field back online.

Lease operating expenses for fiscal 2024 totaled $196,428 compared to $879,471 in fiscal 2023. The decrease was primarily attributed to reduced production in the current year. Lease operating expenses exceeded oil and gas sales revenues mainly due to significant maintenance expenses on the West Henshaw wells.

General and administrative expenses

	2024			2023
Accounting and audit	$	433,719		$	849,783
Consulting		399,957			190,102
Filing and transfer agent		60,155			76,951
Insurance		173,835			230,706
Investor relations		93,844			283,650
Legal fees		668,881			758,367
Marketing and promotion		63,287			426,111
Office and miscellaneous		147,107			215,260
Rent		118,448			157,960
Salaries and benefits		712,841			440,996
Share-based payments		-			318
Travel		32,020			169,519
Gain on settlement of trade payables		(185,119	)		(263,605	)
	$	2,718,975		$	3,536,118

General and administrative expenses for the year ended September 30, 2024 were $2,718,975, compared to $3,536,118 in fiscal 2023. The reduction was mainly due to decreased property development and corporate activities during the current year, as management scaled back operations in response to tighter financial constraints. Key variances from the prior year include:

● Accounting and audit fees of $433,719 in fiscal 2024, down from $849,783 in fiscal 2023. The decrease largely reflects reduced overall activities. A substantial portion of the fees in the current year was related to regulatory compliance work associated with the proposed U.S. uplisting in November 2023.

● Consulting fees of $399,957 in fiscal 2024, up significantly from $190,102 in the prior year. The increase was primarily due to the engagement of three consultants in the current year for merger and acquisition activities, financing, and corporate legal matters. The Company also retained contract consultants for geological, project management, and corporate consulting work.

● Investor relation of $93,844 in fiscal 2024 decreased from $283,650 in fiscal 2023. The Company limited investor relations activities to a minimum in fiscal 2024 due to financial constraints.

● Legal fees of $668,881 in fiscal 2024, down from $758,367 in previous fiscal year. The legal fees in fiscal 2024 mainly related to the regulatory work associated with the Company’s proposed uplisting to the NASDAQ in November 2023 as well as compliance with the disclosure requirements under the Exchange Act.

● Marketing and promotion expenses of $63,287 in the current year, a significant increase from $426,111 in the prior year. This reduction was due to the Company scaling back marketing and promotion activities in fiscal 2024.

● Salaries and benefits expenses of $712,841 in fiscal 2024, a significant increase from $440,996 in fiscal 2023. Of this amount, $661,707 was for management salaries and benefits, an increase from $349,527 in the prior year due to the appointment of a new Chief Executive Officer in April 2024, with an annual salary of $250,000 and a one-time signing bonus of $50,000. Management salaries also included $180,155 in severance payments to the Company’s former Chief Executive Officer. Administrative salaries decreased to $51,134 in fiscal 2024, from $91,469 in the prior year.

Update on Use of Proceeds

During the year ended September 30, 2024, the Company completed two tranches of the private placement of convertible debenture units for gross proceeds of $1,365,000. The net proceeds were intended for potential mergers and acquisitions, general working capital, preparing and filing all outstanding financial statements and continuous disclosure records, paying revocation related legal and filing fees, settling outstanding amounts under certain claim judgments.

40

Liquidity and Capital Resources

As of September 30, 2024, the Company had a cash balance of $1,513,591, an increase of $1,430,855 from the cash balance of $82,736 on September 30, 2023. During the year ended September 30, 2024, cash used in operating activities was $2,285,918, primarily covering accounting, consulting, insurance, salary and general office expenses. The Company received $1,365,000 from debenture financings, $2,250,000 from debt financing subscriptions, $70,000 from reclamation deposit redemption, and $45,000 from a related party loan, while repaying $10,000 on a third-party loan.

The Company had a working capital deficiency of $5,857,870 as of September 30, 2024 compared to a working capital deficiency of $3,142,916 as of September 30, 2023. The Company will need substantial additional funding to pay the outstanding payables and bring the operated assets back to full production. This raises substantial doubt about the Company’s ability to continue as a going concern. The Company has decreased its activity to a minimal level to limit increases in the Company’s working capital deficiency. The Company has also limited its ongoing commitments and account demands going forward. Additionally, the Company is actively engaging with its trade partners to remedy its current working capital deficiency through all means available to it including but not limited to financing arrangements, payment plans, and principal reductions.

Management has budgeted approximately $3 million in operating expenses and $6.5 million in capital expenditures for the next 12 months, which the Company plans to finance principally from one or more equity or debt financings. The purpose of these funds will be to resume full field operations, reduce the working capital deficit, as well as invest in additional oil and gas production activities across the Company’s assets. The amount and timing of capital expenditures will depend on several factors including, but not limited to, the speed with which we are able to bring our wells to production, our ability to complete an equity financing or to secure a suitable line of credit, commodity prices, supply/demand considerations and attractive rates of return. There are no guarantees that we will be able to acquire the necessary funds to meet our budgeted capital expenditures, and any postponement of our planned development of our proved undeveloped reserves could materially affect our business, financial condition and results of operations.

Although the Company has budgeted investments of additional capital in the continued development of our oil and gas operations, the Company currently does not have any material commitments for capital expenditures. As of the date of this report, the Company does not have sufficient working capital to meet its anticipated operating and capital requirements over the next 12 months. Subsequent to September 30, 2024, the Company received additional $601,601 in subscription proceeds to close the first tranche of the Subsequent Private Placement. The Initial Unit Debentures of $1,365,000 and accrued interest of $59,788 were retired in exchange for the Subsequent Unit Debentures. The total gross proceeds raised from the Subsequent Unit Debentures financing are $4,276,389. The Company intends to use the financing proceeds for general working capital and capital development of its oil and gas properties.

Critical Accounting Estimates

The preparation of financial statements in accordance with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities at the date of the financial statements and the reported amount of revenue and expenses during the reporting period. Management evaluates these estimates and judgments on an ongoing basis and bases its estimates on experience, current and expected future conditions, third-party evaluations and various other assumptions that management believes are reasonable under the circumstances. We believe the following discussions of critical accounting estimates address all important accounting areas where the nature of accounting estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

Oil and natural gas reserves

Crude oil and natural gas reserves are estimates of future production that impact certain asset and expense accounts included in the consolidated financial statements. Proved reserves are the estimated quantities of oil and gas that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in the future under existing economic conditions, operating methods and government regulations. Proved reserves include both developed and undeveloped volumes. Proved developed reserves represent volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for recompletion. Variables impacting the Company’s estimated volumes of crude oil and natural gas reserves include field performance, available technology, commodity prices, and development, production and carbon costs.

41

The estimation of proved reserves is important to the consolidated statements of operations because the proved reserve estimate for a field serves as the denominator in the unit-of-production calculation of the depletion of the capitalized costs for that asset. If the estimates of proved reserves used in the unit-of-production calculations had been lower by 10 percent across all calculations, the depletion in the 2024 period would have increased by approximately $4,200.

Impairment

The Company tests long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable through the estimated undiscounted cash flows expected to result from the use and eventual disposition of the assets. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis for oil and gas assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates and prices believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, commodity prices, operating costs and capital decisions, considering all available evidence at the date of review. Differing assumptions could affect the timing and the amount of an impairment in any period.

Asset retirement obligations

The Company is subject to retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the Corporation uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, discount rates, and inflation rates.

A sensitivity analysis of the ARO impact on earnings is not practicable, given the broad range of the company’s long-lived assets and the number of assumptions involved in the estimates. Favorable changes to some assumptions would have reduced estimated future obligations, thereby lowering accretion expense and amortization costs, whereas unfavorable changes would have the opposite effect.

JOBS Act

On April 5, 2012, the JOBS Act was enacted. Section 107 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an “emerging growth company” can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies.

We have chosen to take advantage of the extended transition periods available to emerging growth companies under the JOBS Act for complying with new or revised accounting standards until those standards would otherwise apply to private companies provided under the JOBS Act. As a result, our financial statements may not be comparable to those of companies that comply with public company effective dates for complying with new or revised accounting standards.

Subject to certain conditions set forth in the JOBS Act, as an “emerging growth company,” we intend to rely on certain of these exemptions, including, without limitation, (i) providing an auditor’s attestation report on our system of internal controls over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act and (ii) complying with any requirement that may be adopted by the Public Company Accounting Oversight Board regarding mandatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit and the financial statements, known as the auditor discussion and analysis. We will remain an “emerging growth company” until the earliest of (i) the last day of the fiscal year in which we have total annual gross revenues of $1.235 billion or more; (ii) the last day of our fiscal year following the fifth anniversary of the date of our initial public offering; (iii) the date on which we have issued more than $1 billion in nonconvertible debt during the previous three years; or (iv) the date on which we are deemed to be a large accelerated filer under the rules of the SEC.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

42

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM  (PCAOB ID No. 688)	F-2
CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Balance Sheets	F-3
Consolidated Statements of Operations and Comprehensive Loss	F-4
Consolidated Statements of Changes in Stockholders’ Equity	F-5
Consolidated Statements of Cash Flows	F-6
Notes to the Consolidated Financial Statements	F-7
Supplemental Information on Oil and Gas Operations (Unaudited)	F-24

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of

Permex Petroleum Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Permex Petroleum Corporation (the “Company”) as of September 30, 2024 and 2023, the related consolidated statements of operations and comprehensive loss, stockholders’ equity and cash flows for each of the two years in the period ended September 30, 2024, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2024 and 2023, and the results of its operations and its cash flows for each of the two years in the period ended September 30, 2024, in conformity with accounting principles generally accepted in the United States of America.

Explanatory Paragraph – Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As more fully described in Note 2, the Company has a significant working capital deficiency, has incurred significant losses and needs to raise additional funds to meet its obligations and sustain its operations. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Marcum LLP

Marcum LLP

We have served as the Company’s auditor since 2022.

Houston, Texas

January 14, 2025

F-2

PERMEX PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

AS AT SEPTEMBER 30

	2024			2023
ASSETS
Current assets
Cash	$	1,513,591		$	82,736
Trade and other receivables (net of allowance: 2024 - $nil; 2023 - $nil)		44,932			78,441
Prepaid expenses and deposits		146,452			127,239
Total current assets		1,704,975			288,416
Non-current assets
Reclamation deposits		75,000			145,000
Property and equipment, net of accumulated depletion and depreciation		10,281,248			10,361,419
Right of use asset, net		-			146,912
Total assets	$	12,061,223		$	10,941,747
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Trade and other payables	$	3,786,909		$	3,228,327
Loans payable		160,936			125,936
Convertible debentures		1,365,000			-
Debt subscription proceeds		2,250,000			-
Lease liability – current portion		-			77,069
Total current liabilities		7,562,845			3,431,332
Non-current liabilities
Asset retirement obligations		392,977			260,167
Lease liability, less current portion		-			81,456
Total liabilities		7,955,822			3,772,955
Stockholders’ Equity
Common stock, no par value per share; unlimited shares authorized, 551,503 shares* issued and outstanding as of September 30, 2024 and 2023.		14,947,150			14,947,150
Additional paid-in capital		5,475,316			4,549,431
Accumulated other comprehensive loss		(127,413	)		(127,413	)
Accumulated deficit		(16,189,652	)		(12,200,376	)
Total stockholders’ equity		4,105,401			7,168,792
Total liabilities and stockholders’ equity	$	12,061,223		$	10,941,747

* The number of shares has been restated to reflect the 4:1 reverse stock split effective on October 23, 2023 (Note 1). All historical share and per share amounts reflected in this report have been adjusted to reflect the reverse stock split.

The accompanying notes are an integral part of these consolidated financial statements

F-3

PERMEX PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS

YEARS ENDED SEPTEMBER 30

	2024			2023
Revenues
Oil and gas sales	$	100,220		$	665,623
Royalty income		15,813			23,204
Total revenues		116,033			688,827
Operating expenses
Lease operating expense		196,428			879,471
General and administrative		2,718,975			3,536,118
Depletion and depreciation		82,215			154,834
Accretion on asset retirement obligations		36,792			31,976
Loss on settlement of asset retirement obligations		-			66,067
Loss on settlement of lease liability		38,825			-
Write-off of property and equipment		62,046			-
Total operating expenses		(3,135,281	)		(4,668,466	)
Loss from operations		(3,019,248	)		(3,979,639	)
Other income (expense)
Interest income		-			108
Other income		8,000			24,000
Foreign exchange gain (loss)		133			(3,671	)
Change in fair value of warrant liability		-			22,570
Gain on settlement of warrant liability		-			930
Interest and debt expense		(483,110	)		(4,259	)
Loss on debt extinguishment		(495,051	)		-
Total other income (expense)		(970,028	)		39,678
Net loss and comprehensive loss		(3,989,276	)		(3,939,961	)
Deemed dividend arising from warrant modification		-			(543,234	)
Net loss attributable to common stockholders	$	(3,989,276	)	$	(4,483,195	)
Basic and diluted loss and comprehensive loss per common share	$	(7.23	)	$	(8.81	)
Weighted average number of common shares outstanding*		551,503		$	508,813

* The number of shares has been restated to reflect the 4:1 reverse stock split effective on October 23, 2023 (Note 1). All historical share and per share amounts reflected in this report have been adjusted to reflect the reverse stock split.

The accompanying notes are an integral part of these consolidated financial statements.

F-4

PERMEX PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

	Number of Shares*		Share capital			Additional paid-in capital			Accumulated other comprehensive loss			Accumulated deficit			Total stockholders’ equity
Balance, September 30, 2022		483,150	$	14,337,739		$	4,513,194		$	(127,413	)	$	(8,260,415	)	$	10,463,105
Exercise of warrants		68,353		781,953			-			-			-			781,953
Share issuance costs		-		(172,542	)		35,919			-			-			(136,623	)
Deemed dividend arising from warrant modification		-		-			543,234			-			-			543,234
Warrant modification		-		-			(543,234	)		-			-			(543,234	)
Share-based payments		-		-			318			-			-			318
Net loss		-		-			-			-			(3,939,961	)		(3,939,961	)
Balance, September 30, 2023		551,503	$	14,947,150		$	4,549,431		$	(127,413	)	$	(12,200,376	)	$	7,168,792
Warrants issued in private placement		-		-			431,666			-			-			431,666
Warrants issued for debt amendment		-		-			494,219			-			-			494,219
Net loss		-		-			-			-			(3,989,276	)		(3,989,276	)
Balance, September 30, 2024		551,503	$	14,947,150		$	5,475,316		$	(127,413	)	$	(16,189,652	)	$	4,105,401

* The number of shares has been restated to reflect the 4:1 reverse stock split effective on October 23, 2023 (Note 1). All historical share and per share amounts reflected in this report have been adjusted to reflect the reverse stock split.

The accompanying notes are an integral part of these consolidated financial statements.

F-5

PERMEX PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED SEPTEMBER 30

	2024			2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(3,989,276	)	$	(3,939,961	)
Adjustments to reconcile net loss to net cash from operating activities:
Accretion on asset retirement obligations		36,792			31,976
Depletion and depreciation		82,215			154,834
Foreign exchange loss (gain)		(133	)		-
Amortization of debt discount		430,834			-
Loss on debt extinguishment		495,051			-
Change in fair value of warrant liability		-			(22,570	)
Gain on settlement of warrant liability		-			(930	)
Loss on settlement of asset retirement obligations		-			66,067
Share-based payments		-			318
Loss on settlement of lease liability		38,825			-
Gain on settlement of trade payables		(185,119	)		-
Write-off of property and equipment		62,046			-
Changes in operating assets and liabilities:
Trade and other receivables		33,509			58,773
Prepaid expenses and deposits		(19,213	)		190,038
Trade and other payables		778,989			1,157,736
Right of use asset and lease liability		(50,438	)		7,503
Net cash used in operating activities		(2,285,918	)		(2,296,216	)
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures on property		(3,227	)		(1,445,021	)
Reclamation deposit redemption		70,000			-
Net cash provided by (used in) investing activities		66,773			(1,445,021	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from debenture financing		1,365,000			-
Proceeds from debt financing subscriptions received		2,250,000			-
Proceeds from exercise of warrants		-			781,953
Share issuance costs		-			(136,623	)
Convertible debenture repayment to related party		-			(38,291	)
Loan payable proceeds		45,000			-
Loan repayment		(10,000	)		(83,561	)
Net cash provided by financing activities		3,650,000			523,478
Change in cash during the year		1,430,855			(3,217,759	)
Cash, beginning of the year		82,736			3,300,495
Cash, end of the year	$	1,513,591		$	82,736
Supplemental cash flow disclosures:
Interest paid	$	2,272		$	4,259
Taxes paid	$	-		$	-
Supplemental disclosures of non-cash investing and financing activities:
Share purchase warrants issued in connection with debt issuance	$	431,666		$	-
Share purchase warrants issued in connection with exercise of warrants	$	-		$	579,153
Trade and other payables related to property and equipment	$	-		$	1,299,929
Equipment transferred in settlement with former CEO	$	35,155		$	-
Loan payable issued for settlement	$	-		$	209,497
Changes in estimates of asset retirement obligations	$	(96,018	)	$	7,934

The accompanying notes are an integral part of these consolidated financial statements.

F-6

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

1. BACKGROUND

Permex Petroleum Corporation (the “Company”) was incorporated on April 24, 2017 under the laws of British Columbia, Canada and maintains its head office at 1700 Post Oak Boulevard, 2 Blvd Place Suite 600, Houston Texas, 77056. Its registered office is located at 10^th floor, 595 Howe Street, Vancouver, British Columbia, Canada, V6C 2T5. The Company is primarily engaged in the acquisition, development and production of oil and gas properties in the United States. The Company’s oil and gas interests are located in Texas and New Mexico, USA. The Company is listed on the Canadian Securities Exchange (the “CSE”) under the symbol “OIL”.

On September 12, 2023, the Company’s board of directors approved a reverse stock split of the Company’s issued and outstanding common stock at a 1 for 4 ratio, which was effective October 23, 2023. All issued and outstanding common stock, options, and warrants to purchase common stock and per share amounts contained in the financial statements have been retroactively adjusted to reflect the reverse stock splits for all periods presented.

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

The Company’s consolidated financial statements are prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”).

Principles of Consolidation

The accompanying consolidated financial statements include the assets, liabilities, revenue and expenses of the Company’s wholly-owned subsidiary, Permex Petroleum US Corporation. All intercompany balances and transactions have been eliminated.

Going concern of operations

These consolidated financial statements have been prepared on a going concern basis which assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business. The Company has incurred losses since inception in the amount of $16,189,652, has a working capital deficiency of $5,857,870 as of September 30, 2024 and has not yet achieved profitable operations. The Company requires equity or debt financings to fund its continuing operation, which it has been unable to secure in sufficient amounts to date, and there can be no assurances that it will be able to do so in the future. The aforementioned factors raise substantial doubt about the Company’s ability to continue as a going concern within one year after the date that the financial statements are issued.

The Company expects to raise additional funds through equity and debt financings. There is no assurance that such financing will be available in the future. During the year ended September 30, 2024, the Company raised $1,365,000 through the issuance of convertible debentures and received additional proceeds of $2,250,000 from debt financing subscriptions. Subsequent to September 30, 2024, the Company received further subscription proceeds of $601,601 to complete a convertible debenture financing with total gross proceeds of $4,276,389. The $1,365,000 convertible debentures that matured on September 12, 2024 and accrued interest of $59,788 were retired in exchange for the new convertible debenture units. Management believes that these actions provide a path for the Company to continue as a going concern subject to its continued ability to raise funds to maintain its operations and manage its working capital deficiency.

In view of these matters, continuation as a going concern is dependent upon continued operations of the Company, which in turn is dependent upon the Company’s ability to meet its financial requirements, raise additional capital, and the success of its future operations. The financial statements do not include any adjustments to the amount and classification of assets and liabilities that may be necessary should the Company not continue as a going concern.

F-7

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. Significant Accounting Policies (cont’d…)

Use of Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities at the date of the financial statements and the reported amount of revenue and expenses during the reporting period. Management evaluates these estimates and judgments on an ongoing basis and bases its estimates on experience, current and expected future conditions, third-party evaluations and various other assumptions that management believes are reasonable under the circumstances.

Significant estimates have been used by management in conjunction with the following: (i) the fair value of assets when determining the existence of impairment factors and the amount of impairment, if any; (ii) the costs of site restoration when determining decommissioning liabilities; (iii) the useful lives of assets for the purposes of depletion and depreciation; (iv) petroleum and natural gas reserves; and (v) share-based payments. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, and makes adjustments when facts and circumstances dictate. These estimates are based on information available as of the date of the financial statements; therefore, actual results could differ from those estimates.

Cash and cash equivalents

The Company considers all highly liquid investments with an original maturity of three months or less when purchased to be cash and cash equivalents. Cash and cash equivalents are recorded at cost, which approximates fair value. The Company had no cash equivalents as of September 30, 2024 and 2023.

Trade and other receivables

Trade and other receivables are stated at net realizable value. The majority of customers have payment terms of 30 days or less. The Company’s oil and gas revenues are mainly derived from three significant customers. As a result, the Company’s trade receivables are exposed to a concentration of credit risk. The Company routinely assesses the financial strength of its customers. On a periodic basis, management evaluates its accounts receivable and determines whether to provide an allowance or if any accounts should be written off based on a past history of write-offs, collections, and current credit conditions. A receivable is considered past due if the Company has not received payments based on agreed-upon terms.

Property and equipment

The Company follows the successful efforts method of accounting for its oil and gas properties. All costs for development wells along with related acquisition costs, the costs of drilling development wells, and related estimated future asset retirement costs are capitalized. Exploration costs, such as exploratory geological and geophysical costs, and costs associated with non-productive exploratory wells, delay rentals and exploration overhead are expensed. Costs of drilling exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company groups its oil and gas properties with a common geological structure or stratigraphic condition (“common operating field”) for purposes of computing depletion expenses, assessing proved property impairments and accounting for asset dispositions.

Capitalized costs of proved oil and gas properties are depleted by individual field using a unit-of-production method based on proved and probable developed reserves. Proved reserves are estimated using reserve engineer reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids, which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible.

F-8

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. Significant Accounting Policies (cont’d…)

Property and equipment (cont’d…)

Proved oil and natural gas properties are assessed for possible impairment by comparing their carrying values with their associated undiscounted future net cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset (including changes to the commodity price forecast or carbon costs), significant change in the extent or manner of use of or a physical change in an asset, and a more-likely-than-not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted, future net cash flows. For proved oil and natural gas properties, the Company performs impairment reviews on a field basis, annually or as appropriate.

Other corporate property and equipment consist primarily of leasehold improvements, vehicle, and office furniture and equipment and are stated at cost less accumulated depreciation. The capitalized costs are generally depreciated on a straight line basis over their estimated useful lives ranging from three to five years.

For property dispositions, measurement is at fair value, unless the transaction lacks commercial substance or fair value cannot be reliably measured. Where the exchange is measured at fair value, a gain or loss is recognized in net income.

Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s depletion rate. These gains and losses are classified as asset dispositions in the accompanying consolidated statements of loss and comprehensive loss. Partial common operating field sales or dispositions deemed not to significantly alter the depletion rates are generally accounted for as adjustments to capitalized costs with no gain or loss recognized.

Impairment of long-lived assets

The Company assesses long-lived assets for impairment in accordance with the provisions of the Financial Accounting Standards Board Accounting Standards Codification (“ASC”) regarding long-lived assets. It requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable through the estimated undiscounted cash flows expected to result from the use and eventual disposition of the assets. Whenever any such impairment exists, an impairment loss will be recognized for the amount by which the carrying value exceeds the fair value. As of September 30, 2024 and 2023, no impairment charge has been recorded.

Asset retirement obligations

The Company recognizes asset retirement obligations (“ARO”) associated with tangible assets such as well sites when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The ARO are measured at the present value of management’s best estimate of the future remediation expenditures at the reporting date. The initial measurement of an ARO is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumption used to estimate a recorded ARO change, a revision is recorded to both the ARO and the asset retirement cost. The ARO is accreted to its then present value each period, and the asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.

F-9

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. SIGNIFICANT ACCOUNTING POLICIES (cont’d…)

Fair value measurement

Fair value accounting is applied for all assets and liabilities and nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Fair value is defined as the exchange price that would be received for an asset or an exit price that would be paid to transfer a liability in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The Company follows the established framework for measuring fair value and expands disclosures about fair value measurements.

The Company categorizes its assets and liabilities measured at fair value into a three-level hierarchy based on the priority of the inputs to the valuation technique used to determine fair value. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used in the determination of the fair value measurement fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement.

Assets and liabilities valued at fair value are categorized based on the inputs to the valuation techniques as follows:

Level 1 – Inputs that utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access.

Level 2 – Inputs that include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. Fair values for these instruments are estimated using pricing models, quoted prices of securities with similar characteristics, or discounted cash flows.

Level 3 – Inputs that are unobservable inputs for the asset or liability, which are typically based on an entity’s own assumptions, as there is little, if any, related market activity.

The carrying values of cash, trade receivable, other current receivables, due from/to related parties, trade payable, other current payables, accrued expenses, convertible debenture and lease liability included in the accompanying consolidated balance sheets approximated fair value at September 30, 2024 and 2023. The financial statements as of and for the years ended September 30, 2024 and 2023, do not include any recurring or nonrecurring fair value measurements relating to assets or liabilities.

Subsequent to initial recognition, the Company may re-measure the carrying value of assets and liabilities measured on a nonrecurring basis to fair value. Adjustments to fair value usually result when certain assets are impaired. Such assets are written down from their carrying amounts to their fair value.

Professional standards allow entities the irrevocable option to elect to measure certain financial instruments and other items at fair value for the initial and subsequent measurement on an instrument-by-instrument basis. The Company has not elected to measure any existing financial instruments at fair value. However, it may elect to measure newly acquired financial instruments at fair value in the future.

Earnings (loss) per share

Basic earnings (loss) per share (“EPS”) is calculated by dividing net income (loss) attributable to common shareholders by the weighted average number of common shares outstanding in the period. The diluted EPS reflects all dilutive potential common share equivalents, in the weighted average number of common shares outstanding during the period, if dilutive. All of the outstanding convertible securities, stock options and warrants were anti-dilutive for the years ended September 30, 2024 and 2023.

F-10

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. SIGNIFICANT ACCOUNTING POLICIES (cont’d…)

Leases

At inception of a contract, the Company assesses whether a contract is or contains a lease based on whether the contract conveys the right to control the use of an identified asset for a period in exchange for consideration.

The Company recognizes a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured based on the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date.

The lease obligation is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Company’s incremental borrowing rate. Generally, the Company uses its incremental borrowing rate as the discount rate. Variable lease payments that do not depend on an index or rate are not included in the measurement of the lease liability. The lease liability is subsequently measured at amortized cost using the effective interest rate method.

Share capital

The Company records proceeds from the issuance of its common shares as equity. Incremental costs directly attributable to the issue of new common shares are shown in equity as a deduction from the proceeds. Common shares issued for consideration other than cash are valued based on their fair value at the date that the shares are issued.

Share purchase warrants

The fair value of warrants is determined using the Black-Scholes option pricing model. Proceeds from the issuance of private placement units are allocated between the private placement warrants and common shares on a relative fair value basis. Share purchase warrants with exercise prices denominated in a currency other than its functional currency are classified as a liability. Proceeds from the issuance of private placement units are first allocated to the warrant liability based on their fair value and the residual is allocated to common shares issued while for equity warrants, proceeds are allocated to common stock and additional paid in capital on a relative fair value basis. The changes in fair value of the warrant liability are recorded in the statement of loss and comprehensive loss.

Warrants issued for oil and gas interests and warrants issued as finder’s fees are share-based payments and are measured at fair value on the date of the grant as determined using the Black-Scholes option pricing model.

Share-based payments

The Company issues stock options and other share-based compensation to directors, employees and other service providers. Equity awards including stock options and share purchase warrants are measured at grant date at the fair value of the instruments issued and amortized over the vesting periods using a graded vesting approach. The number of options expected to vest is reviewed and adjusted at the end of each reporting period such that the amount ultimately recognized as an expense is based on the number of options that eventually vest. The Company has elected to account for forfeitures as they occur rather than estimate expected forfeitures.

The fair value of the equity awards is determined using the Black-Scholes option pricing model. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility (based on weighted average historic volatility), weighted average expected life of the instruments (based on historical experience), expected dividends, and the risk-free interest rate (based on government bonds).

F-11

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. SIGNIFICANT ACCOUNTING POLICIES (cont’d…)

Revenue

In accordance with ASC 606, Revenue from Contracts with Customers, the Company recognizes revenue when the performance obligation is satisfied, which typically occurs at the point in time when control of the product transfer to the customer. For natural gas, this is generally at the time product enters the pipeline. For crude oil, this is generally at the time the product is loaded into customer operated transports. Revenue is measured net of discounts, customs duties, royalties and withholding tax. Royalty income represents net revenue interests from certain crude oil and natural gas wells and is recognized upon the operators of the properties producing revenue from subject oil and gas wells.

The Company records revenue in the month production is delivered to the purchaser. However, production statements for oil and gas sales may not be received until the following month end after the products are purchased, and as a result, the Company is required to estimate the amount of revenue to be received. The Company records the differences between its estimates and the actual amounts received for revenue in the month that payment is received from the customer. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to sales volumes and prices for those good sold are estimated and recorded.

The Company does not have any contract assets or liabilities, or capitalized contract costs.

Foreign Currency

These consolidated financial statements are presented in United States dollars (“U.S. dollar”). The functional currency of the Company and the subsidiary of the Company is the U.S. dollar. Foreign currency transactions are translated into the functional currency using exchange rates prevailing at the dates of the transactions. At the end of each reporting period, monetary assets and liabilities that are denominated in foreign currencies are translated at the rates prevailing at that date. All gains and losses on these foreign currency transactions are charged to profit or loss.

F-12

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. SIGNIFICANT ACCOUNTING POLICIES (cont’d…)

Income taxes

Current taxes receivable or payable are estimated on taxable income or loss for the current year at the statutory tax rates enacted or substantively enacted at the reporting date.

Deferred income tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Deferred income tax assets and liabilities are measured at the tax rates that have been enacted or substantially enacted at the end of the reporting period and are expected to apply when the related deferred income tax asset is realized or the deferred income tax liability is settled. Deferred income tax assets also result from unused loss carry forwards, resource related pools and other deductions. At the end of each reporting year the Company reassesses unrecognized deferred tax assets. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Deferred income tax assets and deferred income tax liabilities are offset if a legally enforceable right exists to offset current tax assets against current tax liabilities and the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority.

The Company recognizes a tax benefit in the financial statements for an uncertain tax position only if management assesses that the position is more likely than not (i.e., a likelihood greater than 50%) to be allowed by the tax jurisdiction, based solely on the technical merits of the position. The term “tax position,” as defined in the accounting standards for income taxes, refers to a position in a previously filed tax return or a position expected to be taken in a future tax return. This position is reflected in the measurement of current or deferred income tax assets and liabilities for interim or annual periods.

New accounting standards

In November 2023, the FASB issued ASU 2023 - 07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which becomes effective for fiscal years beginning after December 15, 2024. This update requires public entities to disclose significant expenses for reportable segments in both interim and in annual reporting periods, while entities with only a single reportable segment must now provide all segment disclosures required both in ASC 280 and under the amendments in ASU 2023-07. The Company does not expect the standard to have a material effect on its consolidated financial statements and has begun evaluating disclosure presentation alternatives.

In December 2023, the FASB issued ASU 2023 - 09, Income Taxes (Topic740) Improvements to Income Tax Disclosures, which becomes effective for fiscal years beginning after December 15, 2024. The standard requires companies to disclose specific categories in the income tax rate reconciliation table and the amount of income taxes paid per major jurisdiction. The Company does not expect the standard to have a material effect on its consolidated financial statements and has begun evaluating disclosure presentation alternatives.

3. REVENUE

Revenue from contracts with customers is presented in “Oil and gas sales” on the Consolidated Statement of Operations.

As of September 30, 2024 and 2023, receivables from contracts with customers, included in trade and other receivables, were $26,873 and $48,165, respectively.

The following tables present our revenue from contracts with customers disaggregated by product type and geographic area.

Year ended September 30, 2024	Texas		New Mexico		Total
Crude oil	$	64,611	$	35,609	$	100,220
Natural gas		-		-		-
Revenue from contracts with customers	$	64,611	$	35,609	$	100,220

Year ended September 30, 2023	Texas		New Mexico		Total
Crude oil	$	501,920	$	154,700	$	656,620
Natural gas		9,003		-		9,003
Revenue from contracts with customers	$	510,923	$	154,700	$	665,623

F-13

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

4. CONCENTRATION OF CREDIT RISK

The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash and trade receivables. The Company’s cash balances sometimes exceed the United States’ Federal Deposit Insurance Corporation insurance limits. The Company mitigates this risk by placing its cash with high credit quality financial institutions and attempts to limit the amount of credit exposure with any one institution. To date, the Company has not recognized any losses caused by uninsured balances.

Trade receivables included in the Company’s receivable balance are $26,873 as of September 30, 2024 (September 30, 2023 - $73,021). For the years ended September 30, 2024 and 2023, we had two significant customers that accounted for approximately 100% and 99%, respectively, of our total oil, and natural gas revenues. The Company routinely assesses the financial strength of its customers. The non-trade receivable balance consists of goods and services tax (“GST”) recoverable of $18,060 (September 30, 2023 - $5,420). GST recoverable is due from the Canadian Government. It is management’s opinion that the Company is not exposed to significant credit risk. During the year ended September 30, 2024, the Company recognized $9,587 (2023 - $nil) in credit losses on its other receivables.

5. PROPERTY AND EQUIPMENT

Property and equipment consisted of the following:

	September 30, 2024			September 30, 2023
Oil and natural gas properties, at cost	$	10,600,489		$	10,501,244
Less: accumulated depletion		(330,036	)		(289,456	)
Oil and natural gas properties, net		10,270,453			10,211,788
Other property and equipment, at cost		18,505			205,315
Less: accumulated depreciation		(7,710	)		(55,684	)
Other property and equipment, net		10,795			149,631
Property and equipment, net	$	10,281,248		$	10,361,419

Depletion and depreciation expenses were $82,215 and $154,834 for the years ended September 30, 2024 and 2023, respectively. The Company also recorded write-offs of property and equipment of $62,046 and $nil for the years ended September 30, 2024 and 2023, respectively

F-14

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

6. LEASES

All of the Company’s right-of-use assets are operating leases related to its office premises. Details of the Company’s right-of-use assets and lease liabilities are as follows:

	September 30, 2024			September 30, 2023
Right-of-use assets	$	-		$	146,912
Lease liabilities
Balance, beginning of the year	$	158,525		$	244,906
Addition		-			-
Liability accretion		12,346			24,221
Lease payments		(113,638	)		(110,602	)
Termination of lease		(57,233	)		-
Balance, end of the year	$	-		$	158,525
Current lease liabilities	$	-		$	77,069
Long-term lease liabilities	$	-		$	81,456
Weighted-average remaining lease term (in years)		-			2.17
Weighted-average discount rate		-	%		12	%

The following table presents the Company’s total lease cost.

	2024		2023
Operating lease cost	$	63,200	$	118,105
Variable lease expense		51,062		65,245
Sublease income		-		(25,390	)
Net lease cost	$	114,262	$	157,960

The Company had one office lease agreement for its office premises for terms ending in November 2025. During the year ended September 30, 2024, the Company entered into a settlement agreement to terminate the office lease agreement. The termination resulted in a loss of $38,825, consisting of the settlement payment and the write-off of the remaining right-of-use asset and lease liability associated with the terminated lease.

F-15

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

7. ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties. Changes to the asset retirement obligations are as follows:

	2024		2023
Asset retirement obligations, beginning of the year	$	260,167	$	236,412
Obligations recognized		27,859		-
Obligations derecognized		-		(287	)
Revisions of estimates		68,159		(7,934	)
Accretion expense		36,792		31,976
	$	392,977	$	260,167

During the year ended September 30, 2024, the Company had a revision of estimates totaling $68,159 (2023 - $7,934) primarily due to changes in the timing of expected cash flows. During the year ended September 30, 2023, the Company incurred plugging and abandonment costs of $66,354 and recognized a loss of $66,067 on the settlement.

Reclamation deposits

As of September 30, 2024, the Company held reclamation deposits of $75,000 (September 30, 2023 - $145,000), which are expected to be released after all reclamation work has been completed with regard to its oil and natural gas interests. During the year ended September 30, 2024, the Company redeemed $70,000 in reclamation deposits.

8. DEBT

Convertible debentures

During the year ended September 30, 2024, the Company completed private placement financings of 1,365 convertible debenture units (each a “Unit”) for gross proceeds of $1,365,000. Each Unit is comprised of one senior secured convertible debenture in the principal amount of $1,000 and 294 common share purchase warrants as amended. Each warrant is exercisable for a period of five years from the date of issuance for one common share of the Company at an exercise price of $4.08 per share. As a result, the Company issued convertible debentures with an aggregate principal amount of $1,365,000 and 401,310 Warrants.

Of the 1,365 Units issued, 500 Units were originally comprised of one secured convertible debenture in the principal amount of $1,000 and 1 common share purchase warrant. The number of warrants issued with these Units was subsequently modified to 294 warrants per Unit. No other terms of the debt or warrant were modified. This modification was assessed as a debt extinguishment. A loss of $495,051 was recognized, consisting of $494,219 representing the fair value of the amended warrants determined using the Black-Scholes option pricing model (assuming a risk-free interest rate of 3.41%, an expected life of 5 years, annualized volatility of 128.69% and a dividend rate of 0%) and an unamortized discount of $832 on the original warrants.

The Company allocated the proceeds received from the issuance of the convertible debentures and warrants between the debt and equity components based on their relative fair values at the issuance date. Due to the lack of an active market for the Company’s privately placed debt instruments and the absence of relevant observable inputs, the Company determined that a reliable estimate of the fair value of the convertible debentures could not be obtained. Accordingly, the face value of the debentures is considered to be a reasonable approximation of their fair value at the issuance date. The fair value of the warrants issued was determined using the Black-Scholes option pricing model (assuming a risk-free interest rate of 3.41%, an expected life of 5 years, annualized volatility of 128.69% and a dividend rate of 0%). $431,666 of the proceeds allocated to the warrants was recorded as additional paid-in capital with a corresponding debt discount, which is being amortized over the term of the debt. As of September 30, 2024, the debt discount was fully amortized.

The Convertible Debentures were secured by the Company’s assets, bore simple interest at a rate of 10% per annum, and matured on September 12, 2024. These Convertible Debentures were convertible into common shares of the Company at a conversion price of $3.40 per share. Interest was payable on the maturity date or upon the repayment of all or a portion of the Convertible Debenture and could be settled in cash or shares at the same conversion price. As of September 30, 2024, the Company had recorded $50,008 in accrued interest on the Convertible Debentures.

F-16

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

8. DEBT (cont’d…)

As September 30, 2024, the following Convertible Debentures were outstanding:

Principal Amount		Interest rate			Maturity Date
$	500,000		10	%	September 12, 2024
	865,000		10	%	September 12, 2024
$	1,365,000

As of September 30, 2024, these Convertible Debentures were in default due to the Company’s failure to repay the principal and accrued interest by the maturity date. Subsequent to September 30, 2024, the Company repaid the Convertible Debentures and the accrued interest in full.

Proceeds from debt financing subscriptions

In September 2024, the Company announced a non-brokered private placement of up to 18,635 convertible debenture units of the Company (each, a “Unit”). Each Unit consists of one convertible debenture (a “Debenture”) in the principal amount of $1,000 and 523 common share purchase warrants. Each warrant is exercisable for a period of five years from the date of issuance for one common share of the Company at an exercise price of $1.91 per share. The Debentures will be secured by the Company’s assets, mature one-year from the date of issuance, and bear simple interest at a rate of 10% per annum, payable on the maturity date or upon repayment of all or any portion of the Debenture. The Debentures are convertible into common shares of the Company at a conversion price of $1.91 per share. Interest will be payable in cash or shares based on the same conversion price. As of September 30, 2024, the Company had received subscription proceeds totaling $2,250,000. The private placement was completed on November 1, 2024 for total gross proceeds of $4,276,389 (Note 15).

Loan payable

During the year ended September 30, 2024, the Company received a $45,000 loan from a former director of the Company. The loan is unsecured, non-interest bearing, and has no specific repayment terms.

On April 28, 2023, the Company issued a promissory note with a principal amount of $209,497 to a supplier to settle an outstanding trade payable. The promissory note is unsecured and bears interest at 6% per annum, payable on September 30, 2023. At September 30, 2024, the Company has an outstanding unpaid principal amount of $115,936 (September 30, 2023 - $125,936). The promissory note was in default due to the Company’s failure to repay the principal amount by its maturity date.

Debenture loan – Related party

During the year ended September 30, 2023, the Company repaid the remaining principal amount of $38,291 (CAD$52,454) on the debenture loan due to the former CEO of the Company. During the years ended September 30, 2023, the Company recorded interest of $1,182.

F-17

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

9. RELATED PARTY TRANSACTIONS

(a)	The Company entered into an employment agreement with Bradley Taillon, the Company’s Chief Executive Officer, on April 29, 2024, for an annual base salary of base salary of $250,000, which shall be reviewed by the Company annually. Subject to the discretion of the board of directors, Mr. Taillon is also eligible on an annual basis for a cash bonus of up to 100% of annual salary and additional performance bonuses ranging from $50,000 to $750,000 upon the closing of a qualified financing with proceeds to the Company of $1 million or greater. Further, the terms of this employment agreement provide that if Mr. Taillon’s employment with the Company is terminated without “cause” (as defined in the agreement) than Mr. Taillon is entitled to a severance payment equal to two years of base salary and a bonus equal to 50% of his annual base salary. During the year ended September 30, 2024, the Company incurred management salary of $122,312 and a one-time sign-on bonus of $50,000 for Mr. Taillon.
(b)	The Company had an employment agreement with Mehran Ehsan, the former Chief Executive Officer of the Company, for an annual base salary of $250,000, with no specified term. Mr. Ehsan was also eligible on an annual basis for a cash bonus of up to 100% of annual salary, subject to the discretion of the board of directors. During the year ended September 30, 2024, the Company incurred management salary of $229,167 (2023 - $250,000), for Mr. Ehsan, with no bonuses incurred in either period. Further, the terms of this employment agreement provided that if Mr. Ehsan’s employment with the Company is terminated without “cause” (as defined in the agreement) than Mr. Ehsan was entitled to a severance payment equal to three years of base salary and a bonus equal to 20% of his annual base salary. Mr. Ehsan resigned as President and CEO of the Company on April 29, 2024. On May 15, 2024, the Company amended the employment agreement to change his role to Vice President of Business Development. All other terms and conditions of the employment agreement remained the same. On August 30, 2024, the Company signed a separation agreement to terminate Mr. Ehsan’s employment. The settlement includes: i) a lump sum payment of $100,000 by October 31, 2024 (subsequently paid); ii) six equal monthly payments of $7,500 starting October 1, 2024; and iii) the transfer of ownership of a Company vehicle with a fair value of $35,155. The settlement amount of $145,000 was accrued as of September 30, 2024.
c)	On May 1, 2022, the Company entered into an employment agreement with the CFO of the Company for an annual base salary of $50,000, with no specified term. The CFO is also eligible on an annual basis for a cash bonus of up to 100% of annual salary, subject to the discretion of the board of directors. The employment agreement may be terminated with a termination payment equal to two months of base salary. During the year ended September 30, 2024, the Company incurred management salary of $50,000 (2023 - $50,000), to the CFO of the Company, with no bonuses incurred in either period.
d)	The convertible debenture loan from the former CEO of the Company mentioned in Note 8 was repaid off during the year ended September 30, 2023.

10. LOSS PER SHARE

The calculation of basic and diluted loss per share for the years ended September 30, 2024 and 2023 was based on the net losses attributable to common shareholders. The following table sets forth the computation of basic and diluted loss per share:

	2024			2023
Net loss	$	(3,989,276	)	$	(4,483,195	)
Weighted average common shares outstanding		551,503			508,813
Basic and diluted loss per share	$	(7.23	)	$	(8.81	)

For the year ended September 30, 2024, 10,105 stock options, 676,663 warrants, and $1,365,000 of convertible debentures convertible into 401,471 common shares were excluded from the diluted weighted average number of common shares calculation as their effect would have been anti-dilutive.

For the year ended September 30, 2023, 20,313 stock options and 279,746 warrants were excluded from the diluted weighted average number of common shares calculation as their effect would have been anti-dilutive.

F-18

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

11. EQUITY

Common stock

The Company has authorized an unlimited number of common shares with no par value. At September 30, 2024 and 2023, the Company had 551,503 common shares issued and outstanding after giving effect to the 4:1 reverse stock split effective October 23, 2023. All issued and outstanding common stock, options, and warrants to purchase common stock and per share amounts contained in the financial statements have been retroactively adjusted to reflect the reverse stock split.

There were no share issuance transactions during the year ended September 30, 2024

During the year ended September 30, 2023, the Company announced a warrant exercise incentive program (the “Program”) whereby the Company amended the exercise prices of 253,966 warrants (the “Eligible Warrants”) from $50.40 per share to $11.44 per share if the holders of the Eligible Warrants exercised the Eligible Warrants before June 30, 2023 (the “Program Period”). In addition to the repricing, the Company offered, to each warrant holder who exercised the Eligible Warrants during the Program Period, the issuance of one additional common share purchase warrant for each warrant exercised during the Program Period (each, an “Incentive Warrant”). Each Incentive Warrant entitles the warrant holder to purchase one common share of the Company for a period of 5 years from the date of issuance, at a price of $18.00 per Share.

On June 30, 2023, the Company issued 68,353 common shares at a price of $11.44 per share from the exercise of the Eligible Warrants pursuant to the Program for gross proceeds of $781,953 (net proceeds of $645,330). In connection with the Program, the Company issued 68,353 Incentive Warrants. The Company also incurred $62,556 and issued 5,470 warrants as a finders’ fee to its investment bank. The finder’s warrants are on the same terms as the Incentive Warrants. The Incentive Warrants and finder’s warrants were valued at $449,005 and $35,919, respectively, using the Black-Scholes option pricing model (assuming a risk-free interest rate of 3.68%, an expected life of 5 years, annualized volatility of 128.81% and a dividend rate of 0%). The repricing of the Eligible Warrants is accounted for as a modification under ASC 815-40-35-14 through 18. The effect of the modification is $544,164, measured as the excess of the fair value of the repriced warrants over the fair value of the original warrants immediately before it was modified and the fair value of the incentive warrants issued as an additional inducement to exercise the warrants. The fair values were measured using the Black-Scholes option pricing model (assuming a risk-free interest rate of 4.21%, an expected life of 3.75 years, annualized volatility of 137.62% and a dividend rate of 0%). The Company recognized a deemed dividend of $543,234 for the fair value of the Incentive Warrants and the portion of inducement related to the equity-classified warrants. The effect of the repricing of the liability-classified warrants was $930 and was recorded in the statement of operations and comprehensive loss. The Company also incurred legal and other expenses of $74,066 in connection with the Program.

F-19

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

11. EQUITY (cont’d…)

Share-based payments

Stock options

The Company has a stock option plan (the “SOP”) in place under which it is authorized to grant options to executive officers and directors, employees and consultants. Pursuant to the SOP, the Company may issue aggregate stock options totaling up to 10% of the issued and outstanding common stock of the Company. Further, the SOP calls for the exercise price of each option to be equal to the market price of the Company’s stock as calculated on the date of grant. The options can be granted for a maximum term of 10 years and vest at the discretion of the Board of Directors at the time of grant.

Stock option transactions are summarized as follows:

	Number of options			Weighted Average Exercise Price
Balance, September 30, 2022		21,146		$	53.04
Cancelled		(833	)		42.62
Balance, September 30, 2023		20,313		$	54.23
Cancelled		(10,208	)		55.24
Balance, September 30, 2024		10,105		$	53.21
Exercisable at September 30, 2024		10,105		$	53.21

The aggregate intrinsic value of options outstanding and exercisable as of September 30, 2024 was $nil (September 30, 2023 - $nil).

The options outstanding as of September 30, 2024 have exercise prices in the range of $8.88 to $88.80 and a weighted average remaining contractual life of 5.6 years.

During the year ended September 30, 2024, the Company recognized $nil share-based payment expense. During the year ended September 30, 2023, the Company recognized share-based payment expense of $nil and $318, respectively, for the portion of stock options that vested during the year.

As September 30, 2024, the following stock options were outstanding:

Number of Options		Exercise Price		Issuance Date	Expiry Date
	3,230	$	88.88	December 4, 2017	December 4, 2027
	1,250	$	8.88	March 16, 2020	March 16, 2030
	5,625	$	42.62	October 6, 2021	October 6, 2031
	10,105

F-20

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

11. EQUITY (cont’d…)

Share-based payments (cont’d…)

Warrants

Warrant transactions are summarized as follows:

	Number of Warrants			Weighted Average Exercise Price
Balance, September 30, 2022		274,276		$	48.48
Exercised		(68,353	)		11.44
Granted		73,823			18.00
Balance, September 30, 2023		279,746		$	39.79
Granted		401,810			4.08
Cancelled		(500	)		4.08
Expired		(4,393	)		95.90
Balance, September 30, 2024		676,663		$	18.25

As September 30, 2024, the following warrants were outstanding:

Number of Warrants		Exercise Price		Issuance Date	Expiry Date
	149,447	$	50.40	March 29, 2022	March 29, 2027
	73,823	$	18.00	June 30, 2023	June 30, 2028
	147,000	$	4.08	April 16, 2024	April 16, 2029
				(Subsequently cancelled – Note 15)
	254,310	$	4.08	June 12, 2024	June 12, 2029
				(Subsequently cancelled – Note 15)
	52,083	$	35.52	September 30, 2021	September 30, 2031
	676,663

F-21

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

12. INCOME TAXES

	2024			2023
Loss before income taxes	$	(3,989,276	)	$	(3,939,961	)
Expected income tax recovery at statutory rates	$	(598,000	)	$	(591,000	)
Provincial income tax recovery		(373,000	)		(290,000	)
Effect of income taxes from US operations		(58,000	)		(100,000	)
Change in statutory, foreign tax, foreign exchange rates and other		(3,000	)		(18,000	)
Permanent differences – debt discount		116,000			-
Permanent differences – debt extinguishment		134,000			-
Permanent differences - Other		11,000			3,000
Adjustment to prior years provision versus statutory tax returns		3,000			(43,000	)
Change in valuation allowance		768,000			1,039,000
Deferred income tax recovery	$	-		$	-

Components of the Company’s pre-tax loss and income taxes are as follows:

	2024			2023
Loss for the year
Canada	$	(3,110,348	)	$	(2,418,491	)
US		(878,928	)		(1,521,470	)
	$	(3,989,276	)	$	(3,939,961	)
Expected income tax (recovery)
Canada	$	(589,000	)	$	(659,000	)
US		(177,000	)		(319,000	)
	$	(766,000	)	$	(978,000	)
Deferred income tax
Canada	$	589,000		$	659,000
US		177,000			319,000
	$	766,000		$	978,000
Deferred income tax recovery	$	-		$	-

The significant components of the Company’s deferred tax assets and liabilities are as follows:

	2024			2023
Tax loss carryforwards	$	3,037,000		$	2,313,000
Property and equipment		15,000			39,000
Financing fees		130,000			191,000
Accrued liabilities		129,000			-
		3,311,000			2,543,000
Deferred tax assets valuation allowance		(3,311,000	)		(2,543,000	)
Net deferred tax assets	$	-		$	-

The significant components of the Company’s temporary differences include unamortized financing fees and tax loss carryforwards. The valuation allowance reduces the deferred tax assets to amounts that are, in management’s assessment, more likely than not to be realized. This conclusion is primarily due to the Company’s history of cumulative losses and its expectation of continued losses in the foreseeable future. The Company had tax loss carryforwards of approximately $11,991,000 in Canada and the United States. For the years ended September 30, 2024 and 2023, the Canada tax loss carryforwards totaled $9,421,000 and $7,019,000, respectively, with expiration dates ranging from 2037 to 2043 and 2037 to 2042, respectively. The United States tax loss carryforwards for the years ended September 30, 2024 and 2023 totaled $2,569,000 and $2,367,000, respectively, and had no expiration dates, subject to 80% of taxable income. The United States tax loss carryforwards include $290,000 attributable to New Mexico state tax losses, with expiration dates ranging from 2037 to 2043.

13. SEGMENT INFORMATION

Operating segments

The Company operates in a single reportable segment – the acquisition, development and production of oil and gas properties in the United States.

F-22

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

14. CONTINGENCIES

The Company from time to time may be involved with disputes, claims and litigation related to the conduct of its business. The Company had $545,505 in claims from certain trade vendors for non-payment, of which $499,162 have been accrued as of September 30, 2024. The Company plans to continue engaging with these claimants faithfully and is working on potential settlements for all outstanding claims.

15. SUBSEQUENT EVENTS

i) On October 2, 2024, the Company granted stock options to directors and officers of the Company to purchase 65,000 common shares at an exercise price of $2.44 per share for a period of 10 years.

ii) On November 1, 2024, the Company closed the first tranche of a non-brokered private placement of convertible debenture units of the Company announced in September 2024 for gross proceeds of $4,276,389, of which $2,250,000 was received as subscriptions as of September 30, 2024, and $1,424,788 was issued in exchange for the outstanding debentures in the principal amount of $1,365,000 and accrued interest of $59,788. Each debenture unit consists of one convertible debenture (a “Debenture”) in the principal amount of $1,000 and 523 common share purchase warrants. Each warrant is exercisable for a period of five years from the date of issuance for one common share of the Company (a “Share”) at an exercise price of $1.91 per share. As a result, the Company issued convertible debentures with an aggregate principal amount of $4,276,389 and 2,236,551 Warrants. The Debentures are secured by the Company’s assets, mature one-year from the date of issuance, and bear simple interest at a rate of 10% per annum, payable on the maturity date or upon repayment of all or any portion of the Debenture. The Debentures are convertible into common shares of the Company at a conversion price of $1.91 per share. Interest is payable in cash or shares based on the same conversion price.

iii) In October 2024, the Company retired its previously outstanding debentures of $1,365,000 along with accrued interest of $59,788 in exchange for the new debenture units. The debenture holders also agreed to cancel a total of 401,310 warrants issued in connection with the debentures. This exchange was assessed as a debt extinguishment and a loss of $105,349 was recognized in October 2024.

iv) The Company’s Long Term Incentive Plan was approved by Board on October 2, 2024, which Long Term Incentive Plan was amended and such amended plan was approved by the Board on October 23, 2024 (as amended, the “Long Term Incentive Plan”) and was approved by shareholders at the Company’s Annual General Meeting of Shareholders on November 4, 2024. The Board approved the adoption of the Long-Term Incentive Plan to replace the Company’s 2017 Stock Option Plan and all awards previously issued under the 2017 Stock Option Plan will be deemed issued under the Long-Term Incentive Plan. The maximum aggregate number of Shares issuable in respect of all Incentive Securities granted or issued under the Company’s Security Based Compensation Plans, at any point, shall not exceed (twenty percent (20%) of the total number of issued and outstanding Shares.

F-23

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

16. SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED)

Supplemental unaudited information regarding Permex’s oil and gas activities is presented in this note. All of Permex’s reserves are located within the U.S.

Costs Incurred in Oil and Gas Producing Activities

	12 Months Ended		12 Months Ended
	September 30, 2024		September 30, 2023
Acquisition of proved properties	$	-	$	-
Acquisition of unproved properties		-		-
Development costs		3,227		2,019,639
Exploration costs		-		-
Total costs incurred	$	3,227	$	2,019,639

Results of Operations from Oil and Gas Producing Activities

	12 Months Ended			12 Months Ended
	September 30, 2024			September 30, 2023
Oil and gas revenues	$	116,033		$	688,827
Production costs		(196,428	)		(879,471	)
Exploration expenses		-			-
Depletion, depreciation and amortization		(40,580	)		(104,798	)
Impairment of oil and gas properties		-			-
Result of oil and gas producing operations before income taxes		(120,975	)		(295,442	)
Provision for income taxes		-			-
Results of oil and gas producing activities	$	(120,975	)	$	(295,442	)

F-24

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

16. SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED) (cont’d…)

Proved Reserves

The Company’s proved oil and natural gas reserves have been estimated by the certified independent engineering firm, MKM Engineering. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods when the estimates were made. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history; acquisitions of oil and natural gas properties; and changes in economic factors.

Our proved reserves are summarized in the table below:

	Oil (Barrels)			Natural Gas (Mcf)			BOE (Barrels)
Proved developed and undeveloped reserves:
September 30, 2022		6,237,070			3,001,170			6,737,265
Revisions		(3,588,541	)		(951,270	)		(3,747,086	)
Purchase of proved reserves		-			-			-
Sale reserves		-			-			-
Production		(11,729	)		(7,500	)		(12,979	)
September 30, 2023		2,636,800			2,042,400			2,977,200
Revisions		(939,436	)		(904,200	)		(1,090,136	)
Purchase of proved reserves		-			-			-
Sale reserves		-			-			-
Production		(1,964	)		-			(1,964	)
September 30, 2024		1,695,400			1,138,200			1,885,100
Proved developed reserves:
September 30, 2022		1,153,870			864,770			1,297,998
September 30, 2023		1,027,100			765,300			1,154,650
September 30, 2024		508,700			279,600			555,300
Proved undeveloped reserves:
September 30, 2022		5,083,200			2,136,400			5,439,267
September 30, 2023		1,609,700			1,277,100			1,822,550
September 30, 2024		1,186,700			858,600			1,329,800

F-25

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

16. SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED) (cont’d…)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of September 30, 2024 and 2023 in accordance with ASC 932, “Extractive Activities – Oil and Gas” which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.

Future cash inflows for the years ended September 30, 2024 and 2023 were estimated as specified by the SEC through calculation of an average price based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from October through September during each respective fiscal year. The resulting net cash flow are reduced to present value by applying a 10% discount factor.

	12 Months Ended
	September 30, 2024			September 30, 2023
Future cash inflows	$	134,081,000		$	211,828,000
Future production costs(1)		(31,752,000	)		(40,061,000	)
Future development costs		(17,496,000	)		(17,241,000	)
Future income tax expenses		(19,746,000	)		(39,262,000	)
Future net cash flows		65,087,000			115,264,000
10% annual discount for estimated timing of cash flows		(36,997,000	)		(60,184,000	)
Standardized measure of discounted future net cash flows at the end of the fiscal year	$	28,090,000		$	55,080,000

(1) Production costs include crude oil and natural gas operations expense, production ad valorem taxes, transportation costs and G&A expense supporting the Company’s crude oil and natural gas operations.

Average hydrocarbon prices are set forth in the table below.

	Average Price		Natural
	Crude Oil (Bbl)		Gas (Mcf)
Year ended September 30, 2022 (1)	$	91.72	$	5.79
Year ended September 30, 2023 (1)	$	78.54	$	3.42
Year ended September 30, 2024 (1)	$	78.64	$	2.21

(1) Average prices were based on 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from October through September during each respective fiscal year.

Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved crude oil and natural gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.

F-26

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

16. SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED) (cont’d…)

Sources of Changes in Discounted Future Net Cash Flows

Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves, as required by ASC 932, at fiscal year-end are set forth in the table below.

	12 Months Ended
	September 30, 2024			September 30, 2023
Standardized measure of discounted future net cash flows at the beginning of the year	$	55,080,000		$	144,729,000
Extensions, discoveries and improved recovery, less related costs		-			-
Sales of minerals in place		-			-
Purchase of minerals in place		-			-
Revisions of previous quantity estimates		(25,208,000	)		(103,529,000	)
Net changes in prices and production costs		(4,323,000	)		(52,170,000	)
Accretion of discount		7,400,000			19,862,000
Sales of oil produced, net of production costs		80,000			191,000
Changes in future development costs		(107,000	)		27,173,000
Changes in timing of future production		(15,706,000	)		(16,145,000	)
Net changes in income taxes		10,874,000			34,969,000
Standardized measure of discounted future net cash flows at the end of the year	$	28,090,000		$	55,080,000

F-27

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

On October 31, 2022, Davidson & Company LLP resigned as the Company’s independent registered public accounting firm effective October 31, 2022. On October 31, 2022, through and with the approval of its Audit Committee, the Company appointed Marcum LLP as its independent registered public accounting firm.

Davidson audited the Company’s consolidated financial statements as of and for the fiscal years ended September 30, 2021 and 2020. The report of Davidson on the financial statements of the Company for the fiscal years ended September 30, 2021 and 2020, did not contain any adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principles.

During the Company’s fiscal years ended September 30, 2021 and 2020, and through the interim period ended October 31, 2022, there were no disagreements between the Company and Davidson on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Davidson, would have caused Davidson to make reference to the subject matter of the disagreements in connection with its audit reports on the Company’s financial statements. During the Company’s two most recent fiscal years ended September 30, 2021 and 2020, and the interim period ended October 31, 2022, Davidson did not advise the Company of any reportable events specified in Item 304(a)(1)(v) of Regulation S-K with respect to the Company.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We carried out an evaluation as of the end of the period covered by this Annual Report on Form 10-K, under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-5(e) under the Exchange Act) pursuant to paragraph (b) of Rules 13a-15 and 15d-5 under the Exchange Act. Based on that review, our Chief Executive Officer and our Chief Financial Officer have concluded that, as of the end of the period covered by this Annual Report on Form 10-K, our disclosure controls and procedures are not effective to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

The following control deficiencies constitute material weaknesses in internal control over financial reporting:

● Insufficient resources resulting in inadequate segregation of duties in certain accounting functions, the processing and approval of transactions, due to the size of the accounting department.

● Ineffective controls over inputs used in the valuation of the Asset Retirement Obligation

● Ineffective controls over the depletion calculation and the preparation of the oil and gas reserve report

● Ineffective controls on the accounting and the valuation of complex financial instruments

● Ineffective review of the financial statements due to the limited financial and reporting resources

● Ineffective information technology general controls in the areas of user access and program change-management over certain information technology systems that support the Company’s financial reporting processes.”

● Ineffective controls over the evaluation of the impact of debt amendments.

Internal Control over Financial Reporting

Management’s Report on Internal Control over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of the Company’s financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act and includes those policies and procedures that: (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Company’s assets; (b) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that the Company’s receipts and expenditures are being made only in accordance with authorizations of the Company’s management and directors; and (c) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s financial statements. All internal controls, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2024. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (2013). Based on this assessment, management has concluded that, as of September 30, 2024, our internal control over financial reporting was not effective, due to the material weaknesses in our internal control over financial reporting.

Changes in Internal Control over Financial Reporting

There have not been any changes in the Company’s internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the Company’s fourth fiscal quarter that our certifying officers concluded materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

During the three months ended September 30, 2024, no director or officer (as defined in Rule 16a-1(f) of the Exchange Act) of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “Non-Rule 10b5-1 trading arrangement” as each term is defined in Item 408(a) of Regulation S-K.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors and Executive Officers

Set forth below is the name and position and a brief account of the business experience of each of our directors and executive officers as of January 14, 2025. Each of the directors listed below was elected to our Board of Directors to serve until our next annual meeting of shareholders or until such director’s successor is elected and qualified.

Name	Age	Position
Bradley Taillon	34	Chief Executive Officer, President and Director
Gregory Montgomery	55	Chief Financial Officer
Richard Little	52	Director
Kevin Nanke	59	Director
BaShara (Bo) Boyd	53	Director

Biographical Information

Bradley Taillon

Bradley Taillon was appointed as the Company’s President and Chief Executive Officer on April 29, 2024 and a director on the Company’s Board of Directors on June 12, 2024. Mr. Taillon has extensive experience in the junior oil & gas industry. Mr. Taillon served as the Company’s Vice President Finance from March 15, 2024 to April 28, 2024. He served as Vice President of Finance and Investor Relations from April 2022 to December 2023 at Ruckus Energy, LLC, a private Permian Basin focused junior oil & gas company, where he recently led that company’s M&A activity. Previous to serving in this position at Ruckus Energy, Mr. Taillon served as Business Development Manager and Senior Landman at Ruckus Energy from November 2020 to April 2022 and November 2019 to October 2020, respectively. Mr. Taillon also served from March 2017 to May 2018 as an A&D Analyst at Lilis Energy, Inc. (NYSE: LLEX), a publicly listed junior oil & gas company also focused on the Permian Basin, where he helped contribute to Lilis’ success of more than doubling its acreage position in the Delaware Basin. Mr. Taillon holds a Bachelor of Business Administration in International Economics and an MBA in International Finance from Fort Hays State University. He is also a Registered Professional Landman with the AAPL.

Gregory Montgomery

Gregory Montgomery has served as Chief Financial Officer of the Company since May 2022 and served as a member of the Company’s Board of Directors from March 2020 until April 2023. Since June 2021, Mr. Montgomery has served as Vice President, Project Management Office – Private Equity Energy Management of Priority Power Management, LLC. In addition from October 2018 until June 2021, he served as Partner of Vine Advisors, from October 2017 until October 2018, he served as Chief Financial Officer of Oiltanking North America and from March 2013 until October 2017, he served as Chief Financial Officer of Semarus Energy, LLC. Mr. Montgomery also served as Chief Financial Officer for Lion Copolymer, Coast Energy and Laser Midstream, and was a Director of Strategic Planning for Enbridge Energy Partners (EEP: NYSE) and Compliance Officer for Pennzoil Company (PZL: NYSE). Mr. Montgomery is a CPA and member of the Texas Society of CPA’s and American Institute of Certified Public Accountants. Mr. Montgomery holds a Bachelor of Business Administration from the University of Houston – Bauer College of Business.

Richard Little

Richard Little has served as a member of the Company’s Board of Directors since August 2024. Mr. Little is the current Chief Executive Officer of Fury Resources, Inc., privately held independent energy company, a position he has held since December 2023. Before Fury Resources, Mr. Little was the Chief Executive Officer of Battalion Oil Company (NYSE: BATL) and Halcon Resources Corporation from June 2019 to April 2023. Prior to Battalion Oil and Halcon Resources, Mr. Little served as Chief Executive Officer of Ajax Resources LLC from January 2018 to October 2018. Mr. Little was also Vice-President, Southern US Division of EP Energy. Mr. Little holds a Petroleum Engineering degree from Texas A&M, is a licensed engineer (inactive), and is engaged with industry organizations like the Society of Petroleum Engineers, American Petroleum Institute, and Independent Petroleum Association of America.

Kevin Nanke

Kevin Nanke has served as a member of the Company’s Board of Directors since August 2024. Mr. Nanke has held diverse finance and accounting executive positions in the oil and gas industry for more than 30 years. Mr. Nanke has served as the President and Manager of Nanke Energy, LLC, an oil and gas company with a focus on the Denver-Julesburg (DJ) Basin, since March 2017 and has served as President of KN Consulting from August 2012. Previously, Mr. Nanke served as Chief Financial Officer of Lilis Energy, Inc. (NYSE: LLEX) from March 2015 to January 2017 and Chief Financial Officer and Treasurer of Delta Petroleum Company from 1995 to 2012. Prior to joining Delta Petroleum, Mr. Nanke was employed by KPMG LLP, a leading global audit, tax and advisory firm. Mr. Nanke holds a Bachelor of Arts, Accounting from the University of Northern Iowa and is a Certified Public Accounting (inactive).

BaShara (Bo) Boyd

BaShara (Bo) Boyd has been a partner at Walker Eisenbraun, LLC, a corporate law firm located in Houston, Texas, since January 2019, and previously served as Senior Counsel from June 2017 to December 2018. Ms. Boyd’s practice covers an array of complex corporate, transactional, and governance matters, predominantly for clients in the energy sector. In Ms. Boyd’s twenty-five years of practice, she has excelled as a corporate and securities lawyer with a national law firm, and as general counsel, senior vice president, and corporate secretary of the then largest publicly traded, independent oil and gas producer in the Gulf of Mexico, where she had sole responsibility for managing all of the company’s legal affairs. Ms. Boyd is experienced managing A&D transactions, a full range of commercial energy transactions, health, safety and environmental matters, corporate governance, securities and exchange compliance, executive compensation and employment matters, insurance and risk mitigation, investor relations, internal investigation and audit processes, litigation discovery practices and regulatory compliance at local, state and national levels. Ms. Boyd graduated from The University of Texas at Austin and earned her J.D. from the University of Houston Law Center, magna cum laude.

Family Relationships

There are no family relationships among any of our executive officers or directors.

Involvement in Certain Legal Proceedings

We are not aware of any of our directors or officers being involved in any legal proceedings in the past ten years relating to any matters in bankruptcy, insolvency, criminal proceedings (other than traffic and other minor offenses), or being subject to any of the items set forth under Item 401(f) of Regulation S-K under the Securities Act.

44

Arrangements between Officers and Directors

Except as set forth herein, to our knowledge, there is no arrangement or understanding between any of our officers or directors and any other person pursuant to which the officer or director was selected to serve as an officer or director.

Independence

We have determined Richard Little, Kevin Nanke, and BaShara (Bo) Boyd, to be “independent” directors within the meaning of the listing standards of the Nasdaq Capital Market. Bradley Taillon is not independent since he is the current President and CEO of the Company. In making our independence determinations, we have considered all relationships between any of the directors and the Company.

Committees of our Board of Directors

Our Board of Directors has a separately designated standing audit committee (the “Audit Committee”) and compensation committee (the “Compensation Committee”).

Compensation Committee

Our Compensation Committee currently consists of three board members, Richard Little, Kevin Nanke, and BaShara (Bo) Boyd. Our board of directors has affirmatively determined that each of Mr. Little, Mr. Nanke, and Ms. Boyd satisfies the “independence” requirements of the SEC and Nasdaq Capital Market Company Guide. Our Board has adopted a Compensation Committee Charter specifying (i) the scope of the Compensation Committee’s responsibilities, and how it carries out those responsibilities, including structure, processes and membership requirements; (ii) the Compensation Committee’s responsibility for determining, or recommending to the Board for determination, the compensation of the chief executive officer and all other executive officers of the Company; and (iii) that the Company’s chief executive officer may not be present during voting or deliberations on his or her compensation.

Audit Committee

Our Audit Committee currently consists of three board members, Richard Little, Kevin Nanke, and Bashara (Bo) Boyd. Our board of directors has affirmatively determined that each of Mr. Little, Mr. Nanke, and Ms. Boyd satisfies the “independence” requirements of the SEC and Nasdaq Capital Market Company Guide. The Audit Committee will meet at least two times per year. Each member of the Audit Committee is financially literate, and in addition, our Board of Directors has determined that Kevin Nanke qualifies as an “audit committee financial expert,” as defined in applicable SEC regulations.

Our Audit Committee is responsible for overseeing our financial reporting process on behalf of the Board, including overseeing the work of the independent auditors who report directly to the Audit Committee. The specific responsibilities of our Audit Committee, among others, include:

● evaluating the performance and assessing the qualifications of the independent directors and recommending to the Board and the shareholders the appointment of our external auditor;

● determining and approving the engagement of and compensation for audit and non-audit services of our external auditor;

● reviewing our financial statements and management’s discussion and analysis of financial condition and results of operations and recommending to our Board of Directors whether or not such financial statements and management’s discussion and analysis of financial condition and results of operations should be approved by our Board of Directors;

● conferring with our external auditor and with management regarding the scope, adequacy and effectiveness of internal financial reporting controls;

● establishing procedures for the receipt, retention and treatment of complaints received by us regarding our accounting controls, internal accounting controls or auditing matters and the confidential and anonymous submission by employees of concerns regarding questionable accounting and auditing matters; and

● reviewing and discussing with management and the independent auditor, as appropriate, our guidelines and policies with respect to risk assessment and risk management, including major financial risk exposure and investment and hedging policies and the steps taken by management to monitor and control our exposure to such risks.

Nominating Committee Functions

Our Board serves in place of a nominating and corporate governance committee, to nominate members to our Board of Directors. The functions of a nominating committee are performed exclusively by the independent directors on the Board, meeting separately, and determinations are made by a majority of such independent directors. In lieu of a charter for the nominating committee functions, our Board has adopted resolutions addressing the nominations process and certain other matters related to corporate governance.

45

Committee Charters and Other Corporate Governance Matters

Audit and Compensation Committee Charters

Each of the Audit Committee and Compensation Committee operates under a written charter setting forth the functions and responsibilities of the committee, which is reviewed by the committee on a periodic basis, and by the Board of Directors as appropriate.

Code of Business Conduct and Ethics

We have adopted a written Code of Business Conduct and Ethics which addresses issues including, but not limited to: (i) conflicts of interest; (ii) compliance with laws, rules, and regulations; (iii) protection and proper use of corporate opportunities; (iv) protection and proper use of corporate assets; (v)confidentiality of corporate information; (vi) fair dealing with securityholders, customers, competitors, and employees; and (vii) accuracy of business records. The Code of Business Conduct and Ethics applies to all of our directors, officers and employees. Any change or waivers from the provisions of the Code of Business Conduct and Ethics for our executive officers or directors will be made only after approval by the Board of Directors and will be promptly disclosed.

Insider Trading Policy

As of the date of this report, the Company has not adopted an Insider Trading Policy. We anticipate that the Insider Trading Policy will be adopted in the near future. The absence of such a policy is not reflective of disregard for the principles of fair and ethical trading practices. The Company is keenly aware of the importance of establishing clear guidelines to prevent insider trading and to uphold the Company’s reputation for integrity and ethical conduct.

Policies And Practices for Granting Certain Equity Awards

The Company’s policies and practices regarding the granting of equity awards are carefully designed to ensure compliance with applicable securities laws and to maintain the integrity of our executive compensation program. The Compensation Committee of the Board is responsible for determining the long-term incentive component of executive compensation.

The timing of equity award grants is determined with consideration to a variety of factors, including but not limited to, the achievement of pre-established performance targets, market conditions, and internal milestones. The Company does not follow a predetermined schedule for the granting of equity awards; instead, each grant is considered on a case-by-case basis to align with the Company’s strategic objectives and to ensure the competitiveness of our compensation packages.

In determining the timing and terms of an equity award, the Board or Compensation Committee may consider material nonpublic information to ensure that such grants are made in compliance with applicable laws and regulations. The Board or Compensation Committee’s procedures to prevent the improper use of material nonpublic information in connection with the granting of equity awards include oversight by legal counsel and, where appropriate, delaying the grant of equity awards until the public disclosure of such material nonpublic information.

The Company is committed to maintaining transparency in its executive compensation practices and to making equity awards in a manner that is not influenced by the timing of the disclosure of material nonpublic information for the purpose of affecting the value of executive compensation. The Company regularly reviews its policies and practices related to equity awards to ensure they meet the evolving standards of corporate governance and continue to serve the best interests of the Company and its stockholders.

Director Compensation

We have no formal policy concerning director compensation; however, options may be granted to directors as compensation for services on the Board, at the discretion of our Board. Prior to September 30, 2024, we have not paid any cash or equity-based compensation to our directors for service on the Board of Directors. However, in October 2024, we issued options to purchase an aggregate of 60,000 shares of common stock to our directors for their service on the Board of Directors and may continue to do so in the future.

The following table presents the total compensation for each person who served as a member of our Board of Directors (other than Bradley Taillon, our current Chief Executive Officer and Mehran Ehsan, our former Chief Executive Officer, each of whose compensation is summarized below under “Summary Compensation Table”) and received compensation for such service on our Board of Directors during the fiscal year ended September 30, 2024. Mehran Ehsan resigned from the Board on June 12, 2024.

Name

Fees earned or paid in cash ($)

Stock Awards ($)

Option Awards ($)

Non-Equity Incentive Plan Compensation ($)

Nonqualified deferred compensation earnings ($)

All Other Compensation ($)

Total ($)

Richard Little

—

—

—

—

—

—

—

Kevin Nanke

—

—

—

—

—

—

—

Douglas Charles Urch (1)

—

—

—

—

—

—

—

John James Lendrum (2)

—

—

—

—

—

—

—

James Perry Bryan (3)

—

—

—

—

—

—

—

Barry Whelan (4)

—

—

—

—

—

—

—

Melissa Folz (5)

—

—

—

—

—

—

—

(1) Douglas Charles Urch resigned from the Board on June 20, 2024.

(2) John James Lendrum resigned from the Board on June 20, 2024.

(3) James Perry Bryan resigned from the Board on June 12, 2024.

(4) Barry Whelan also served as our Chief Operating Officer. Barry Whelan resigned from the Board on June 12, 2024.

(5) Melissa Folz resigned from the Board on June 12, 2024.

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ITEM 11. EXECUTIVE COMPENSATION

For the purposes hereof, a named executive officer (“NEO”) of the Company means the Company’s current Chief Executive Officer, Bradley Taillon (since April 29, 2024) and the Company’s former Chief Executive Officer, Mehran Ehsan (until April 29, 2024), as no other executive officer of the Company received total compensation in 2024 in excess of $100,000, and thus disclosure is not required for any other person.

Summary Compensation Table

The following table sets forth, for the years ended September 30, 2024 and 2023, all compensation paid or accrued by the Company, to or on behalf of the NEO:

Name and Principal Position	Fiscal Years Ended 09/30		Salary ($)		Bonus ($)		Stock Awards ($)		Option Awards ($)		Non-Equity Incentive Plan Compensation ($)		Non- Qualified Deferred Compensation Earnings ($)		All Other Compensation ($)			Total ($)
Bradley Taillon		2024		122,312		50,000		—		—		—		—		—			172,312
President, CEO and Director (1)		2023		N/A		N/A		N/A		N/A		N/A		N/A		N/A			N/A
Mehran Ehsan		2024		229,167		—		—		—		—		—		180,155	(3)		409,322
Former President, CEO and Director (2)		2023		250,000		—		—		—		—		—		—			250,000

(1) Bradley Taillon was appointed as President and Chief Executive Officer of the Company effective April 29, 2024 and as a director on June 12, 2024. From March 15, 2024 to April 28, 2024, Mr. Taillon served as the Company’s Vice President Finance. For Mr. Taillon’s 2024 salary, $104,167 was earned by Mr. Taillon in his role as the Company’s President and Chief Executive Officer and $18,145 was earned by Mr. Taillon in his role as the Company’s Vice President Finance. Mr. Taillon received a one-time cash bonus payment of $50,000 as a signing bonus under his employment agreement for his role as the Company’s President and Chief Executive Officer.

(2) Mehran Ehsan resigned as President and Chief Executive Officer of the Company on April 29, 2024, and from the Board on June 12, 2024. From April 29, 2024 through August 30, 2024, Mehran Ehsan served as Vice President of Business Development. For his 2024 salary, $145,834 of salary was earned by Mr. Ehsan in his role as President and Chief Executive Officer and $83,333 of salary was earned by Mr. Ehsan in his role as Vice President of Business Development

(3) Represents amount paid under Mr. Ehsan’s separation agreement with Company of which (i) $35,155 which is the fair market value of the Jeep Gladiator transferred to Mr. Ehsan, (ii) $100,000 is a lump sum payment paid on October 31, 2024 and (iii) $45,000 is the value of six months of continued payments to be Mr. Ehsan (with the first payment of $7,500 paid prior to September 30, 2024), in each case pursuant to Mr. Ehsan’s separation agreement with the Company.

Outstanding Equity Awards at Fiscal Year-End

The following table provides information regarding option and restricted stock unit awards held by our NEO’s that were outstanding as of September 30, 2024.

	Option Awards											Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) (Exercisable)			Number of Securities Underlying Unexercised Options (#) (Unexercisable)		Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)		Option Exercise Price ($)		Option Expiration Date		Number of Shares or Units of Stock That Have Not Vested (#)		Market Value of Shares or Units of Stock That Have Not Vested (#)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that Have Not Vested (#)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights that Have Not Vested ($)
Bradley Taillon President, CEO and Director		—			—		—	$	—		—		—		—		—		—
Mehran Ehsan		2,813	(1)		—		—	$	90		12/4/2027		—		—		—		—
Former President, CEO and Director		3,125	(2)		—		—	$	43.20		10/6/2031		—		—		—		—

(1) Stock options granted to Mehran Ehsan in December 2017 vested immediately upon grant.

(2) Stock options granted to Mehran Ehsan in October 2021 vested immediately upon grant.

47

Stock Incentive Plan

Long Term Incentive Plan

The Company’s Long Term Incentive Plan was originally approved by Board on October 2, 2024, and amended by the Board on October 23, 2024 (as amended, the “Long Term Incentive Plan”) and was approved by shareholders at the Company’s Annual General Meeting of Shareholders on November 4, 2024. The Long Term Incentive Plan was adopted to replace the Company’s 2017 Stock Option Plan and all awards previously issued under the 2017 Stock Option Plan will be deemed issued under the Long Term Incentive Plan. The purpose of the Long Term Incentive Plan is to promote the long-term success of the Company and the creation of shareholder value by: (a) encouraging the attraction and retention of eligible persons under the Long Term Incentive Plan; (b) encouraging such eligible persons to focus on critical long-term objectives; and (c) promoting greater alignment of the interests of such eligible persons with the interests of the Company, in each case as applicable to the type of eligible person to whom an award under the Long Term Incentive Plan is granted.

The maximum aggregate number of the Company’s common shares issuable pursuant to awards granted under the Long Term Incentive Plan shall not exceed twenty percent (20%) of the total number of issued and outstanding common shares of the Company on a non-diluted basis at such point in time, provided no more than 110,300 may be issued to U.S. taxpayers in connection with exercise of incentive stock options.

The Long Term Incentive Plan is administered by the Board, which has authority to interpret and construe any provision of this Long Term Incentive Plan and to adopt, amend and rescind such rules and regulations for administering this Long Term Incentive Plan as the Board may deems necessary in order to comply with the requirements of this Long Term Incentive Plan. The Board may delegate its powers under the Long Term Incentive Plan to the Compensation Committee or such other committee of the Board, as the Board determines.

Any of the Company’s common shares related to awards granted under the Long Term Incentive Plan which have been settled in cash, cancelled, surrendered, forfeited, expired or otherwise terminated without the issuance of such common shares shall be available again for granting awards under the Long Term Incentive Plan.

Subject to the provisions of the Long Term Incentive Plan (including, without limitation, restrictions on grants to investor relations service providers) and such other terms and conditions as the Board may prescribe, the Board may, from time to time, grant awards of restricted stock units, performance stock units, deferred stock units and stock options to all categories of eligible persons, except that eligible charitable organizations shall only be entitled to receive stock options.

Employment, Consulting and Management Agreements

Other than the executive employment agreement between the Company and Bradley Taillon, the material terms of which are set forth below, the Company does not have any compensation agreements or arrangements that the Company or any of its subsidiaries have entered into with respect to services provided by a NEO, a director or any other party in the event such services provided are typically provided by a director or NEO (collectively, “Compensation Arrangements”). Previously, the Company had an employment agreement with Mehran Ehsan, its former Chief Executive Officer, which agreement terminated upon Mr. Ehsan’s termination from the Company on August 30, 2024.

Employment Agreement with Bradley Taillon

Pursuant to an employment agreement between the Company and Bradley Taillon dated April 29, 2024, the Company employs Mr. Taillon to serve as the President and Chief Executive Officer of the Company and to perform such duties and have such authority as may from time to time be assigned by the Board. As compensation for the performance of such duties, Mr. Taillon is to receive an annual base salary of $250,000. Mr. Taillon is also eligible for cash bonuses and grants of stock options under the Company’s stock incentive plans, in the sole discretion of the Board, as well as group health, medical and disability insurance benefits and any other fringe benefit programs that the Company maintains from time to time for the benefit of its employees. In addition to any annual bonus, Mr. Taillon is eligible for additional performance bonuses ranging from $50,000 to $750,000 upon the closing of a qualified financing with proceeds to the Company of $1 million or greater.

The Company may immediately terminate Mr. Taillon’s employment at any time for cause, by written notice. The Company may terminate the Mr. Taillon’s employment at any time without cause by providing him with notice in writing and compensation in lieu of notice as follows:

● payment of all outstanding and accrued base salary and vacation pay, earned and owing up to the last day of the active employment, and reimbursement for all proper expenses incurred by him in connection with the Company’s business prior to the last day of active employment;

● payment of an amount equal to 24 months base salary;

● payment of an amount in lieu of his performance bonus equal to 50% of base salary; and

● continuation of his benefit coverage for a period of six months, or alternatively, if it is unable to continue Mr. Taillon’s participation in one or more of the Company’s benefit plans, the Company shall pay him an amount equal to the premium cost or contributions the Company would otherwise have made in respect of his participation in the relevant plan(s) for six months.

Mr. Taillon is required to give the Company not less than two weeks’ notice in the event of his resignation. Upon receipt of his notice of resignation, or at any time thereafter, the Company has the right to elect to pay, in lieu of such notice period, Mr. Taillon’s salary for the remainder of the notice period and a reasonable amount in lieu of the benefits for that period. If the Company elects for payment in lieu of notice, the Mr. Taillon’s employment shall terminate immediately upon such payment.

In the event of death, Mr. Taillon’s employment shall be deemed to have terminated on the date thereof and the Company shall pay his estate the amounts specified above in respect of termination without cause.

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Employment Agreement with Mehran Ehsan

Pursuant to an employment agreement between the Company and Mehran Ehsan dated May 1, 2022, the Company employed Mr. Ehsan to serve as the President and Chief Executive Officer of the Company and to perform such duties and have such authority as may from time to time be assigned by the Board. As compensation for the performance of such duties, the Company paid Mr. Ehsan an annual base salary of $250,000. Mr. Ehsan was also eligible for cash bonuses and grants of stock options under the Company’s stock incentive plans, in the sole discretion of the Board, as well as group health, medical and disability insurance benefits and any other fringe benefit programs that the Company maintains from time to time for the benefit of its employees.

Mr. Ehsan resigned as President and Chief Executive Officer of the Company on April 29, 2024 and on May 15, 2024, the Company amended Mr. Ehsan’s employment agreement to change his role to Vice President of Business Development, effective April 29, 2024. All other terms and conditions of Mr. Ehsan’s employment agreement remained the same, until the agreement was terminated in connection with Mr. Ehsan’s departure from the Company on August 30, 2024.

Separation Agreement with Mehran Ehsan

On August 30, 2024, we entered into a separation agreement with Mehran Ehsan. The terms of the separation agreement provides that Mr. Ehsan is entitled to receive: i) a lump sum payment of $100,000 payable by October 31, 2024 (paid); ii) six equal monthly payments of $7,500 starting October 1, 2024 ($22,500 paid); and iii) the transfer of ownership of a Company vehicle with a fair value of $35,155 (completed). In addition, the separation agreement provides that Mr. Ehsan shall make himself reasonably available to us for a period of 12 months following the effective date of the separation agreement and to respond promptly for any requests for information regarding the Company and to fully cooperate in any litigation. Further, under the terms of the separation agreement, Mr. Ehsan agreed to a one-year non-compete clause.

Other than pursuant to the Mr. Taillon’s employment agreement described above, the Company has not granted any termination or change of control benefits with respect to any compensation arrangement and there are no compensatory plans or arrangements with respect to any NEO or director resulting from the resignation, retirement or any other termination of any NEO or director or from a change of any NEO’s or director’s responsibilities following a change of control. In case of termination of NEOs, other than the CEO, common law and statutory law applies.

The table below sets forth information with respect to each NEO currently employed by the Company in order to assist the reader in determining the potential payment to each such NEO in the event of the termination of such NEO’s employment by the Company other than for cause or in the event of a change of control. The estimated payments have been calculated on the basis of employment agreements as they exist at the date of this Annual Report and assuming that they were in effect on September 30, 2024.

Name	Estimated Payment Assuming Termination Without Cause on September 30, 2024 ($)		Estimated Payment Assuming a Change of Control on September 30, 2024 ($)
Bradley Taillon	$	625,000		—

The estimated payments assuming a change of control on September 30, 2024 are based on the assumption that the NEOs are terminated without cause or elect to terminate the agreements.

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Oversight and Description of Director and Name Executive Officer Compensation

Elements of Compensation

Compensation to be awarded or paid to the Company’s directors and/or executive officers, including NEOs consist primarily of management fees, stock options and bonuses. Payments may be made from time to time to executive officers, including NEOs, or companies they control for the provision of consulting or management services. Such services are paid for by the Company at competitive industry rates for work of a similar nature done by reputable arm’s length services providers.

The Board will from time to time determine the stock option grants to be made pursuant to the Option Plan. It is also anticipated that the Board may award bonuses, in its sole discretion, to executive officers (including NEOs) from time to time.

The most significant components of the Company’s executive compensation plan are base salary and an annual incentive bonus. These components are based upon:

● achievement of specific corporate or segment performance targets;

● a performance evaluation process, taking into consideration comparative levels of compensation with comparable entities in the Company’s industry;

● alignment of the compensation level of each individual to that individual’s level of responsibility;

● the individual’s performance, competencies, skills and achievements;

● alignment with corporate strategy; and

● contributions to corporate or segment performance.

Base Salary

The base salary review of any NEO will take into consideration the current competitive market conditions, experience, proven or expected performance, and the particular skills of the NEO. Base salary is not expected to be evaluated against a formal “peer group”.

Performance-Based Cash Bonuses

Cash bonuses are not a normal part of the Company’s executive compensation. However, the Company may elect to utilize such incentives where the role-related context and competitive environment suggest that such a compensation modality is appropriate. When and if utilized, the amount of cash bonus compensation will normally be paid on the basis of timely achievement of specific pre-agreed milestones. Each milestone will be selected based upon consideration of its impact on shareholder value creation and the ability of the Company to achieve the milestone during a specific interval. The amount of bonus compensation will be determined based upon achievement of the milestone, its importance to the Company’s near and long term goals at the time such bonus is being considered, the bonus compensation awarded to similarly situated executives in similarly situated companies or any other factors the Company may consider appropriate at the time such performance-based bonuses are decided upon.

Stock Options and Other Incentive Awards

Stock options and other incentive awards granted under the Long Term Incentive Plan are also an important component of aligning the objectives of the Company’s employees with those of shareholders. The Company expects to provide significant option positions to senior employees and lesser amounts to lower-level employees.

Notwithstanding the above, the Company is still in the development stage and has an informal compensation program and strategy. The management team is committed to developing the operations of the Company and will establish a formal compensation program for directors and executive officers once it begins generating revenues sufficient to sustain operations. The Board is responsible for determining, by way of discussions at Board meetings, the ultimate compensation to be paid to the executive officers of the Company. The Company does not have a formal compensation program with set benchmarks; however, the performance of each executive will be considered along with the Company’s ability to pay compensation and its results of operation for the period.

The Company relies solely on its Board to determine the executive compensation that is to be paid to NEOs and directors without any formal objectives, criteria, or analysis.

Pension Disclosure

The Company does not currently provide any pension plan or any other kind of welfare benefits for executive officers, directors, or employees.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security ownership of certain beneficial owners and management

The following table sets forth certain information regarding the beneficial ownership of our capital stock outstanding as of January 14, 2025 by:

● each person, or group of affiliated persons, known by us to beneficially own more than 5% of our common shares;

● each of our directors;

● each of our named executive officers; and

● all of our directors and named executive officers as a group.

The percentage ownership information is based on 551,503 common shares outstanding as of January 14, 2025. The number of shares owned are those beneficially owned, as determined under the rules of the SEC. Under these rules, beneficial ownership includes any common shares as to which a person has sole or shared voting power or investment power and any common shares that the person has the right to acquire within 60 days of January 14, 2025 through the exercise of any option, warrant or right, through conversion of any security or pursuant to the automatic termination of a power of attorney or revocation of a trust, discretionary account or similar arrangement. These shares are deemed to be outstanding and beneficially owned by the person holding such option, warrants or other derivative securities for the purpose of computing the percentage ownership of that person, but they are not treated as outstanding for the purpose of computing the percentage ownership of any other person. Unless otherwise indicated, the persons or entities identified in this table have sole voting and investment power with respect to all common shares shown as beneficially owned by them, subject to applicable community property laws.

Except as otherwise noted below, the address for each person or entity listed in the table is c/o Permex Petroleum Corporation, 1700 Post Oak Boulevard, 2 Blvd Place Suite 600, Houston Texas, 77056.

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	Number of Shares Beneficially Owned			Percentage of Common Shares Beneficially Owned
Directors and Named Executive Officers:
Bradley Taillon		52,050	(1)		8.62	%
Richard Little		20,000	(2)		3.50	%
Kevin Nanke		15,000	(3)		2.65	%
BaShara (Bo) Boyd		-			-	%
Mehran Ehsan (4)		19,092	(4)		3.46	%
Gregory Montgomery		1,875	(5)		0.34	%
All Current Executive Officers and Directors as a Group (5 persons)		88,925			13.89	%
5% or Greater Shareholders:
Kent Lindemuth		1,623,037	(6)		74.64	%
Jeffrey E. Eberwein		420,036	(7)		43.23	%
John Peckham		54,101	(8)		8.93	%
Justin Law		54,101	(9)		8.93	%
John James Lendrum		82,813	(10)		14.30	%
James Perry Bryan		73,437	(11)		12.75	%
Ramnarain Jaigobind (12)		133,235	(13)		21.06	%

(1) Represents 25,000 common shares issuable upon exercise of options with an exercise price of $2.44 and 27,050 shares issuable upon conversion of $51,666 of 10% senior secured convertible notes (including accrued interest as of January 14, 2025 and interest accruing for 60-days after January 14, 2025) at a conversion price of $1.91. Mr. Taillon disclaims beneficial ownership of warrants to purchase up to 26,150 common shares as the holder of the warrants may not exercise the warrants to the extent such exercise would cause such holder, together with its affiliates and attribution parties, to beneficially own a number of common shares which would exceed 4.99% (or, at the election of the holder, 9.99%) of our then outstanding common shares following such exercise.

(2) Represents 20,000 common shares issuable upon exercise of options with an exercise price of $2.44.

(3) Represents 15,000 common shares issuable upon exercise of options with an exercise price of $2.44.

(4) Represents (i) 8,571 common shares owned by Mehran Ehsan, (ii) 10,417 common shares owned by N.A. Energy Resources Corporation, and (iii) 104 common shares owned by Mehran Ehsan’s spouse. Mehran Ehsan is the President and Chief Executive Officer of N.A. Energy Resources Corporation and in such capacity has the right to vote and dispose of the securities held by such entity.

(5) Represents 1,250 common shares issuable upon exercise of options with an exercise price of $12.00 CAD and 625 common shares issuable upon exercise of options with an exercise price of $57.60 CAD.

(6) Represents 1,623,037 common shares issuable upon conversion of $3,100,000 of 10% senior secured convertible notes (including accrued interest as of January 14, 2025 and interest accruing for 60-days after January 14, 2025) at a conversion price of $1.91. The address is 4350 NW Green Hills, Topeka, KS 66618. Mr. Lindemuth disclaims beneficial ownership of warrants to purchase up to 1,569,000 common shares as the holder of the warrants may not exercise the warrants to the extent such exercise would cause such holder, together with its affiliates and attribution parties, to beneficially own a number of common shares which would exceed 4.99% (or, at the election of the holder, 9.99%) of our then outstanding common shares following such exercise.

(7) Represents 420,036 common shares issuable upon conversion of $802,268 of 10% senior secured convertible notes (including accrued interest as of January 14, 2025 and interest accruing for 60-days after January 14, 2025) at a conversion price of $1.91. The address is 4 Lockwood Avenue, Old Greenwich, CT 06870. Mr. Eberwein disclaims beneficial ownership of warrants to purchase up to 406,051 common shares as the holder of the warrants may not exercise the warrants to the extent such exercise would cause such holder, together with its affiliates and attribution parties, to beneficially own a number of common shares which would exceed 4.99% (or, at the election of the holder, 9.99%) of our then outstanding common shares following such exercise.

(8) Represents 54,101 common shares issuable upon conversion of $103,333 of 10% senior secured convertible notes (including accrued interest as of January 14, 2025 and interest accruing for 60-days after January 14, 2025) at a conversion price of $1.91. The address is 130 S Estates Dr, Salina, KS 67401. Mr. Peckham disclaims beneficial ownership of warrants to purchase up to 52,300 common shares as the holder of the warrants may not exercise the warrants to the extent such exercise would cause such holder, together with its affiliates and attribution parties, to beneficially own a number of common shares which would exceed 4.99% (or, at the election of the holder, 9.99%) of our then outstanding common shares following such exercise.

(9) Represents 54,101 common shares issuable upon conversion of $103,333 of 10% senior secured convertible notes (including accrued interest as of January 14, 2025 and interest accruing for 60-days after January 14, 2025) at a conversion price of $1.91. The address is 2223 Tamarron Terrace, Manhattan, KS 66502. Mr. Law disclaims beneficial ownership of warrants to purchase up to 52,300 common shares as the holder of the warrants may not exercise the warrants to the extent such exercise would cause such holder, together with its affiliates and attribution parties, to beneficially own a number of common shares which would exceed 4.99% (or, at the election of the holder, 9.99%) of our then outstanding common shares following such exercise.

(10) Represents (i) 29,167 common shares owned by Petro Americas Resources, LLC, (ii) 26,042 common shares owned by Rockport Permian, LLC, (iii) 13,021 common shares issuable upon exercise of warrants owned by Rockport Permian, LLC and (iv) 14,583 common shares issuable upon exercise of warrants owned by Petro Americas Resources, LLC. John James Lendrum has the right to vote and dispose of the securities held by each of Petro Americas Resources, LLC and Rockport Permian, LLC.

(11) Represents (i) 48,958 common shares owned by Pratt Oil and Gas, LLC and (ii) 24,479 common shares issuable upon exercise of warrants owned by Pratt Oil and Gas, LLC. James Perry Bryan has the right to vote and dispose of the securities held by Pratt Oil and Gas, LLC.

(12) Ramnarain Jaigobind is a principal of ThinkEquity LLC a registered broker dealer with a registered address of c/o ThinkEquity LLC 17 State Street, 41st Floor New York, NY 10004. ThinkEquity LLC acted as the Company’s placement agent for its March 2022 private placement offering, as financial advisor for the June 2023 warrant exercise program and is the representative for the several underwriters of this offering.

(13) Represents 52,083 common shares and 81,152 shares issuable upon conversion of $155,000 of 10% senior secured convertible notes (including accrued interest as of January 14, 2025 and interest accruing for 60-days after January 14, 2025) at a conversion price of $1.91. Mr. Jaigobind disclaims beneficial ownership of warrants to purchase up to 108,901 common shares as the holder of the warrants may not exercise the warrants to the extent such exercise would cause such holder, together with its affiliates and attribution parties, to beneficially own a number of common shares which would exceed 4.99% (or, at the election of the holder, 9.99%) of our then outstanding common shares following such exercise.

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Equity Compensation Plan Information

The following table summarizes information about our equity compensation plans as of September 30, 2024.

	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)			Weighted average exercise price of outstanding options, warrants and rights			Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by securityholders		10,105	(1)	$	53.21	(2)		45,045
Equity compensation plans not approved by securityholders		—			—			—
Total		10,105		$	53.21			45,045

(1)	Represents the number of common shares available for issuance upon exercise of outstanding options as at September 30, 2024.
(2)	CAD$71.90 converted into USD.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information for this item is set forth in the sections entitled “Related Party Transactions” and “Executive Compensation”.

Independence

We have determined each of Richard Little, Kevin Nanke, and BaShara (Bo) Boyd to be “independent” directors within the meaning of the listing standards of the Nasdaq Capital Market. Bradley Taillon is not independent since he is the current President and CEO of the Company. In making our independence determinations, we have considered all relationships between any of the directors and the Company.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Audit and Audit-Related Fees

The following table sets forth the aggregate fees billed by our current and prior independent accountants, Marcum LLP and Davidson & Company LLP, for professional services rendered in the fiscal years ended September 30, 2024 and 2023.

	2024		2023
Audit Fees (1)	$	199,913	$	530,390
Audit-Related Fees (2)		86,746		111,980
Tax fees (3)		-		-
All Other Fees (4)		-		-

(1)	“Audit Fees” represent fees for professional services provided in connection with the audit of our annual financial statements and review of our quarterly financial statements included in our reports on Form 10-Q, and audit services provided in connection with other statutory or regulatory filings, including without limitation, our Registration Statements on Form S-1
(2)	“Audit-Related Fees” generally represent fees for assurance and related services reasonably related to the performance of the audit or review of our financial statements.
(3)	“Tax Fees” generally represent fees for tax compliance, tax advice and tax planning.
(4)	“All Other Fees” generally represents fees for products and services provided to the Company that are not otherwise reported in the table.

Pre-approval policies and procedures

It is the policy of the Company not to enter into any agreement for Marcum LLP to provide any non-audit services to the Company unless: (a) the agreement is approved in advance by the Audit Committee; or (b) (i) the aggregate amount of all such non-audit services constitutes no more than 5% of the total amount the Company pays to Marcum LLP during the fiscal year in which such services are rendered, (ii) such services were not recognized by the Company as constituting non-audit services at the time of the engagement of the non-audit services and (iii) such services are promptly brought to the attention of the Audit Committee and prior to the completion of the audit were approved by the Audit Committee or by one or more members of the Audit Committee who are members of the Board to whom authority to grant such approvals has been delegated by the Audit Committee. The Audit Committee will not approve any agreement in advance for non-audit services unless: (1) the procedures and policies are detailed in advance as to such services; (2) the Audit Committee is informed of such services prior to commencement; and (3) such policies and procedures do not constitute delegation of the Audit Committee’s responsibilities to management under the Exchange Act.

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as part of this Annual Report:

(1) Financial Statements

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM  (PCAOB ID No. 688)	F-2
CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Balance Sheets	F-3
Consolidated Statements of Operations and Comprehensive Loss	F-4
Consolidated Statements of Changes in Stockholders’ Equity	F-5
Consolidated Statements of Cash Flows	F-6
Notes to the Consolidated Financial Statements	F-7
Supplemental Information on Oil and Gas Operations (Unaudited)	F-24

(2) Financial Statement Schedules

All financial statement schedules are omitted either because they are not required, not applicable or the required information is included in the financial statements or notes thereto.

(3) Exhibits

Exhibit Number	Exhibit Description
3.1	Articles of Permex Petroleum Corporation (Incorporated by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on August 29, 2022)
3.2	Amendment to the Articles of Permex Petroleum Corporation (Incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on September 29, 2023)
3.3*	Amendment to the Articles of Permex Petroleum Corporation
4.1	Specimen of Share Certificate for Permex Petroleum Corporation’s common shares (Incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-1 filed with the SEC on June 28, 2022)
4.2*	Description of Common Stock
4.3	Form of Incentive Warrant (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed with the SEC on July 11, 2023)
4.4	Form of 10% Secured Convertible Debenture (Incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the SEC on November 7, 2024)
4.5	Form of Common share Purchase Warrant (Incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed with the SEC on November 7, 2024)
4.6	Form of Registration Rights Agreement between the Company and various purchasers (Incorporated by reference to Exhibit 10.3 to the Company’s Registration Statement on Form S-1 filed with the SEC on June 28, 2022)
4.7	Form of Registration Rights Agreement between the Company and various purchasers (Incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on November 7, 2024)

55

10.2+	Employment Agreement by and between the Company and Mehran Ehsan (Incorporated by reference to Exhibit 10.8 to the Company’s Registration Statement on Form S-1 filed with the SEC on June 28, 2022)
10.3+	Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on October 28, 2024)
10.4+	Executive Employment Agreement by and between the Company and Gregory Montgomery (Incorporated by reference to Exhibit 10.10 to the Company’s Registration Statement on Form S-1/A filed with the SEC on July 15, 2022)
10.5+	Employment Agreement dated April 29, 2024 between the Company and Bradley Taillon (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on April 29, 2024)
10.6+	Separation Agreement dated August 30, 2024 between the Company and Mehran Ehsan, (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on October 28, 2024)
10.7	Security Agreement, dated November 1, 2024, by and between the Company, various obligors and Jeffrey Eberwein, as collateral agent for the holders of the debentures (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on November 7, 2024)
14.1	Code of Business Conduct and Ethics, (Incorporated by reference filed as an Exhibit 14.1 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2023 filed with the SEC on February 13, 2023).
16.1	Letter of Davidson & Company LLP dated November 3, 2022 (Incorporated by reference to Exhibit 16.1 to the Company’s Current Report on Form 8-K filed with the SEC on November 4, 2022)
21.1*	List of subsidiaries of the Registrant
23.1*	Consent of MKM Engineering
31.1*	Certification of the Principal Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of the Principal Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certification of the Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certification of the Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1*	Appraisal of Certain Oil & Gas Interests Owned by Permex Petroleum Corporation Located in New Mexico & Texas as of September 30, 2024
99.2	Appraisal of Certain Oil & Gas Interests Owned by Permex Petroleum Corporation Located in New Mexico & Texas as of September 30, 2023(Incorporated by reference to Exhibit 99.1 to the Company’s Annual Report on Form 10-K for the year ended September 30, 2023 filed with the SEC on July 26, 2024).
99.3*	Audit Committee Charter
99.4*	Compensation Committee Charter
101.INS*	Inline XBRL Instance Document.
101.SCH*	Inline XBRL Taxonomy Extension Schema Document.
101.CAL*	Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*Filed herewith

+ Indicates management contract or compensatory plan or arrangement.

ITEM 16. FORM 10-K SUMMARY

None.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PERMEX PETROLEUM CORPORATION

By:	/s/ Bradley Taillon
	Bradley Taillon
	President and Chief Executive Officer

Date: January 14, 2025

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:

Signature		Date
/s/ Bradley Taillon	Chief Executive Officer, President and Director (Principal Executive Officer)	January 14, 2025
Bradley Taillon
/s/ Gregory Montgomery	Chief Financial Officer (Principal Financial and Accounting Officer)	January 14, 2025
Gregory Montgomery
/s/ Richard Little	Director	January 14, 2025
Richard Little
/s/ Kevin Nanke	Director	January 14, 2025
Kevin Nanke
/s/ BaShara (Bo) Boyd	Director	January 14, 2025
BaShara (Bo) Boyd

57

EX-3.3

Exhibit 3.3

PERMEX PETROLEUM CORPORATION

(the “Company”)

AMENDMENT TO THE ARTICLES OF THE COMPANY

Pursuant to section 42(2)(a)(iv) of the British Columbia Business Corporations Act, the following is an extract of a resolution passed by the directors of the Company on October 30, 2024, which extract is to be attached to the Articles of the Company as effected on October 30, 2024.

“AMENDMENT TO ARTICLES

WHEREAS the Company wishes to amend section 11.3 of the Articles of the Company to change the quorum requirement for the transaction of business at a meeting of shareholders;

BE IT RESOLVED THAT the existing Articles of the Company be amended by deleting the existing section 11.3 in its entirety and replacing section 11.3 in the form attached as Schedule “A” hereto, to be effective as of the date herein.”

Schedule “A”

11.3 Quorum

Subject to the special rights and restrictions attached to the shares of any class or series of shares, the quorum for the transaction of business at a meeting of shareholders is one person present or represented by proxy.

EX-4.2

Exhibit 4.2

DESCRIPTION OF THE REGISTRANT’S COMMON SHARES

The authorized share capital of Permex Petroleum Corporation (the “Company”) consists of an unlimited number of common shares without par value (the “Common Shares”). As of January 14, 2025, 551,503 common shares were issued and outstanding.

Each common share carries the right to attend and vote at all general meetings of the Company’s shareholders. Holders of the common shares are entitled to dividends, if any, as and when declared by the Company’s Board of Directors and to one vote per common share at meetings of the Company’s shareholders. In addition, upon liquidation, dissolution or winding-up of the Company, holders of common shares may share, on a pro rata basis, the remaining assets of the Company as are distributable to holders of common shares of the Company. The Company may, subject to certain exceptions, purchase, redeem or otherwise acquire any of its shares at the price and upon the terms determined by the Company’s Board of Directors. The Company’s Common Shares are not subject to call or assessment rights, rights regarding purchase for cancellation or surrender, or any pre-emptive or conversion rights.

 

EX-21.1

Exhibit 21.1

Permex Petroleum Corporation

List of Subsidiaries

Entity Name	Jurisdiction of Formation
Permex Petroleum US Corporation	New Mexico

EX-23.1

Exhibit 23.1

CONSENT OF MKM ENGINEERING

We hereby consent to (i) the use of the name MKM Engineering, (ii) references to MKM Engineering as an independent oil and gas engineering consulting firm, and (iii) the use of information from our Appraisal of Certain Oil and Gas Interests owned by Permex Petroleum Corporation located in New Mexico and Texas as of September 30, 2024 (the “2024 Appraisal Report”), as well as, our Appraisal of Certain Oil and Gas Interests owned by Permex Petroleum Corporation located in New Mexico and Texas as of September 30, 2023 (the “2023 Appraisal Report”, and together with the 2024 Appraisal Report, the “Appraisal Reports”), which contain our opinion of the proved reserves and future net revenue of Permex Petroleum as of September 30 2024, and September 30 2023, respectively, in the Permex Petroleum Corporation Annual Report on Form 10-K for the year ended September 30, 2024 (the “Form 10-K”). We further consent to the inclusion of our Appraisal Reports as Exhibits 99.1, and 99.2 in the Form 10-K.

	MKM ENGINEERING
	Texas Registered Engineering Firm F-009733
January 14, 2025	By	/s/ Michele K. Mudrone
	Name:	Michele K. Mudrone
	Title:	Professional Engineer

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13a-14(a) OF THE SECURITIES EXCHANGE ACT OF 1934

I, Bradley Taillon, certify that:

1. I have reviewed this Annual Report on Form 10-K of Permex Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: January 14, 2025

/s/ “Bradley Taillon”

Bradley Taillon

President and Chief Executive Officer

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO RULE 13a-14(a) OF THE SECURITIES EXCHANGE ACT OF 1934

I, Gregory Montgomery, certify that:

1. I have reviewed this Annual Report on Form 10-K of Permex Petroleum Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: January 14, 2025

/s/ Gregory Montgomery

Gregory Montgomery

Chief Financial Officer

(Principal Financial and Accounting Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Bradley Taillon, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report of Permex Petroleum Corporation on Form 10-K for the annual period ended September 30, 2024 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Form 10-K fairly presents in all material respects the financial condition and results of operations of Permex Petroleum Corporation.

Date: January 14, 2025

By:	/s/ Bradley Taillon
Name:	Bradley Taillon
Title:	President and Chief Executive Officer

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002 has been provided to Permex Petroleum Corporation. and will be retained by Permex Petroleum Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

This certification accompanies this Report on Form 10-K pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by such Act, be deemed filed by Permex Petroleum Corporation for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act, except to the extent that Permex Petroleum Corporation specifically incorporates it by reference.

EX-32.2

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Gregory Montgomery, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report of Permex Petroleum Corporation. on Form 10-K for the annual period ended September 30, 2024 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Form 10-K fairly presents in all material respects the financial condition and results of operations of Permex Petroleum Corporation.

Date: January 14, 2025

By:	/s/ Gregory Montgomery
Name:	Gregory Montgomery
Title:	Chief Financial Officer

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002 has been provided to Permex Petroleum Corporation and will be retained by Permex Petroleum Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

This certification accompanies this Report on Form 10-K pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by such Act, be deemed filed by Permex Petroleum Corporation for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act, except to the extent that Permex Petroleum Corporation specifically incorporates it by reference.

January 14, 2025

EX-99.1

Exhibit 99.1

Permex Petroleum Corporation

November 27, 2024

Page 1

APPRAISAL OF

CERTAIN OIL AND GAS INTERESTS

OWNED BY PER MEX PETROLEUM CORPORATION

LOCATED IN

NEW MEXICO AND TEXAS

AS OF SEPTEMBER 30, 2024

PREPARED FOR

PERMEX PETROLEUM CORPORATION

SEC Pricing

Revision 2

MKM ENGINEERING

F-009377

Michele K. Mudrone, P.E.

November 27, 2024

MKM ENGINEERING

Oil and Gas Consulting Services

3905 Sagamore Hill Court

Plano, Texas 75025

November 27, 2024

Mr. Brad Taillon

Permex Petroleum Corporation

100 Crescent Court, Suite 700

Dallas, Texas 75201

Dear Mr. Taillon:

As requested, we are submitting our estimates of proved and probable reserves and our forecasts of the resulting economics attributable to the interests of Permex Petroleum Corporation as of September 30, 2024, in certain properties located in Eddy County, New Mexico, Gaines, Stonewall, and Young Counties, Texas. We completed our evaluation on November 27, 2024. It is our understanding that the proved and probable reserves estimated in this report constitute 100% of all proved and probable reserves owned by Permex Petroleum Corporation in the United States.

This report has been prepared for Permex Petroleum Corporation’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose. Composite proved reserve estimates and economic forecasts are summarized below:

				Proved		Proved
				Developed		Non-		Proved
		Proved		Producing		Producing		Undeveloped
Net Reserves
Oil/Condensate	MBbl		1,695.4		46.4		462.3		1,186.7
Gas	MMcf		1,138.2		54.4		225.2		858.6
Revenue
Oil/Condensate	M$		133,265.3		3,642.4		36,020.7		93,602.2
Gas	M$		815.7		81.4		132.0		602.3
Severance and
Ad Valorem Taxes	M$		10,020.0		267.8		3,036.0		6,716.2
Operating Expenses	M$		21,731.8		1,753.9		9,977.4		10,000.5
Investments	M$		17,496.5		255.0,		1,621.5		15,620.0
Operating Income (BFIT)	M$		84,832.5		1,447.0		21,517.7		61,867.8
Discounted @ 10%	M$		36,137.4		907.7		11,258.8		23,970.9

Composite probable reserve estimates and economic forecasts are summarized below:

				Probable
				Non-		Probable
		Probable		Producing		Undeveloped
Net Reserves
Oil/Condensate	MBbl		12,306.5		93.8		12,212.7
Gas	MMcf		15,437.0		9.8		15,427.2
Revenue
Oil/Condensate	M$		965,699.9		7,259.7		958,440.2
Gas	M$		21,957.0		21.5		21,935.5
Severance and
Ad Valorem Taxes	M$		51,196.1		531.8		50,664.3
Operating Expenses	M$		74,958.9		1,137.3		73,821.6
Investments	M$		134,328.5		0.0		134,328.5
Operating Income (BFIT)	M$		727,173.4		5,612.1		721,561.3
Discounted @ 10%	M$		192,718.9		2,161.2		190,557.7

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the September 30, 2024 estimated reserves.

Primary Economic Assumptions

Values of proved and probable reserves in this report are expressed in terms of estimated future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating expenses, capital costs, and abandonment costs from the future gross revenue. Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Future income tax expenses were not taken into account in the preparation of these estimates. Present worth of future net revenue is calculated by discounting the future net revenue at the rate of 10 percent per year compounded annually over the expected period of realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold.

Future prices were estimated using guidelines established by the SEC and the Financial Account Standards Board (FASB). The assumptions used for estimating future prices and expense are as follows:

Oil and Condensate Prices

Oil and condensate price differentials were calculated for each property based on prices received by Permex. The prices were calculated using these differentials to a posted West Texas Intermediate (WTI) at Cushing of $78.64 per barrel and were held constant for the lives of the properties. The WTI oil price of $78.64 per barrel is the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each of the last three months of 2023 and the first nine months of 2024. The volume-weighted average product price over the life of the properties was $78.49 per barrel of oil.

Gas Prices

Gas price differentials were calculated for each property based on prices received by Permex. The prices were calculated using these differentials to a Henry Hub price of $2.206 per million British thermal units (MMBtu) and were held constant for the lives of the properties. The Henry Hub gas price of $2.206 per MMBtu is the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each of the last three months of 2023 and the first nine months of 2024 British thermal unit factors were provided by Permex and used to convert prices from dollars per MMBtu to dollars per thousand cubic feet ($/Mcf). The volume-weighted average product price over the life of the properties was $1.37 per thousand cubic feet of gas.

Production and Ad Valorem taxes

Production taxes were calculated using the tax rates for the state in which the property is located. Ad valorem taxes were calculated using average rates for each county in which the property is located.

Operating Expenses, Capital Costs and Abandonment Costs

Operating costs were based on operating expense records of Permex Petroleum Corporation and based on current expenses, were held constant for the lives of the properties. Development costs were furnished to us by Permex and are based on authorization for expenditures for the proposed work or actual costs of similar projects. The development costs furnished to us were accepted as factual data and reviewed by MKM Engineering for their reasonableness; however, we have not conducted an independent verification of these costs. Capital expenditures for plugging, abandonment, and reclamation of the properties at the end-of-project life were included in this report.

The undeveloped reserves in this report have been incorporated herein in accordance with Permex’s plans to develop these reserves as of September 30, 2024. The implementation of Permex’s development plans and budget as presented to us and incorporated herein were approved by Permex’s management. Additionally, Permex has informed MKM Engineering that they are not aware of any legal, regulatory, or political obstacles that would significantly alter the development plans.

The proved and probable reserve classifications conform to criteria of the Securities and Exchange Commission. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangement but not including escalations based on future conditions. The reserves and economics are predicted on the regulatory agency classifications, rules, policies, laws, taxes, and royalties in effect on the date of this report except as noted herein. In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geosciences. Therefore, the possible effects of changes in legislation or other Federal or State restrictive actions have not been considered. An on-site field inspection of these properties has not been made nor have the wells been tested by MKM Engineering. Possible environmental liability related to the properties has not been investigated nor considered.

Methodology and Procedures

The reserves were estimated using a combination of the production performance, volumetric, and analogy methods, in each case as we considered to be appropriate and necessary to establish the conclusions set forth herein. All reserve estimates represent our best judgment based on data available at the time of preparation and assumptions as to future economic and regulatory conditions. It should be realized that the reserves actually recovered, the revenue derived therefrom, and the actual cost incurred could be more or less than the estimated amounts.

The process of estimated reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.

For depletion type reservoirs or those whose performance disclosed a reliable decline in producing rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production decline curves, reserves were estimated only to the limits of economic production based on existing economic conditions. In certain cases, when the previously named method could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complex data were available.

As circumstances change and additional data become available, reserve estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions, and governmental restrictions.

Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions, new geological or production information, and a changing environment may impact these estimates. Revisions to reserve estimates can arise from changes in year-end oil and gas prices, and reservoir performance. Such revisions can be positive or negative.

Gas reserves estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel use and shrinkage resulting from the field separation and processing. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit and at the pressure base of the state in which the resources are located. Gas reserves included herein are expressed in thousands of cubic feet (Mcf). Oil and condensate reserves estimated herein are those to be recovered by conventional lease separation. Oil and condensate reserves included in this report are expressed in barrels (bbl) representing 42 United States gallons per barrel.

The reserve estimates were based on interpretations of factual data furnished by Permex Petroleum Corporation. Ownership interests were supplied by Permex Petroleum Corporation and were accepted as furnished. To some extent, information from public records has been used to check and/or supplement this data. The basic engineering and geological data were utilized subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data.

MKM Engineering is independent with respect to Permex Petroleum Corporation as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (“SPE Standards”). Neither MKM Engineering nor any of its employees has any interest in the subject properties. Neither the employment to make this study nor the compensation is contingent on the results of our work or the future production rates for the subject properties.

Our work papers and related data are available for inspection and review by authorized parties.

Respectfully submitted,

MKM ENGINEERING

Texas Registered Engineering Firm F-009733

Michele K. Mudrone, P.E.

Attachments

EX-99.3

Exhibit 99.3

AUDIT COMMITTEE CHARTER

This Charter establishes the composition, the authority, roles and responsibilities and the general objectives of the Company’s audit committee, or its Board of Directors in lieu thereof (the “Audit Committee”). The roles and responsibilities described in this Charter must at all times be exercised in compliance with the legislation and regulations governing the Company and any subsidiaries.

1. Composition

(a) Number of Members. The Audit Committee must be comprised of a minimum of three directors of the Company.

(b) Chair. If there is more than one member of the Audit Committee, members will appoint a chair of the Audit Committee (the “Chair”) to serve for a term of one (1) year on an annual basis. The Chair may serve as the chair of the Audit Committee for any number of consecutive terms.

(c) Financial Literacy. All members of the audit committee will be financially literate as defined by applicable legislation. If upon appointment a member of the Audit Committee is not financially literate as required, the person will be provided with a period of three months to acquire the required level of financial literacy.

2. Meetings

(a) Quorum. The quorum required to constitute a meeting of the Audit Committee is set at a majority of members.

(b) Agenda. The Chair will set the agenda for each meeting, after consulting with management and the external auditor. Agenda materials such as draft financial statements must be circulated to all Audit Committee members for members to have a reasonable amount of time to review the materials prior to the meeting.

(c) Notice to Auditors. The Company’s auditors (the “Auditors”) will be provided with notice as necessary of any Audit Committee meeting, will be invited to attend each such meeting and will receive an opportunity to be heard at those meetings on matters related to the Auditor’s duties.

(d) Minutes. Minutes of the Audit Committee meetings will be accurately recorded, with such minutes recording the decisions reached by the committee.

3. Roles and Responsibilities

The roles and responsibilities of the Audit Committee include the following: External Auditor

The Audit Committee will:

(a) Selection of the external auditor. Select, evaluate and recommend to the Board, for shareholder approval, the Auditor to examine the Company’s accounts, controls and financial statements.

(b) Scope of Work. Evaluate, prior to the annual audit by the Auditors, the scope and general extent of the Auditor’s review, including the Auditor’s engagement letter.

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(c) Compensation. Recommend to the Board the compensation to be paid to the external auditors.

(d) Replacement of Auditor. If necessary, recommend the replacement of the Auditor to the Board of Directors.

(e) Approve Non-Audit Related Services. Pre-approve all non-audit services to be provided by the Auditor to the Company or its subsidiaries.

(f) Responsibility for Oversight. Must directly oversee the work of the Auditor. The Auditor must report directly to the Audit Committee.

(g) Resolution of Disputes. Assist with resolving any disputes between the Company’s management and the Auditors regarding financial reporting.

Consolidated Financial Statements and Financial Information

The Audit Committee will:

(a) Review Audited Financial Statements. Review the audited consolidated financial statements of the Company, discuss those statements with management and with the Auditor, and recommend their approval to the Board.

(b) Review of Interim Financial Statements. Review and discuss with management the quarterly consolidated financial statements, and if appropriate, recommend their approval by the Board.

(c) MD&A, Annual and Interim Earnings Press Releases, Audit Committee Reports. Review the Company’s management discussion and analysis, interim and annual press releases, and audit committee reports before the Company publicly discloses this information.

(d) Auditor Reports and Recommendations. Review and consider any significant reports and recommendations issued by the Auditor, together with management’s response, and the extent to which recommendations made by the Auditor have been implemented.

Risk Management, Internal Controls and Information Systems

The Audit Committee will:

(a) Internal Control. Review with the Auditors and with management, the general policies and procedures used by the Company with respect to internal accounting and financial controls. Remain informed, through communications with the Auditor, of any weaknesses in internal control that could cause errors or deficiencies in financial reporting or deviations from the accounting policies of the Company or from applicable laws or regulations.

(b) Financial Management. Periodically review the team in place to carry out financial reporting functions, circumstances surrounding the departure of any officers in charge of financial reporting, and the appointment of individuals in these functions.

(c) Accounting Policies and Practices. Review management plans regarding any changes in accounting practices or policies and the financial impact thereof.

(d) Litigation. Review with the Auditors and legal counsel any litigation, claim or contingency, including tax assessments, that could have a material effect upon the financial position of the

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Company and the manner in which these matters are being disclosed in the consolidated financial statements.

(e) Other. Discuss with management and the Auditors correspondence with regulators, employee complaints, or published reports that raise material issues regarding the Company’s financial statements or disclosure.

Complaints

(a) Accounting, Auditing and Internal Control Complaints. The Audit Committee must establish a procedure for the receipt, retention and treatment of complaints received by the Company regarding accounting, internal controls or auditing matters.

(b) Employee Complaints. The Audit Committee must establish a procedure for the confidential transmittal on condition of anonymity by the Company’s employees of concerns regarding questionable accounting or auditing matters.

4. Authority

(a) Auditor. The Auditor, and any internal auditors hired by the company, will report directly to the Audit Committee.

(b) Independent Advisors. The Audit Committee may, at the Company’s expense and without the approval of management, retain the services of independent legal counsels and any other advisors it deems necessary to carry out its duties and set and pay the monetary compensation of these individuals.

5. Reporting

The Audit Committee will report to the Board on:

(a) the Auditor’s independence;

(b) the performance of the Auditor and any recommendations of the Audit Committee in relation thereto;

(c) the reappointment and termination of the Auditor;

(d) the adequacy of the Company’s internal controls and disclosure controls;

(e) the Audit Committee’s review of the annual and interim consolidated financial statements;

(f) the Audit Committee’s review of the annual and interim management discussion and analysis;

(g) the Company’s compliance with legal and regulatory matters to the extent they affect the financial statements of the Company; and

(h) all other material matters dealt with by the Audit Committee.

EX-99.4

Exhibit 99.4

COMPENSATION COMMITTEE CHARTER

PURPOSE

The purpose of the Compensation Committee (the “Committee”) of the Board of Directors (the “Board”) of Permex Petroleum Corporation (the “Company”) is to discharge the Board’s responsibilities relating to compensation of the Company’s Management, as defined below. The Committee, under the supervision of the Board, shall have the overall responsibility for:

(a)	Reviewing and recommending the compensation of the Company’s Chief Executive Officer (“CEO”), the CEO’s direct reports, the Chief Financial Officer, and any other executive officers (as defined in Rule 3b-7 of the Exchange Act, as defined below) of the Company (collectively, the “Executive Officers”), directors and key employees (collectively, the “Management”).
(b)	Reviewing and recommending succession plans for the CEO and other Executive Officers.
(c)	Overseeing and evaluating the Company’s compensation and benefits policies, plans and programs, and insuring overall alignment to the corporate compensation philosophy.
(d)	General oversight of the Company’s compensation structure.
(e)	Preparing any report on executive compensation required by the rules and regulations of the U.S. Securities and Exchange Commission (the “SEC”).
(f)	Such other additional specific duties and responsibilities as are set out herein.

The term “compensation” shall include salary, incentive and equity compensation, bonuses, severance arrangements and other compensatory benefits or rights received under the Company’s benefit plans.

COMMITTEE COMPOSITION

The membership of the Committee shall be as follows:

(a)

The Committee shall consist of a minimum of two members of the Board, appointed annually by members of the Board. The Board may fill a vacancy that occurs in the Committee at any time.

(b)

Each Committee member must qualify as: (i) an independent director, as defined by Nasdaq Rule 5605(a)(2); (ii) to the extent required by the Board, a “non-employee director” within the meaning of Rule 16b-3 promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”); and (iii) to the extent required by the Board, shall satisfy any other applicable standards of independence under the federal securities and tax laws. In the event that any member of the Committee does not qualify as a “non-employee director” for purposes of Section 16 of the Exchange Act, then all compensation that is intended to be exempt from Section 16 shall also be approved by the Board or a subcommittee made up of members of the Board who qualify as non-employee directors.

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(c)	Each committee member will have no direct or indirect relationship with the Company which, in the view of the Board, could reasonably interfere with the exercise of a member’s independent judgment.
(d)	In considering whether a Committee member is independent, the Board must consider all factors specifically relevant to determining whether a director has a relationship to the Company which is material to that director’s ability to be independent from management in connection with the duties of a compensation committee member, including, but not limited to: (i) the source of compensation of such director, including any consulting, advisory or other compensatory fee paid by the Company to such director; and (ii) whether such director is affiliated with the Company, a subsidiary of the Company or an affiliate of a subsidiary of the Company.
(e)	The Board will elect, by a majority vote, one Committee member to serve as chairperson of the Committee (the “Chair”). If a Chair has not been designated by the Board, the members of the Committee may designate a Chair by majority vote of the Committee membership.
(f)	Committee members shall be appointed by the Board. Committee members shall be appointed for one year terms, with such terms to renew automatically if no successor is appointed; provided that members of the Committee may be replaced or removed by the Chair of the Board, or the Board at any time, with or without cause.
(g)	A member may resign from the Committee. Vacancies shall be filled by appointment from among the independent members of the Board. Resignation or removal of a director from the Board, for whatever reason, will automatically constitute resignation or removal, as applicable, from the Committee.
(h)	The Committee may create one or more subcommittees of members of the Committee and may delegate, in its discretion, all or a portion of its duties and responsibilities to such subcommittees.

MEETINGS

(a)	The Committee shall meet as often as may be considered necessary or appropriate, in its judgment, and will report regularly to the full Board with respect to its activities and make recommendations to the Board as appropriate.
(b)	The Committee may meet either in person, through use of conference telephone, video or similar communications equipment in a manner consistent with the Company’s articles, at such times and places as determined by the members of the Committee.

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(c)	The presence of a majority of the Committee’s members at a meeting shall constitute a quorum. Committee members may participate in a meeting, and be deemed present at the meeting, through use of conference telephone, video or similar communications equipment in a manner consistent with the Company’s articles.
(d)	Actions of the Committee may be taken: (i) by approval by at least a majority of the Committee members present at a meeting at which a quorum is present; or (ii) without a meeting if all members of the Committee individually or collectively consent in writing to such action. Where a meeting is not practicable, resolutions in writing which are signed by all members of the Committee are deemed valid as if they had been passed at a meeting of the Committee.
(e)	Meetings will be generally conducted without the presence of members of management, however the Committee may invite such members of management to its meetings as it may deem desirable or appropriate, consistent with the maintenance of the confidentiality of compensation discussions.
(f)	The CEO may not be present for any portion of any meeting at which the compensation of the CEO is being deliberated or voted upon.
(g)	Minutes of the Committee meetings will be kept and filed in the Company’s minute book.

RESPONSIBILITIES

Subject to the powers and duties of the Board, the Board hereby delegates to the Committee the following powers and duties to be performed by the Committee on behalf of and for the Board:

Compensation of CEO, Other Executive Officers, Directors and Key Employees

(a)

On an annual basis, or more frequently if deemed necessary by the Committee or requested by the Board, review and recommend corporate goals and objectives concerning the compensation of Management.

(b)

Evaluate Management’s performance against these corporate goals and objectives. In evaluating, determining and approving the long-term incentive component of CEO compensation, the Committee may consider, among such other factors as it may deem relevant, the Company’s performance, shareholder returns, the value of similar incentive awards to executive officers at comparable companies, the value of similar awards given to other Executive Officers of the Company, the results of the most recent shareholder advisory vote on executive compensation required by Section 14A of the Exchange Act (the “Say-on-Pay Vote”) and the awards given to the CEO in past years.

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(c)	Determine and recommend Management’s compensation and benefits plans based on this evaluation. In evaluating and making recommendations with respect to the long-term incentive component of Management compensation, the Committee may consider, among such other factors as it may deem relevant, the Company’s performance, shareholder returns, the value of similar incentive awards to executive officers at comparable companies, the value of similar awards given to other Executive Officers of the Company, the results of the most recent Say-on-Pay Vote and the awards given to the member of Management in past years.
(d)	To review and recommend to the Board for approval the frequency with which the Company will conduct Say-on-Pay Votes, taking into account the results of the most recent stockholder advisory vote on frequency of Say-on-Pay Votes required by Section 14A of the Exchange Act, and review and approve the proposals regarding the Say-on-Pay Vote and the frequency of the Say-on-Pay Vote to be included in the Company’s proxy statement.
(e)	Review and recommend to the Board the overall compensation of each newly elected Executive Officer, director and key employee, including all employment related and severance agreements. Evaluate on an annual basis the competitiveness of the remuneration packages for Management. Without limiting the generality of (a) to (f) above, the Committee shall annually review all compensation arrangements with the Executive Officers, including (i) the annual base salary level; (ii) the annual incentive opportunity level; (iii) the long-term incentive opportunity level; (iv) employment agreements, severance arrangements, and change in control agreements/provisions, in each case as, when and if appropriate; and (v) any special or supplemental benefits. In conducting such annual reviews, the Committee shall review the corporate goals and objectives relevant to such compensation, the Executive Officers’ performance in light of those goals and objectives, the Company’s stockholder returns, the value of incentive awards to the Executive Officers and officers at comparable companies and the awards given to the Executive Officers in past years.

Board of Directors Compensation

(a) Review annually, or more frequently if deemed necessary by the Committee or requested by the Board, and recommend to the Board for its approval, the compensation paid to directors who serve on the Board or its committees, including any retainer, chair fees, and equity compensation. These recommendations should take into account North American and industry-wide compensation practices and trends for comparable companies.

Company Compensation

(a)	Oversee and evaluate the Company’s general compensation structure and policies to attract, award, develop and retain Management and other employees.
(b)	Evaluate on an annual basis the competitiveness of the overall compensation structure and incentive programs for non-Management employees.

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Administration of Plans

(a)	Review and administer the Company’s stock option plan and other equity-based and incentive compensation plans (the “Plans”) and make recommendations to the Board as appropriate.
(b)	Evaluate on a periodic basis the competitiveness of the Plans established and make recommendations for improvement as appropriate.
(c)	Evaluate the use of the Plans, from time to time, as a form of incentive compensation for external consultants, subject to applicable laws and regulations.
(d)	Monitor the compliance of these plans with applicable laws and regulations.

Clawback Policy

(a)	The Committee shall administer any Company policy relating to recovery or recoupment of compensation from officers and other employees (each, a “clawback policy”), in each case in accordance with the provisions of such policy.
(b)	The Committee shall periodically review the Company’s clawback policy or policies, as applicable, and recommend to the Board any amendment, modification, supplement, restatement, termination or replacement thereto as it deems advisable or necessary to reflect and comply with applicable laws and regulations.

Public Disclosure of Executive Compensation

(a)	Review all disclosure of executive compensation, including compensation philosophy, prior to public release.
(b)	Prepare any executive compensation report required by regulatory requirements for inclusion in the Company’s annual report, proxy statement, information circular or other regulatory filings, as the case may be and if applicable, in accordance with applicable SEC rules and regulations.
(c)	Where applicable, to review and discuss with management the Company’s Compensation Discussion and Analysis (“CD&A”) and the related executive compensation information, recommend that the CD&A and related executive compensation information be included in the Company’s annual report on Form 10-K and proxy statement.

Stock Ownership

(a) To determine stock ownership guidelines for Management and monitor compliance with such guidelines.

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Risk Management and Succession

(a)	To review the Company’s incentive compensation arrangements to determine whether they encourage excessive risk-taking, to review and discuss at least annually the relationship between risk management policies and practices and compensation, and to evaluate compensation policies and practices that could mitigate any such risk.
(b)	To develop and recommend to the Board for approval a CEO succession plan (the “Succession Plan”), to review the Succession Plan periodically with the CEO, develop and evaluate potential candidates for CEO and recommend to the Board any changes to, and any candidates for succession under, the Succession Plan.

Committee Assessment

(a) Evaluate annually the performance of the Committee in light of the roles and responsibilities outlined in this Charter. The Committee shall conduct this evaluation in such manner as it deems appropriate.

Charter Evaluation

(a) Review, discuss and assess annually this Charter and recommend changes to the Board for approval.

Experts and Advisors

(a)

The Committee shall have the authority to retain or appoint, at the Company’s expense, internal or external legal, accounting or other advisors and consultants (together, “Outside Experts”) to assist it in carrying out its duties. The Committee shall be directly responsible for the appointment, compensation and oversight of the work of any such Outside Expert. The Committee shall have the authority to terminate such arrangements as appropriate.

(b)

Before receiving advice from an Outside Expert, the Committee must consider the following factors:

i.	the provision of other services to the Company by the person that employs the Outside Expert;
ii.	the amount of fees received from the Company by the person that employs the Outside Expert, as a percentage of the total revenue of the person that employs the Outside Expert;
iii.	the policies and procedures of the person that employs the Outside Expert that are designed to prevent conflicts of interest;
iv.	any business or personal relationship of the Outside Expert with a member of the Committee;
v.	any stock of the Company owned by the Outside Expert; and
vi.	any business or personal relationship of the Outside expert or the person employing the Outside Expert with an Executive Officer of the Company.

(c) To oversee, in conjunction with the Board, engagement with stockholders and proxy advisory firms on executive compensation matters.

General Authority

(a) The Committee may form and delegate authority to subcommittees as appropriate.

(b) The Committee shall also have such other powers and duties as are delegated to it by the Board.

EFFECTIVE DATE

This Charter was implemented by the Board on January 7, 2025

XML

Cover - USD ($)	12 Months Ended
	Sep. 30, 2024	Jan. 14, 2025	Mar. 28, 2024
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Annual Report	true
Document Transition Report	false
Document Period End Date	Sep. 30, 2024
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2024
Current Fiscal Year End Date	--09-30
Entity File Number	001-41558
Entity Registrant Name	PERMEX PETROLEUM CORPORATION
Entity Central Index Key	0001922639
Entity Tax Identification Number	98-1384682
Entity Incorporation, State or Country Code	A1
Entity Address, Address Line One	1700 Post Oak Boulevard
Entity Address, Address Line Two	2 Blvd Place Suite 600
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77056
City Area Code	(346)
Local Phone Number	245-8981
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	true
Elected Not To Use the Extended Transition Period	true
Entity Shell Company	false
Entity Public Float			$ 1,774,686
Entity Common Stock, Shares Outstanding		551,503
Documents Incorporated by Reference [Text Block]	None
ICFR Auditor Attestation Flag	false
Document Financial Statement Error Correction [Flag]	false
Auditor Firm ID	688
Auditor Opinion [Text Block]	We have audited the accompanying consolidated balance sheets of Permex Petroleum Corporation (the “Company”) as of September 30, 2024 and 2023, the related consolidated statements of operations and comprehensive loss, stockholders’ equity and cash flows for each of the two years in the period ended September 30, 2024, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2024 and 2023, and the results of its operations and its cash flows for each of the two years in the period ended September 30, 2024, in conformity with accounting principles generally accepted in the United States of America.
Auditor Name	Marcum LLP
Auditor Location	Houston, Texas

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Consolidated Balance Sheets - USD ($)	Sep. 30, 2024	Sep. 30, 2023
Current assets
Cash	$ 1,513,591	$ 82,736
Trade and other receivables (net of allowance: 2024 - $nil; 2023 - $nil)	44,932	78,441
Prepaid expenses and deposits	146,452	127,239
Total current assets	1,704,975	288,416
Non-current assets
Reclamation deposits	75,000	145,000
Property and equipment, net of accumulated depletion and depreciation	10,281,248	10,361,419
Right of use asset, net		146,912
Total assets	12,061,223	10,941,747
Current liabilities
Trade and other payables	3,786,909	3,228,327
Loans payable	160,936	125,936
Convertible debentures	1,365,000
Debt subscription proceeds	2,250,000
Lease liability – current portion		77,069
Total current liabilities	7,562,845	3,431,332
Non-current liabilities
Asset retirement obligations	392,977	260,167
Lease liability, less current portion		81,456
Total liabilities	7,955,822	3,772,955
Stockholders’ Equity
Common stock, no par value per share; unlimited shares authorized, 551,503 shares* issued and outstanding as of September 30, 2024 and 2023.	14,947,150	14,947,150
Additional paid-in capital	5,475,316	4,549,431
Accumulated other comprehensive loss	(127,413)	(127,413)
Accumulated deficit	(16,189,652)	(12,200,376)
Total stockholders’ equity	4,105,401	7,168,792
Total liabilities and stockholders’ equity	$ 12,061,223	$ 10,941,747

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Consolidated Balance Sheets (Parenthetical) - USD ($)		12 Months Ended
		Sep. 30, 2024	Sep. 30, 2023
Statement of Financial Position [Abstract]
Trade and other receivables, net of allowance
Common stock, par value		$ 0	$ 0
Common stock, shares authorized		Unlimited	Unlimited
Common stock, shares issued	[1]	551,503	551,503
Common stock, shares outstanding	[1]	551,503	551,503

[1] The number of shares has been restated to reflect the 4:1 reverse stock split effective on October 23, 2023 (Note 1). All historical share and per share amounts reflected in this report have been adjusted to reflect the reverse stock split.

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Consolidated Statements of Operations and Comprehensive Loss - USD ($)		12 Months Ended
		Sep. 30, 2024	Sep. 30, 2023
Revenues
Oil and gas sales		$ 100,220	$ 665,623
Royalty income		15,813	23,204
Total revenues		116,033	688,827
Operating expenses
Lease operating expense		196,428	879,471
General and administrative		2,718,975	3,536,118
Depletion and depreciation		82,215	154,834
Accretion on asset retirement obligations		36,792	31,976
Loss on settlement of asset retirement obligations			66,067
Loss on settlement of lease liability		38,825
Write-off of property and equipment		62,046
Total operating expenses		(3,135,281)	(4,668,466)
Loss from operations		(3,019,248)	(3,979,639)
Other income (expense)
Interest income			108
Other income		8,000	24,000
Foreign exchange gain (loss)		133	(3,671)
Change in fair value of warrant liability			22,570
Gain on settlement of warrant liability			930
Interest and debt expense		(483,110)	(4,259)
Loss on debt extinguishment		(495,051)
Total other income (expense)		(970,028)	39,678
Net loss and comprehensive loss		(3,989,276)	(3,939,961)
Deemed dividend arising from warrant modification			(543,234)
Net loss attributable to common stockholders		$ (3,989,276)	$ (4,483,195)
Basic loss and comprehensive loss per common share		$ (7.23)	$ (8.81)
Diluted loss and comprehensive loss per common share		$ (7.23)	$ (8.81)
Weighted average number of common shares outstanding - Basic	[1]	551,503	508,813
Weighted average number of common shares outstanding - Diluted	[1]	551,503	508,813

[1] The number of shares has been restated to reflect the 4:1 reverse stock split effective on October 23, 2023 (Note 1). All historical share and per share amounts reflected in this report have been adjusted to reflect the reverse stock split.

XML

Consolidated Statements of Operations and Comprehensive Loss (Parenthetical)	Oct. 23, 2023
Income Statement [Abstract]
Stockholders equity reverse stock split	4:1

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Consolidated Statements of Changes in Stockholders' Equity - USD ($)		Share Capital [Member]	Additional Paid-in Capital [Member]	AOCI Attributable to Parent [Member]	Retained Earnings [Member]	Total
Balance at Sep. 30, 2022		$ 14,337,739	$ 4,513,194	$ (127,413)	$ (8,260,415)	$ 10,463,105
Balance, shares at Sep. 30, 2022	[1]	483,150
Exercise of warrants		$ 781,953				781,953
Exercise of warrants, shares	[1]	68,353
Share issuance costs		$ (172,542)	35,919			(136,623)
Deemed dividend arising from warrant modification			543,234			543,234
Warrant modification			(543,234)			(543,234)
Share-based payments			318			318
Net loss					(3,939,961)	(3,939,961)
Balance at Sep. 30, 2023		$ 14,947,150	4,549,431	(127,413)	(12,200,376)	7,168,792
Balance, shares at Sep. 30, 2023	[1]	551,503
Net loss					(3,989,276)	(3,989,276)
Warrants issued in private placement			431,666			431,666
Warrants issued for debt amendment			494,219			494,219
Balance at Sep. 30, 2024		$ 14,947,150	$ 5,475,316	$ (127,413)	$ (16,189,652)	$ 4,105,401
Balance, shares at Sep. 30, 2024	[1]	551,503

[1] The number of shares has been restated to reflect the 4:1 reverse stock split effective on October 23, 2023 (Note 1). All historical share and per share amounts reflected in this report have been adjusted to reflect the reverse stock split.

XML

Consolidated Statements of Changes in Stockholders' Equity (Parenthetical)	Oct. 23, 2023
Statement of Stockholders' Equity [Abstract]
Stockholders equity reverse stock split	4:1

XML

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$ (3,989,276)	$ (3,939,961)
Adjustments to reconcile net loss to net cash from operating activities:
Accretion on asset retirement obligations	36,792	31,976
Depletion and depreciation	82,215	154,834
Foreign exchange loss (gain)	(133)
Amortization of debt discount	430,834
Loss on debt extinguishment	495,051
Change in fair value of warrant liability		(22,570)
Gain on settlement of warrant liability		(930)
Loss on settlement of asset retirement obligations		66,067
Share-based payments		318
Loss on settlement of lease liability	38,825
Gain on settlement of trade payables	(185,119)
Write-off of property and equipment	62,046
Changes in operating assets and liabilities:
Trade and other receivables	33,509	58,773
Prepaid expenses and deposits	(19,213)	190,038
Trade and other payables	778,989	1,157,736
Right of use asset and lease liability	(50,438)	7,503
Net cash used in operating activities	(2,285,918)	(2,296,216)
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures on property	(3,227)	(1,445,021)
Reclamation deposit redemption	70,000
Net cash provided by (used in) investing activities	66,773	(1,445,021)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from debenture financing	1,365,000
Proceeds from debt financing subscriptions received	2,250,000
Proceeds from exercise of warrants		781,953
Share issuance costs		(136,623)
Convertible debenture repayment to related party		(38,291)
Loan payable proceeds	45,000
Loan repayment	(10,000)	(83,561)
Net cash provided by financing activities	3,650,000	523,478
Change in cash during the year	1,430,855	(3,217,759)
Cash, beginning of the year	82,736	3,300,495
Cash, end of the year	1,513,591	82,736
Supplemental cash flow disclosures:
Interest paid	2,272	4,259
Taxes paid
Supplemental disclosures of non-cash investing and financing activities:
Share purchase warrants issued in connection with debt issuance	431,666
Share purchase warrants issued in connection with exercise of warrants		579,153
Trade and other payables related to property and equipment		1,299,929
Equipment transferred in settlement with former CEO	35,155
Loan payable issued for settlement		209,497
Changes in estimates of asset retirement obligations	$ (96,018)	$ 7,934

XML

Pay vs Performance Disclosure - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Pay vs Performance Disclosure [Table]
Net Income (Loss)	$ (3,989,276)	$ (3,939,961)

XML

Insider Trading Arrangements	3 Months Ended
	Sep. 30, 2024
Insider Trading Arrangements [Line Items]
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

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BACKGROUND

12 Months Ended

Sep. 30, 2024

Organization, Consolidation and Presentation of Financial Statements [Abstract]

BACKGROUND

1. BACKGROUND

Permex Petroleum Corporation (the “Company”) was incorporated on April 24, 2017 under the laws of British Columbia, Canada and maintains its head office at 1700 Post Oak Boulevard, 2 Blvd Place Suite 600, Houston Texas, 77056. Its registered office is located at 10^th floor, 595 Howe Street, Vancouver, British Columbia, Canada, V6C 2T5. The Company is primarily engaged in the acquisition, development and production of oil and gas properties in the United States. The Company’s oil and gas interests are located in Texas and New Mexico, USA. The Company is listed on the Canadian Securities Exchange (the “CSE”) under the symbol “OIL”.

On September 12, 2023, the Company’s board of directors approved a reverse stock split of the Company’s issued and outstanding common stock at a 1 for 4 ratio, which was effective October 23, 2023. All issued and outstanding common stock, options, and warrants to purchase common stock and per share amounts contained in the financial statements have been retroactively adjusted to reflect the reverse stock splits for all periods presented.

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SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Sep. 30, 2024

Accounting Policies [Abstract]

SIGNIFICANT ACCOUNTING POLICIES

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

The Company’s consolidated financial statements are prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”).

Principles of Consolidation

The accompanying consolidated financial statements include the assets, liabilities, revenue and expenses of the Company’s wholly-owned subsidiary, Permex Petroleum US Corporation. All intercompany balances and transactions have been eliminated.

Going concern of operations

These consolidated financial statements have been prepared on a going concern basis which assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business. The Company has incurred losses since inception in the amount of $16,189,652, has a working capital deficiency of $5,857,870 as of September 30, 2024 and has not yet achieved profitable operations. The Company requires equity or debt financings to fund its continuing operation, which it has been unable to secure in sufficient amounts to date, and there can be no assurances that it will be able to do so in the future. The aforementioned factors raise substantial doubt about the Company’s ability to continue as a going concern within one year after the date that the financial statements are issued.

The Company expects to raise additional funds through equity and debt financings. There is no assurance that such financing will be available in the future. During the year ended September 30, 2024, the Company raised $1,365,000 through the issuance of convertible debentures and received additional proceeds of $2,250,000 from debt financing subscriptions. Subsequent to September 30, 2024, the Company received further subscription proceeds of $601,601 to complete a convertible debenture financing with total gross proceeds of $4,276,389. The $1,365,000 convertible debentures that matured on September 12, 2024 and accrued interest of $59,788 were retired in exchange for the new convertible debenture units. Management believes that these actions provide a path for the Company to continue as a going concern subject to its continued ability to raise funds to maintain its operations and manage its working capital deficiency.

In view of these matters, continuation as a going concern is dependent upon continued operations of the Company, which in turn is dependent upon the Company’s ability to meet its financial requirements, raise additional capital, and the success of its future operations. The financial statements do not include any adjustments to the amount and classification of assets and liabilities that may be necessary should the Company not continue as a going concern.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. Significant Accounting Policies (cont’d…)

Use of Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities at the date of the financial statements and the reported amount of revenue and expenses during the reporting period. Management evaluates these estimates and judgments on an ongoing basis and bases its estimates on experience, current and expected future conditions, third-party evaluations and various other assumptions that management believes are reasonable under the circumstances.

Significant estimates have been used by management in conjunction with the following: (i) the fair value of assets when determining the existence of impairment factors and the amount of impairment, if any; (ii) the costs of site restoration when determining decommissioning liabilities; (iii) the useful lives of assets for the purposes of depletion and depreciation; (iv) petroleum and natural gas reserves; and (v) share-based payments. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, and makes adjustments when facts and circumstances dictate. These estimates are based on information available as of the date of the financial statements; therefore, actual results could differ from those estimates.

Cash and cash equivalents

The Company considers all highly liquid investments with an original maturity of three months or less when purchased to be cash and cash equivalents. Cash and cash equivalents are recorded at cost, which approximates fair value. The Company had no cash equivalents as of September 30, 2024 and 2023.

Trade and other receivables

Trade and other receivables are stated at net realizable value. The majority of customers have payment terms of 30 days or less. The Company’s oil and gas revenues are mainly derived from three significant customers. As a result, the Company’s trade receivables are exposed to a concentration of credit risk. The Company routinely assesses the financial strength of its customers. On a periodic basis, management evaluates its accounts receivable and determines whether to provide an allowance or if any accounts should be written off based on a past history of write-offs, collections, and current credit conditions. A receivable is considered past due if the Company has not received payments based on agreed-upon terms.

Property and equipment

The Company follows the successful efforts method of accounting for its oil and gas properties. All costs for development wells along with related acquisition costs, the costs of drilling development wells, and related estimated future asset retirement costs are capitalized. Exploration costs, such as exploratory geological and geophysical costs, and costs associated with non-productive exploratory wells, delay rentals and exploration overhead are expensed. Costs of drilling exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company groups its oil and gas properties with a common geological structure or stratigraphic condition (“common operating field”) for purposes of computing depletion expenses, assessing proved property impairments and accounting for asset dispositions.

Capitalized costs of proved oil and gas properties are depleted by individual field using a unit-of-production method based on proved and probable developed reserves. Proved reserves are estimated using reserve engineer reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids, which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. Significant Accounting Policies (cont’d…)

Property and equipment (cont’d…)

Proved oil and natural gas properties are assessed for possible impairment by comparing their carrying values with their associated undiscounted future net cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset (including changes to the commodity price forecast or carbon costs), significant change in the extent or manner of use of or a physical change in an asset, and a more-likely-than-not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted, future net cash flows. For proved oil and natural gas properties, the Company performs impairment reviews on a field basis, annually or as appropriate.

Other corporate property and equipment consist primarily of leasehold improvements, vehicle, and office furniture and equipment and are stated at cost less accumulated depreciation. The capitalized costs are generally depreciated on a straight line basis over their estimated useful lives ranging from three to five years.

For property dispositions, measurement is at fair value, unless the transaction lacks commercial substance or fair value cannot be reliably measured. Where the exchange is measured at fair value, a gain or loss is recognized in net income.

Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s depletion rate. These gains and losses are classified as asset dispositions in the accompanying consolidated statements of loss and comprehensive loss. Partial common operating field sales or dispositions deemed not to significantly alter the depletion rates are generally accounted for as adjustments to capitalized costs with no gain or loss recognized.

Impairment of long-lived assets

The Company assesses long-lived assets for impairment in accordance with the provisions of the Financial Accounting Standards Board Accounting Standards Codification (“ASC”) regarding long-lived assets. It requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable through the estimated undiscounted cash flows expected to result from the use and eventual disposition of the assets. Whenever any such impairment exists, an impairment loss will be recognized for the amount by which the carrying value exceeds the fair value. As of September 30, 2024 and 2023, no impairment charge has been recorded.

Asset retirement obligations

The Company recognizes asset retirement obligations (“ARO”) associated with tangible assets such as well sites when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The ARO are measured at the present value of management’s best estimate of the future remediation expenditures at the reporting date. The initial measurement of an ARO is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumption used to estimate a recorded ARO change, a revision is recorded to both the ARO and the asset retirement cost. The ARO is accreted to its then present value each period, and the asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. SIGNIFICANT ACCOUNTING POLICIES (cont’d…)

Fair value measurement

Fair value accounting is applied for all assets and liabilities and nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Fair value is defined as the exchange price that would be received for an asset or an exit price that would be paid to transfer a liability in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The Company follows the established framework for measuring fair value and expands disclosures about fair value measurements.

The Company categorizes its assets and liabilities measured at fair value into a three-level hierarchy based on the priority of the inputs to the valuation technique used to determine fair value. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used in the determination of the fair value measurement fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement.

Assets and liabilities valued at fair value are categorized based on the inputs to the valuation techniques as follows:

Level 1 – Inputs that utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access.

Level 2 – Inputs that include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. Fair values for these instruments are estimated using pricing models, quoted prices of securities with similar characteristics, or discounted cash flows.

Level 3 – Inputs that are unobservable inputs for the asset or liability, which are typically based on an entity’s own assumptions, as there is little, if any, related market activity.

The carrying values of cash, trade receivable, other current receivables, due from/to related parties, trade payable, other current payables, accrued expenses, convertible debenture and lease liability included in the accompanying consolidated balance sheets approximated fair value at September 30, 2024 and 2023. The financial statements as of and for the years ended September 30, 2024 and 2023, do not include any recurring or nonrecurring fair value measurements relating to assets or liabilities.

Subsequent to initial recognition, the Company may re-measure the carrying value of assets and liabilities measured on a nonrecurring basis to fair value. Adjustments to fair value usually result when certain assets are impaired. Such assets are written down from their carrying amounts to their fair value.

Professional standards allow entities the irrevocable option to elect to measure certain financial instruments and other items at fair value for the initial and subsequent measurement on an instrument-by-instrument basis. The Company has not elected to measure any existing financial instruments at fair value. However, it may elect to measure newly acquired financial instruments at fair value in the future.

Earnings (loss) per share

Basic earnings (loss) per share (“EPS”) is calculated by dividing net income (loss) attributable to common shareholders by the weighted average number of common shares outstanding in the period. The diluted EPS reflects all dilutive potential common share equivalents, in the weighted average number of common shares outstanding during the period, if dilutive. All of the outstanding convertible securities, stock options and warrants were anti-dilutive for the years ended September 30, 2024 and 2023.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. SIGNIFICANT ACCOUNTING POLICIES (cont’d…)

Leases

At inception of a contract, the Company assesses whether a contract is or contains a lease based on whether the contract conveys the right to control the use of an identified asset for a period in exchange for consideration.

The Company recognizes a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured based on the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date.

The lease obligation is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Company’s incremental borrowing rate. Generally, the Company uses its incremental borrowing rate as the discount rate. Variable lease payments that do not depend on an index or rate are not included in the measurement of the lease liability. The lease liability is subsequently measured at amortized cost using the effective interest rate method.

Share capital

The Company records proceeds from the issuance of its common shares as equity. Incremental costs directly attributable to the issue of new common shares are shown in equity as a deduction from the proceeds. Common shares issued for consideration other than cash are valued based on their fair value at the date that the shares are issued.

Share purchase warrants

The fair value of warrants is determined using the Black-Scholes option pricing model. Proceeds from the issuance of private placement units are allocated between the private placement warrants and common shares on a relative fair value basis. Share purchase warrants with exercise prices denominated in a currency other than its functional currency are classified as a liability. Proceeds from the issuance of private placement units are first allocated to the warrant liability based on their fair value and the residual is allocated to common shares issued while for equity warrants, proceeds are allocated to common stock and additional paid in capital on a relative fair value basis. The changes in fair value of the warrant liability are recorded in the statement of loss and comprehensive loss.

Warrants issued for oil and gas interests and warrants issued as finder’s fees are share-based payments and are measured at fair value on the date of the grant as determined using the Black-Scholes option pricing model.

Share-based payments

The Company issues stock options and other share-based compensation to directors, employees and other service providers. Equity awards including stock options and share purchase warrants are measured at grant date at the fair value of the instruments issued and amortized over the vesting periods using a graded vesting approach. The number of options expected to vest is reviewed and adjusted at the end of each reporting period such that the amount ultimately recognized as an expense is based on the number of options that eventually vest. The Company has elected to account for forfeitures as they occur rather than estimate expected forfeitures.

The fair value of the equity awards is determined using the Black-Scholes option pricing model. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility (based on weighted average historic volatility), weighted average expected life of the instruments (based on historical experience), expected dividends, and the risk-free interest rate (based on government bonds).

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. SIGNIFICANT ACCOUNTING POLICIES (cont’d…)

Revenue

In accordance with ASC 606, Revenue from Contracts with Customers, the Company recognizes revenue when the performance obligation is satisfied, which typically occurs at the point in time when control of the product transfer to the customer. For natural gas, this is generally at the time product enters the pipeline. For crude oil, this is generally at the time the product is loaded into customer operated transports. Revenue is measured net of discounts, customs duties, royalties and withholding tax. Royalty income represents net revenue interests from certain crude oil and natural gas wells and is recognized upon the operators of the properties producing revenue from subject oil and gas wells.

The Company records revenue in the month production is delivered to the purchaser. However, production statements for oil and gas sales may not be received until the following month end after the products are purchased, and as a result, the Company is required to estimate the amount of revenue to be received. The Company records the differences between its estimates and the actual amounts received for revenue in the month that payment is received from the customer. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to sales volumes and prices for those good sold are estimated and recorded.

The Company does not have any contract assets or liabilities, or capitalized contract costs.

Foreign Currency

These consolidated financial statements are presented in United States dollars (“U.S. dollar”). The functional currency of the Company and the subsidiary of the Company is the U.S. dollar. Foreign currency transactions are translated into the functional currency using exchange rates prevailing at the dates of the transactions. At the end of each reporting period, monetary assets and liabilities that are denominated in foreign currencies are translated at the rates prevailing at that date. All gains and losses on these foreign currency transactions are charged to profit or loss.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. SIGNIFICANT ACCOUNTING POLICIES (cont’d…)

Income taxes

Current taxes receivable or payable are estimated on taxable income or loss for the current year at the statutory tax rates enacted or substantively enacted at the reporting date.

Deferred income tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Deferred income tax assets and liabilities are measured at the tax rates that have been enacted or substantially enacted at the end of the reporting period and are expected to apply when the related deferred income tax asset is realized or the deferred income tax liability is settled. Deferred income tax assets also result from unused loss carry forwards, resource related pools and other deductions. At the end of each reporting year the Company reassesses unrecognized deferred tax assets. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Deferred income tax assets and deferred income tax liabilities are offset if a legally enforceable right exists to offset current tax assets against current tax liabilities and the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority.

The Company recognizes a tax benefit in the financial statements for an uncertain tax position only if management assesses that the position is more likely than not (i.e., a likelihood greater than 50%) to be allowed by the tax jurisdiction, based solely on the technical merits of the position. The term “tax position,” as defined in the accounting standards for income taxes, refers to a position in a previously filed tax return or a position expected to be taken in a future tax return. This position is reflected in the measurement of current or deferred income tax assets and liabilities for interim or annual periods.

New accounting standards

In November 2023, the FASB issued ASU 2023 - 07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which becomes effective for fiscal years beginning after December 15, 2024. This update requires public entities to disclose significant expenses for reportable segments in both interim and in annual reporting periods, while entities with only a single reportable segment must now provide all segment disclosures required both in ASC 280 and under the amendments in ASU 2023-07. The Company does not expect the standard to have a material effect on its consolidated financial statements and has begun evaluating disclosure presentation alternatives.

In December 2023, the FASB issued ASU 2023 - 09, Income Taxes (Topic740) Improvements to Income Tax Disclosures, which becomes effective for fiscal years beginning after December 15, 2024. The standard requires companies to disclose specific categories in the income tax rate reconciliation table and the amount of income taxes paid per major jurisdiction. The Company does not expect the standard to have a material effect on its consolidated financial statements and has begun evaluating disclosure presentation alternatives.

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REVENUE

12 Months Ended

Sep. 30, 2024

Revenue from Contract with Customer [Abstract]

REVENUE

3. REVENUE

Revenue from contracts with customers is presented in “Oil and gas sales” on the Consolidated Statement of Operations.

As of September 30, 2024 and 2023, receivables from contracts with customers, included in trade and other receivables, were $26,873 and $48,165, respectively.

The following tables present our revenue from contracts with customers disaggregated by product type and geographic area.

Year ended September 30, 2024	Texas		New Mexico		Total
Crude oil	$	64,611	$	35,609	$	100,220
Natural gas		-		-		-
Revenue from contracts with customers	$	64,611	$	35,609	$	100,220

Year ended September 30, 2023	Texas		New Mexico		Total
Crude oil	$	501,920	$	154,700	$	656,620
Natural gas		9,003		-		9,003
Revenue from contracts with customers	$	510,923	$	154,700	$	665,623

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

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CONCENTRATION OF CREDIT RISK

12 Months Ended

Sep. 30, 2024

Risks and Uncertainties [Abstract]

CONCENTRATION OF CREDIT RISK

4. CONCENTRATION OF CREDIT RISK

The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash and trade receivables. The Company’s cash balances sometimes exceed the United States’ Federal Deposit Insurance Corporation insurance limits. The Company mitigates this risk by placing its cash with high credit quality financial institutions and attempts to limit the amount of credit exposure with any one institution. To date, the Company has not recognized any losses caused by uninsured balances.

Trade receivables included in the Company’s receivable balance are $26,873 as of September 30, 2024 (September 30, 2023 - $73,021). For the years ended September 30, 2024 and 2023, we had two significant customers that accounted for approximately 100% and 99%, respectively, of our total oil, and natural gas revenues. The Company routinely assesses the financial strength of its customers. The non-trade receivable balance consists of goods and services tax (“GST”) recoverable of $18,060 (September 30, 2023 - $5,420). GST recoverable is due from the Canadian Government. It is management’s opinion that the Company is not exposed to significant credit risk. During the year ended September 30, 2024, the Company recognized $9,587 (2023 - $nil) in credit losses on its other receivables.

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PROPERTY AND EQUIPMENT

12 Months Ended

Sep. 30, 2024

Property, Plant and Equipment [Abstract]

PROPERTY AND EQUIPMENT

5. PROPERTY AND EQUIPMENT

Property and equipment consisted of the following:

	September 30, 2024			September 30, 2023
Oil and natural gas properties, at cost	$	10,600,489		$	10,501,244
Less: accumulated depletion		(330,036	)		(289,456	)
Oil and natural gas properties, net		10,270,453			10,211,788
Other property and equipment, at cost		18,505			205,315
Less: accumulated depreciation		(7,710	)		(55,684	)
Other property and equipment, net		10,795			149,631
Property and equipment, net	$	10,281,248		$	10,361,419

Depletion and depreciation expenses were $82,215 and $154,834 for the years ended September 30, 2024 and 2023, respectively. The Company also recorded write-offs of property and equipment of $62,046 and $nil for the years ended September 30, 2024 and 2023, respectively

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

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LEASES

12 Months Ended

Sep. 30, 2024

Leases

LEASES

6. LEASES

All of the Company’s right-of-use assets are operating leases related to its office premises. Details of the Company’s right-of-use assets and lease liabilities are as follows:

	September 30, 2024			September 30, 2023
Right-of-use assets	$	-		$	146,912
Lease liabilities
Balance, beginning of the year	$	158,525		$	244,906
Addition		-			-
Liability accretion		12,346			24,221
Lease payments		(113,638	)		(110,602	)
Termination of lease		(57,233	)		-
Balance, end of the year	$	-		$	158,525
Current lease liabilities	$	-		$	77,069
Long-term lease liabilities	$	-		$	81,456
Weighted-average remaining lease term (in years)		-			2.17
Weighted-average discount rate		-	%		12	%

The following table presents the Company’s total lease cost.

	2024		2023
Operating lease cost	$	63,200	$	118,105
Variable lease expense		51,062		65,245
Sublease income		-		(25,390	)
Net lease cost	$	114,262	$	157,960

The Company had one office lease agreement for its office premises for terms ending in November 2025. During the year ended September 30, 2024, the Company entered into a settlement agreement to terminate the office lease agreement. The termination resulted in a loss of $38,825, consisting of the settlement payment and the write-off of the remaining right-of-use asset and lease liability associated with the terminated lease.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

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ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Sep. 30, 2024

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATIONS

7. ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties. Changes to the asset retirement obligations are as follows:

	2024		2023
Asset retirement obligations, beginning of the year	$	260,167	$	236,412
Obligations recognized		27,859		-
Obligations derecognized		-		(287	)
Revisions of estimates		68,159		(7,934	)
Accretion expense		36,792		31,976
	$	392,977	$	260,167

During the year ended September 30, 2024, the Company had a revision of estimates totaling $68,159 (2023 - $7,934) primarily due to changes in the timing of expected cash flows. During the year ended September 30, 2023, the Company incurred plugging and abandonment costs of $66,354 and recognized a loss of $66,067 on the settlement.

Reclamation deposits

As of September 30, 2024, the Company held reclamation deposits of $75,000 (September 30, 2023 - $145,000), which are expected to be released after all reclamation work has been completed with regard to its oil and natural gas interests. During the year ended September 30, 2024, the Company redeemed $70,000 in reclamation deposits.

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DEBT

12 Months Ended

Sep. 30, 2024

Debt Disclosure [Abstract]

DEBT

8. DEBT

Convertible debentures

During the year ended September 30, 2024, the Company completed private placement financings of 1,365 convertible debenture units (each a “Unit”) for gross proceeds of $1,365,000. Each Unit is comprised of one senior secured convertible debenture in the principal amount of $1,000 and 294 common share purchase warrants as amended. Each warrant is exercisable for a period of five years from the date of issuance for one common share of the Company at an exercise price of $4.08 per share. As a result, the Company issued convertible debentures with an aggregate principal amount of $1,365,000 and 401,310 Warrants.

Of the 1,365 Units issued, 500 Units were originally comprised of one secured convertible debenture in the principal amount of $1,000 and 1 common share purchase warrant. The number of warrants issued with these Units was subsequently modified to 294 warrants per Unit. No other terms of the debt or warrant were modified. This modification was assessed as a debt extinguishment. A loss of $495,051 was recognized, consisting of $494,219 representing the fair value of the amended warrants determined using the Black-Scholes option pricing model (assuming a risk-free interest rate of 3.41%, an expected life of 5 years, annualized volatility of 128.69% and a dividend rate of 0%) and an unamortized discount of $832 on the original warrants.

The Company allocated the proceeds received from the issuance of the convertible debentures and warrants between the debt and equity components based on their relative fair values at the issuance date. Due to the lack of an active market for the Company’s privately placed debt instruments and the absence of relevant observable inputs, the Company determined that a reliable estimate of the fair value of the convertible debentures could not be obtained. Accordingly, the face value of the debentures is considered to be a reasonable approximation of their fair value at the issuance date. The fair value of the warrants issued was determined using the Black-Scholes option pricing model (assuming a risk-free interest rate of 3.41%, an expected life of 5 years, annualized volatility of 128.69% and a dividend rate of 0%). $431,666 of the proceeds allocated to the warrants was recorded as additional paid-in capital with a corresponding debt discount, which is being amortized over the term of the debt. As of September 30, 2024, the debt discount was fully amortized.

The Convertible Debentures were secured by the Company’s assets, bore simple interest at a rate of 10% per annum, and matured on September 12, 2024. These Convertible Debentures were convertible into common shares of the Company at a conversion price of $3.40 per share. Interest was payable on the maturity date or upon the repayment of all or a portion of the Convertible Debenture and could be settled in cash or shares at the same conversion price. As of September 30, 2024, the Company had recorded $50,008 in accrued interest on the Convertible Debentures.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

8. DEBT (cont’d…)

As September 30, 2024, the following Convertible Debentures were outstanding:

Principal Amount		Interest rate			Maturity Date
$	500,000		10	%	September 12, 2024
	865,000		10	%	September 12, 2024
$	1,365,000

As of September 30, 2024, these Convertible Debentures were in default due to the Company’s failure to repay the principal and accrued interest by the maturity date. Subsequent to September 30, 2024, the Company repaid the Convertible Debentures and the accrued interest in full.

Proceeds from debt financing subscriptions

In September 2024, the Company announced a non-brokered private placement of up to 18,635 convertible debenture units of the Company (each, a “Unit”). Each Unit consists of one convertible debenture (a “Debenture”) in the principal amount of $1,000 and 523 common share purchase warrants. Each warrant is exercisable for a period of five years from the date of issuance for one common share of the Company at an exercise price of $1.91 per share. The Debentures will be secured by the Company’s assets, mature one-year from the date of issuance, and bear simple interest at a rate of 10% per annum, payable on the maturity date or upon repayment of all or any portion of the Debenture. The Debentures are convertible into common shares of the Company at a conversion price of $1.91 per share. Interest will be payable in cash or shares based on the same conversion price. As of September 30, 2024, the Company had received subscription proceeds totaling $2,250,000. The private placement was completed on November 1, 2024 for total gross proceeds of $4,276,389 (Note 15).

Loan payable

During the year ended September 30, 2024, the Company received a $45,000 loan from a former director of the Company. The loan is unsecured, non-interest bearing, and has no specific repayment terms.

On April 28, 2023, the Company issued a promissory note with a principal amount of $209,497 to a supplier to settle an outstanding trade payable. The promissory note is unsecured and bears interest at 6% per annum, payable on September 30, 2023. At September 30, 2024, the Company has an outstanding unpaid principal amount of $115,936 (September 30, 2023 - $125,936). The promissory note was in default due to the Company’s failure to repay the principal amount by its maturity date.

Debenture loan – Related party

During the year ended September 30, 2023, the Company repaid the remaining principal amount of $38,291 (CAD$52,454) on the debenture loan due to the former CEO of the Company. During the years ended September 30, 2023, the Company recorded interest of $1,182.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

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RELATED PARTY TRANSACTIONS

12 Months Ended

Sep. 30, 2024

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

9. RELATED PARTY TRANSACTIONS

(a)	The Company entered into an employment agreement with Bradley Taillon, the Company’s Chief Executive Officer, on April 29, 2024, for an annual base salary of base salary of $250,000, which shall be reviewed by the Company annually. Subject to the discretion of the board of directors, Mr. Taillon is also eligible on an annual basis for a cash bonus of up to 100% of annual salary and additional performance bonuses ranging from $50,000 to $750,000 upon the closing of a qualified financing with proceeds to the Company of $1 million or greater. Further, the terms of this employment agreement provide that if Mr. Taillon’s employment with the Company is terminated without “cause” (as defined in the agreement) than Mr. Taillon is entitled to a severance payment equal to two years of base salary and a bonus equal to 50% of his annual base salary. During the year ended September 30, 2024, the Company incurred management salary of $122,312 and a one-time sign-on bonus of $50,000 for Mr. Taillon.
(b)	The Company had an employment agreement with Mehran Ehsan, the former Chief Executive Officer of the Company, for an annual base salary of $250,000, with no specified term. Mr. Ehsan was also eligible on an annual basis for a cash bonus of up to 100% of annual salary, subject to the discretion of the board of directors. During the year ended September 30, 2024, the Company incurred management salary of $229,167 (2023 - $250,000), for Mr. Ehsan, with no bonuses incurred in either period. Further, the terms of this employment agreement provided that if Mr. Ehsan’s employment with the Company is terminated without “cause” (as defined in the agreement) than Mr. Ehsan was entitled to a severance payment equal to three years of base salary and a bonus equal to 20% of his annual base salary. Mr. Ehsan resigned as President and CEO of the Company on April 29, 2024. On May 15, 2024, the Company amended the employment agreement to change his role to Vice President of Business Development. All other terms and conditions of the employment agreement remained the same. On August 30, 2024, the Company signed a separation agreement to terminate Mr. Ehsan’s employment. The settlement includes: i) a lump sum payment of $100,000 by October 31, 2024 (subsequently paid); ii) six equal monthly payments of $7,500 starting October 1, 2024; and iii) the transfer of ownership of a Company vehicle with a fair value of $35,155. The settlement amount of $145,000 was accrued as of September 30, 2024.
c)	On May 1, 2022, the Company entered into an employment agreement with the CFO of the Company for an annual base salary of $50,000, with no specified term. The CFO is also eligible on an annual basis for a cash bonus of up to 100% of annual salary, subject to the discretion of the board of directors. The employment agreement may be terminated with a termination payment equal to two months of base salary. During the year ended September 30, 2024, the Company incurred management salary of $50,000 (2023 - $50,000), to the CFO of the Company, with no bonuses incurred in either period.
d)	The convertible debenture loan from the former CEO of the Company mentioned in Note 8 was repaid off during the year ended September 30, 2023.

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LOSS PER SHARE

12 Months Ended

Sep. 30, 2024

Earnings Per Share [Abstract]

LOSS PER SHARE

10. LOSS PER SHARE

The calculation of basic and diluted loss per share for the years ended September 30, 2024 and 2023 was based on the net losses attributable to common shareholders. The following table sets forth the computation of basic and diluted loss per share:

	2024			2023
Net loss	$	(3,989,276	)	$	(4,483,195	)
Weighted average common shares outstanding		551,503			508,813
Basic and diluted loss per share	$	(7.23	)	$	(8.81	)

For the year ended September 30, 2024, 10,105 stock options, 676,663 warrants, and $1,365,000 of convertible debentures convertible into 401,471 common shares were excluded from the diluted weighted average number of common shares calculation as their effect would have been anti-dilutive.

For the year ended September 30, 2023, 20,313 stock options and 279,746 warrants were excluded from the diluted weighted average number of common shares calculation as their effect would have been anti-dilutive.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

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EQUITY

12 Months Ended

Sep. 30, 2024

Equity [Abstract]

EQUITY

11. EQUITY

Common stock

The Company has authorized an unlimited number of common shares with no par value. At September 30, 2024 and 2023, the Company had 551,503 common shares issued and outstanding after giving effect to the 4:1 reverse stock split effective October 23, 2023. All issued and outstanding common stock, options, and warrants to purchase common stock and per share amounts contained in the financial statements have been retroactively adjusted to reflect the reverse stock split.

There were no share issuance transactions during the year ended September 30, 2024

During the year ended September 30, 2023, the Company announced a warrant exercise incentive program (the “Program”) whereby the Company amended the exercise prices of 253,966 warrants (the “Eligible Warrants”) from $50.40 per share to $11.44 per share if the holders of the Eligible Warrants exercised the Eligible Warrants before June 30, 2023 (the “Program Period”). In addition to the repricing, the Company offered, to each warrant holder who exercised the Eligible Warrants during the Program Period, the issuance of one additional common share purchase warrant for each warrant exercised during the Program Period (each, an “Incentive Warrant”). Each Incentive Warrant entitles the warrant holder to purchase one common share of the Company for a period of 5 years from the date of issuance, at a price of $18.00 per Share.

On June 30, 2023, the Company issued 68,353 common shares at a price of $11.44 per share from the exercise of the Eligible Warrants pursuant to the Program for gross proceeds of $781,953 (net proceeds of $645,330). In connection with the Program, the Company issued 68,353 Incentive Warrants. The Company also incurred $62,556 and issued 5,470 warrants as a finders’ fee to its investment bank. The finder’s warrants are on the same terms as the Incentive Warrants. The Incentive Warrants and finder’s warrants were valued at $449,005 and $35,919, respectively, using the Black-Scholes option pricing model (assuming a risk-free interest rate of 3.68%, an expected life of 5 years, annualized volatility of 128.81% and a dividend rate of 0%). The repricing of the Eligible Warrants is accounted for as a modification under ASC 815-40-35-14 through 18. The effect of the modification is $544,164, measured as the excess of the fair value of the repriced warrants over the fair value of the original warrants immediately before it was modified and the fair value of the incentive warrants issued as an additional inducement to exercise the warrants. The fair values were measured using the Black-Scholes option pricing model (assuming a risk-free interest rate of 4.21%, an expected life of 3.75 years, annualized volatility of 137.62% and a dividend rate of 0%). The Company recognized a deemed dividend of $543,234 for the fair value of the Incentive Warrants and the portion of inducement related to the equity-classified warrants. The effect of the repricing of the liability-classified warrants was $930 and was recorded in the statement of operations and comprehensive loss. The Company also incurred legal and other expenses of $74,066 in connection with the Program.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

11. EQUITY (cont’d…)

Share-based payments

Stock options

The Company has a stock option plan (the “SOP”) in place under which it is authorized to grant options to executive officers and directors, employees and consultants. Pursuant to the SOP, the Company may issue aggregate stock options totaling up to 10% of the issued and outstanding common stock of the Company. Further, the SOP calls for the exercise price of each option to be equal to the market price of the Company’s stock as calculated on the date of grant. The options can be granted for a maximum term of 10 years and vest at the discretion of the Board of Directors at the time of grant.

Stock option transactions are summarized as follows:

	Number of options			Weighted Average Exercise Price
Balance, September 30, 2022		21,146		$	53.04
Cancelled		(833	)		42.62
Balance, September 30, 2023		20,313		$	54.23
Cancelled		(10,208	)		55.24
Balance, September 30, 2024		10,105		$	53.21
Exercisable at September 30, 2024		10,105		$	53.21

The aggregate intrinsic value of options outstanding and exercisable as of September 30, 2024 was $nil (September 30, 2023 - $nil).

The options outstanding as of September 30, 2024 have exercise prices in the range of $8.88 to $88.80 and a weighted average remaining contractual life of 5.6 years.

During the year ended September 30, 2024, the Company recognized $nil share-based payment expense. During the year ended September 30, 2023, the Company recognized share-based payment expense of $nil and $318, respectively, for the portion of stock options that vested during the year.

As September 30, 2024, the following stock options were outstanding:

Number of Options		Exercise Price		Issuance Date	Expiry Date
	3,230	$	88.88	December 4, 2017	December 4, 2027
	1,250	$	8.88	March 16, 2020	March 16, 2030
	5,625	$	42.62	October 6, 2021	October 6, 2031
	10,105

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

11. EQUITY (cont’d…)

Share-based payments (cont’d…)

Warrants

Warrant transactions are summarized as follows:

	Number of Warrants			Weighted Average Exercise Price
Balance, September 30, 2022		274,276		$	48.48
Exercised		(68,353	)		11.44
Granted		73,823			18.00
Balance, September 30, 2023		279,746		$	39.79
Granted		401,810			4.08
Cancelled		(500	)		4.08
Expired		(4,393	)		95.90
Balance, September 30, 2024		676,663		$	18.25

As September 30, 2024, the following warrants were outstanding:

Number of Warrants		Exercise Price		Issuance Date	Expiry Date
	149,447	$	50.40	March 29, 2022	March 29, 2027
	73,823	$	18.00	June 30, 2023	June 30, 2028
	147,000	$	4.08	April 16, 2024	April 16, 2029
				(Subsequently cancelled – Note 15)
	254,310	$	4.08	June 12, 2024	June 12, 2029
				(Subsequently cancelled – Note 15)
	52,083	$	35.52	September 30, 2021	September 30, 2031
	676,663

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

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INCOME TAXES

12 Months Ended

Sep. 30, 2024

Income Tax Disclosure [Abstract]

INCOME TAXES

12. INCOME TAXES

	2024			2023
Loss before income taxes	$	(3,989,276	)	$	(3,939,961	)
Expected income tax recovery at statutory rates	$	(598,000	)	$	(591,000	)
Provincial income tax recovery		(373,000	)		(290,000	)
Effect of income taxes from US operations		(58,000	)		(100,000	)
Change in statutory, foreign tax, foreign exchange rates and other		(3,000	)		(18,000	)
Permanent differences – debt discount		116,000			-
Permanent differences – debt extinguishment		134,000			-
Permanent differences - Other		11,000			3,000
Adjustment to prior years provision versus statutory tax returns		3,000			(43,000	)
Change in valuation allowance		768,000			1,039,000
Deferred income tax recovery	$	-		$	-

Components of the Company’s pre-tax loss and income taxes are as follows:

	2024			2023
Loss for the year
Canada	$	(3,110,348	)	$	(2,418,491	)
US		(878,928	)		(1,521,470	)
	$	(3,989,276	)	$	(3,939,961	)
Expected income tax (recovery)
Canada	$	(589,000	)	$	(659,000	)
US		(177,000	)		(319,000	)
	$	(766,000	)	$	(978,000	)
Deferred income tax
Canada	$	589,000		$	659,000
US		177,000			319,000
	$	766,000		$	978,000
Deferred income tax recovery	$	-		$	-

The significant components of the Company’s deferred tax assets and liabilities are as follows:

	2024			2023
Tax loss carryforwards	$	3,037,000		$	2,313,000
Property and equipment		15,000			39,000
Financing fees		130,000			191,000
Accrued liabilities		129,000			-
		3,311,000			2,543,000
Deferred tax assets valuation allowance		(3,311,000	)		(2,543,000	)
Net deferred tax assets	$	-		$	-

The significant components of the Company’s temporary differences include unamortized financing fees and tax loss carryforwards. The valuation allowance reduces the deferred tax assets to amounts that are, in management’s assessment, more likely than not to be realized. This conclusion is primarily due to the Company’s history of cumulative losses and its expectation of continued losses in the foreseeable future. The Company had tax loss carryforwards of approximately $11,991,000 in Canada and the United States. For the years ended September 30, 2024 and 2023, the Canada tax loss carryforwards totaled $9,421,000 and $7,019,000, respectively, with expiration dates ranging from 2037 to 2043 and 2037 to 2042, respectively. The United States tax loss carryforwards for the years ended September 30, 2024 and 2023 totaled $2,569,000 and $2,367,000, respectively, and had no expiration dates, subject to 80% of taxable income. The United States tax loss carryforwards include $290,000 attributable to New Mexico state tax losses, with expiration dates ranging from 2037 to 2043.

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SEGMENT INFORMATION

12 Months Ended

Sep. 30, 2024

Segment Reporting [Abstract]

SEGMENT INFORMATION

13. SEGMENT INFORMATION

Operating segments

The Company operates in a single reportable segment – the acquisition, development and production of oil and gas properties in the United States.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

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CONTINGENCIES

12 Months Ended

Sep. 30, 2024

Commitments and Contingencies Disclosure [Abstract]

CONTINGENCIES

14. CONTINGENCIES

The Company from time to time may be involved with disputes, claims and litigation related to the conduct of its business. The Company had $545,505 in claims from certain trade vendors for non-payment, of which $499,162 have been accrued as of September 30, 2024. The Company plans to continue engaging with these claimants faithfully and is working on potential settlements for all outstanding claims.

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SUBSEQUENT EVENTS

12 Months Ended

Sep. 30, 2024

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

15. SUBSEQUENT EVENTS

i) On October 2, 2024, the Company granted stock options to directors and officers of the Company to purchase 65,000 common shares at an exercise price of $2.44 per share for a period of 10 years.

ii) On November 1, 2024, the Company closed the first tranche of a non-brokered private placement of convertible debenture units of the Company announced in September 2024 for gross proceeds of $4,276,389, of which $2,250,000 was received as subscriptions as of September 30, 2024, and $1,424,788 was issued in exchange for the outstanding debentures in the principal amount of $1,365,000 and accrued interest of $59,788. Each debenture unit consists of one convertible debenture (a “Debenture”) in the principal amount of $1,000 and 523 common share purchase warrants. Each warrant is exercisable for a period of five years from the date of issuance for one common share of the Company (a “Share”) at an exercise price of $1.91 per share. As a result, the Company issued convertible debentures with an aggregate principal amount of $4,276,389 and 2,236,551 Warrants. The Debentures are secured by the Company’s assets, mature one-year from the date of issuance, and bear simple interest at a rate of 10% per annum, payable on the maturity date or upon repayment of all or any portion of the Debenture. The Debentures are convertible into common shares of the Company at a conversion price of $1.91 per share. Interest is payable in cash or shares based on the same conversion price.

iii) In October 2024, the Company retired its previously outstanding debentures of $1,365,000 along with accrued interest of $59,788 in exchange for the new debenture units. The debenture holders also agreed to cancel a total of 401,310 warrants issued in connection with the debentures. This exchange was assessed as a debt extinguishment and a loss of $105,349 was recognized in October 2024.

iv) The Company’s Long Term Incentive Plan was approved by Board on October 2, 2024, which Long Term Incentive Plan was amended and such amended plan was approved by the Board on October 23, 2024 (as amended, the “Long Term Incentive Plan”) and was approved by shareholders at the Company’s Annual General Meeting of Shareholders on November 4, 2024. The Board approved the adoption of the Long-Term Incentive Plan to replace the Company’s 2017 Stock Option Plan and all awards previously issued under the 2017 Stock Option Plan will be deemed issued under the Long-Term Incentive Plan. The maximum aggregate number of Shares issuable in respect of all Incentive Securities granted or issued under the Company’s Security Based Compensation Plans, at any point, shall not exceed (twenty percent (20%) of the total number of issued and outstanding Shares.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

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SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED)

12 Months Ended

Sep. 30, 2024

Supplemental Information On Oil And Gas Operations

SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED)

16. SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED)

Supplemental unaudited information regarding Permex’s oil and gas activities is presented in this note. All of Permex’s reserves are located within the U.S.

Costs Incurred in Oil and Gas Producing Activities

	12 Months Ended		12 Months Ended
	September 30, 2024		September 30, 2023
Acquisition of proved properties	$	-	$	-
Acquisition of unproved properties		-		-
Development costs		3,227		2,019,639
Exploration costs		-		-
Total costs incurred	$	3,227	$	2,019,639

Results of Operations from Oil and Gas Producing Activities

	12 Months Ended			12 Months Ended
	September 30, 2024			September 30, 2023
Oil and gas revenues	$	116,033		$	688,827
Production costs		(196,428	)		(879,471	)
Exploration expenses		-			-
Depletion, depreciation and amortization		(40,580	)		(104,798	)
Impairment of oil and gas properties		-			-
Result of oil and gas producing operations before income taxes		(120,975	)		(295,442	)
Provision for income taxes		-			-
Results of oil and gas producing activities	$	(120,975	)	$	(295,442	)

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

16. SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED) (cont’d…)

Proved Reserves

The Company’s proved oil and natural gas reserves have been estimated by the certified independent engineering firm, MKM Engineering. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods when the estimates were made. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history; acquisitions of oil and natural gas properties; and changes in economic factors.

Our proved reserves are summarized in the table below:

	Oil (Barrels)			Natural Gas (Mcf)			BOE (Barrels)
Proved developed and undeveloped reserves:
September 30, 2022		6,237,070			3,001,170			6,737,265
Revisions		(3,588,541	)		(951,270	)		(3,747,086	)
Purchase of proved reserves		-			-			-
Sale reserves		-			-			-
Production		(11,729	)		(7,500	)		(12,979	)
September 30, 2023		2,636,800			2,042,400			2,977,200
Revisions		(939,436	)		(904,200	)		(1,090,136	)
Purchase of proved reserves		-			-			-
Sale reserves		-			-			-
Production		(1,964	)		-			(1,964	)
September 30, 2024		1,695,400			1,138,200			1,885,100
Proved developed reserves:
September 30, 2022		1,153,870			864,770			1,297,998
September 30, 2023		1,027,100			765,300			1,154,650
September 30, 2024		508,700			279,600			555,300
Proved undeveloped reserves:
September 30, 2022		5,083,200			2,136,400			5,439,267
September 30, 2023		1,609,700			1,277,100			1,822,550
September 30, 2024		1,186,700			858,600			1,329,800

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

16. SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED) (cont’d…)

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of September 30, 2024 and 2023 in accordance with ASC 932, “Extractive Activities – Oil and Gas” which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.

Future cash inflows for the years ended September 30, 2024 and 2023 were estimated as specified by the SEC through calculation of an average price based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from October through September during each respective fiscal year. The resulting net cash flow are reduced to present value by applying a 10% discount factor.

	12 Months Ended
	September 30, 2024			September 30, 2023
Future cash inflows	$	134,081,000		$	211,828,000
Future production costs(1)		(31,752,000	)		(40,061,000	)
Future development costs		(17,496,000	)		(17,241,000	)
Future income tax expenses		(19,746,000	)		(39,262,000	)
Future net cash flows		65,087,000			115,264,000
10% annual discount for estimated timing of cash flows		(36,997,000	)		(60,184,000	)
Standardized measure of discounted future net cash flows at the end of the fiscal year	$	28,090,000		$	55,080,000

(1) Production costs include crude oil and natural gas operations expense, production ad valorem taxes, transportation costs and G&A expense supporting the Company’s crude oil and natural gas operations.

Average hydrocarbon prices are set forth in the table below.

	Average Price		Natural
	Crude Oil (Bbl)		Gas (Mcf)
Year ended September 30, 2022 (1)	$	91.72	$	5.79
Year ended September 30, 2023 (1)	$	78.54	$	3.42
Year ended September 30, 2024 (1)	$	78.64	$	2.21

(1) Average prices were based on 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from October through September during each respective fiscal year.

Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved crude oil and natural gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

16. SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED) (cont’d…)

Sources of Changes in Discounted Future Net Cash Flows

Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves, as required by ASC 932, at fiscal year-end are set forth in the table below.

	12 Months Ended
	September 30, 2024			September 30, 2023
Standardized measure of discounted future net cash flows at the beginning of the year	$	55,080,000		$	144,729,000
Extensions, discoveries and improved recovery, less related costs		-			-
Sales of minerals in place		-			-
Purchase of minerals in place		-			-
Revisions of previous quantity estimates		(25,208,000	)		(103,529,000	)
Net changes in prices and production costs		(4,323,000	)		(52,170,000	)
Accretion of discount		7,400,000			19,862,000
Sales of oil produced, net of production costs		80,000			191,000
Changes in future development costs		(107,000	)		27,173,000
Changes in timing of future production		(15,706,000	)		(16,145,000	)
Net changes in income taxes		10,874,000			34,969,000
Standardized measure of discounted future net cash flows at the end of the year	$	28,090,000		$	55,080,000

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SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Sep. 30, 2024

Accounting Policies [Abstract]

Basis of presentation

Basis of presentation

The Company’s consolidated financial statements are prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”).

Principles of Consolidation

Principles of Consolidation

The accompanying consolidated financial statements include the assets, liabilities, revenue and expenses of the Company’s wholly-owned subsidiary, Permex Petroleum US Corporation. All intercompany balances and transactions have been eliminated.

Going concern of operations

Going concern of operations

These consolidated financial statements have been prepared on a going concern basis which assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business. The Company has incurred losses since inception in the amount of $16,189,652, has a working capital deficiency of $5,857,870 as of September 30, 2024 and has not yet achieved profitable operations. The Company requires equity or debt financings to fund its continuing operation, which it has been unable to secure in sufficient amounts to date, and there can be no assurances that it will be able to do so in the future. The aforementioned factors raise substantial doubt about the Company’s ability to continue as a going concern within one year after the date that the financial statements are issued.

The Company expects to raise additional funds through equity and debt financings. There is no assurance that such financing will be available in the future. During the year ended September 30, 2024, the Company raised $1,365,000 through the issuance of convertible debentures and received additional proceeds of $2,250,000 from debt financing subscriptions. Subsequent to September 30, 2024, the Company received further subscription proceeds of $601,601 to complete a convertible debenture financing with total gross proceeds of $4,276,389. The $1,365,000 convertible debentures that matured on September 12, 2024 and accrued interest of $59,788 were retired in exchange for the new convertible debenture units. Management believes that these actions provide a path for the Company to continue as a going concern subject to its continued ability to raise funds to maintain its operations and manage its working capital deficiency.

In view of these matters, continuation as a going concern is dependent upon continued operations of the Company, which in turn is dependent upon the Company’s ability to meet its financial requirements, raise additional capital, and the success of its future operations. The financial statements do not include any adjustments to the amount and classification of assets and liabilities that may be necessary should the Company not continue as a going concern.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. Significant Accounting Policies (cont’d…)

Use of Estimates

Use of Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities at the date of the financial statements and the reported amount of revenue and expenses during the reporting period. Management evaluates these estimates and judgments on an ongoing basis and bases its estimates on experience, current and expected future conditions, third-party evaluations and various other assumptions that management believes are reasonable under the circumstances.

Significant estimates have been used by management in conjunction with the following: (i) the fair value of assets when determining the existence of impairment factors and the amount of impairment, if any; (ii) the costs of site restoration when determining decommissioning liabilities; (iii) the useful lives of assets for the purposes of depletion and depreciation; (iv) petroleum and natural gas reserves; and (v) share-based payments. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, and makes adjustments when facts and circumstances dictate. These estimates are based on information available as of the date of the financial statements; therefore, actual results could differ from those estimates.

Cash and cash equivalents

Cash and cash equivalents

The Company considers all highly liquid investments with an original maturity of three months or less when purchased to be cash and cash equivalents. Cash and cash equivalents are recorded at cost, which approximates fair value. The Company had no cash equivalents as of September 30, 2024 and 2023.

Trade and other receivables

Trade and other receivables

Trade and other receivables are stated at net realizable value. The majority of customers have payment terms of 30 days or less. The Company’s oil and gas revenues are mainly derived from three significant customers. As a result, the Company’s trade receivables are exposed to a concentration of credit risk. The Company routinely assesses the financial strength of its customers. On a periodic basis, management evaluates its accounts receivable and determines whether to provide an allowance or if any accounts should be written off based on a past history of write-offs, collections, and current credit conditions. A receivable is considered past due if the Company has not received payments based on agreed-upon terms.

Property and equipment

Property and equipment

The Company follows the successful efforts method of accounting for its oil and gas properties. All costs for development wells along with related acquisition costs, the costs of drilling development wells, and related estimated future asset retirement costs are capitalized. Exploration costs, such as exploratory geological and geophysical costs, and costs associated with non-productive exploratory wells, delay rentals and exploration overhead are expensed. Costs of drilling exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company groups its oil and gas properties with a common geological structure or stratigraphic condition (“common operating field”) for purposes of computing depletion expenses, assessing proved property impairments and accounting for asset dispositions.

Capitalized costs of proved oil and gas properties are depleted by individual field using a unit-of-production method based on proved and probable developed reserves. Proved reserves are estimated using reserve engineer reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids, which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. Significant Accounting Policies (cont’d…)

Property and equipment (cont’d…)

Proved oil and natural gas properties are assessed for possible impairment by comparing their carrying values with their associated undiscounted future net cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset (including changes to the commodity price forecast or carbon costs), significant change in the extent or manner of use of or a physical change in an asset, and a more-likely-than-not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted, future net cash flows. For proved oil and natural gas properties, the Company performs impairment reviews on a field basis, annually or as appropriate.

Other corporate property and equipment consist primarily of leasehold improvements, vehicle, and office furniture and equipment and are stated at cost less accumulated depreciation. The capitalized costs are generally depreciated on a straight line basis over their estimated useful lives ranging from three to five years.

For property dispositions, measurement is at fair value, unless the transaction lacks commercial substance or fair value cannot be reliably measured. Where the exchange is measured at fair value, a gain or loss is recognized in net income.

Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s depletion rate. These gains and losses are classified as asset dispositions in the accompanying consolidated statements of loss and comprehensive loss. Partial common operating field sales or dispositions deemed not to significantly alter the depletion rates are generally accounted for as adjustments to capitalized costs with no gain or loss recognized.

Impairment of long-lived assets

Impairment of long-lived assets

The Company assesses long-lived assets for impairment in accordance with the provisions of the Financial Accounting Standards Board Accounting Standards Codification (“ASC”) regarding long-lived assets. It requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable through the estimated undiscounted cash flows expected to result from the use and eventual disposition of the assets. Whenever any such impairment exists, an impairment loss will be recognized for the amount by which the carrying value exceeds the fair value. As of September 30, 2024 and 2023, no impairment charge has been recorded.

Asset retirement obligations

Asset retirement obligations

The Company recognizes asset retirement obligations (“ARO”) associated with tangible assets such as well sites when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The ARO are measured at the present value of management’s best estimate of the future remediation expenditures at the reporting date. The initial measurement of an ARO is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumption used to estimate a recorded ARO change, a revision is recorded to both the ARO and the asset retirement cost. The ARO is accreted to its then present value each period, and the asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. SIGNIFICANT ACCOUNTING POLICIES (cont’d…)

Fair value measurement

Fair value measurement

Fair value accounting is applied for all assets and liabilities and nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Fair value is defined as the exchange price that would be received for an asset or an exit price that would be paid to transfer a liability in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The Company follows the established framework for measuring fair value and expands disclosures about fair value measurements.

The Company categorizes its assets and liabilities measured at fair value into a three-level hierarchy based on the priority of the inputs to the valuation technique used to determine fair value. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used in the determination of the fair value measurement fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement.

Assets and liabilities valued at fair value are categorized based on the inputs to the valuation techniques as follows:

Level 1 – Inputs that utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access.

Level 2 – Inputs that include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. Fair values for these instruments are estimated using pricing models, quoted prices of securities with similar characteristics, or discounted cash flows.

Level 3 – Inputs that are unobservable inputs for the asset or liability, which are typically based on an entity’s own assumptions, as there is little, if any, related market activity.

The carrying values of cash, trade receivable, other current receivables, due from/to related parties, trade payable, other current payables, accrued expenses, convertible debenture and lease liability included in the accompanying consolidated balance sheets approximated fair value at September 30, 2024 and 2023. The financial statements as of and for the years ended September 30, 2024 and 2023, do not include any recurring or nonrecurring fair value measurements relating to assets or liabilities.

Subsequent to initial recognition, the Company may re-measure the carrying value of assets and liabilities measured on a nonrecurring basis to fair value. Adjustments to fair value usually result when certain assets are impaired. Such assets are written down from their carrying amounts to their fair value.

Professional standards allow entities the irrevocable option to elect to measure certain financial instruments and other items at fair value for the initial and subsequent measurement on an instrument-by-instrument basis. The Company has not elected to measure any existing financial instruments at fair value. However, it may elect to measure newly acquired financial instruments at fair value in the future.

Earnings (loss) per share

Earnings (loss) per share

Basic earnings (loss) per share (“EPS”) is calculated by dividing net income (loss) attributable to common shareholders by the weighted average number of common shares outstanding in the period. The diluted EPS reflects all dilutive potential common share equivalents, in the weighted average number of common shares outstanding during the period, if dilutive. All of the outstanding convertible securities, stock options and warrants were anti-dilutive for the years ended September 30, 2024 and 2023.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. SIGNIFICANT ACCOUNTING POLICIES (cont’d…)

Leases

Leases

At inception of a contract, the Company assesses whether a contract is or contains a lease based on whether the contract conveys the right to control the use of an identified asset for a period in exchange for consideration.

The Company recognizes a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured based on the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date.

The lease obligation is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Company’s incremental borrowing rate. Generally, the Company uses its incremental borrowing rate as the discount rate. Variable lease payments that do not depend on an index or rate are not included in the measurement of the lease liability. The lease liability is subsequently measured at amortized cost using the effective interest rate method.

Share capital

Share capital

The Company records proceeds from the issuance of its common shares as equity. Incremental costs directly attributable to the issue of new common shares are shown in equity as a deduction from the proceeds. Common shares issued for consideration other than cash are valued based on their fair value at the date that the shares are issued.

Share purchase warrants

Share purchase warrants

The fair value of warrants is determined using the Black-Scholes option pricing model. Proceeds from the issuance of private placement units are allocated between the private placement warrants and common shares on a relative fair value basis. Share purchase warrants with exercise prices denominated in a currency other than its functional currency are classified as a liability. Proceeds from the issuance of private placement units are first allocated to the warrant liability based on their fair value and the residual is allocated to common shares issued while for equity warrants, proceeds are allocated to common stock and additional paid in capital on a relative fair value basis. The changes in fair value of the warrant liability are recorded in the statement of loss and comprehensive loss.

Warrants issued for oil and gas interests and warrants issued as finder’s fees are share-based payments and are measured at fair value on the date of the grant as determined using the Black-Scholes option pricing model.

Share-based payments

Share-based payments

The Company issues stock options and other share-based compensation to directors, employees and other service providers. Equity awards including stock options and share purchase warrants are measured at grant date at the fair value of the instruments issued and amortized over the vesting periods using a graded vesting approach. The number of options expected to vest is reviewed and adjusted at the end of each reporting period such that the amount ultimately recognized as an expense is based on the number of options that eventually vest. The Company has elected to account for forfeitures as they occur rather than estimate expected forfeitures.

The fair value of the equity awards is determined using the Black-Scholes option pricing model. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility (based on weighted average historic volatility), weighted average expected life of the instruments (based on historical experience), expected dividends, and the risk-free interest rate (based on government bonds).

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. SIGNIFICANT ACCOUNTING POLICIES (cont’d…)

Revenue

Revenue

In accordance with ASC 606, Revenue from Contracts with Customers, the Company recognizes revenue when the performance obligation is satisfied, which typically occurs at the point in time when control of the product transfer to the customer. For natural gas, this is generally at the time product enters the pipeline. For crude oil, this is generally at the time the product is loaded into customer operated transports. Revenue is measured net of discounts, customs duties, royalties and withholding tax. Royalty income represents net revenue interests from certain crude oil and natural gas wells and is recognized upon the operators of the properties producing revenue from subject oil and gas wells.

The Company records revenue in the month production is delivered to the purchaser. However, production statements for oil and gas sales may not be received until the following month end after the products are purchased, and as a result, the Company is required to estimate the amount of revenue to be received. The Company records the differences between its estimates and the actual amounts received for revenue in the month that payment is received from the customer. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to sales volumes and prices for those good sold are estimated and recorded.

The Company does not have any contract assets or liabilities, or capitalized contract costs.

Foreign Currency

Foreign Currency

These consolidated financial statements are presented in United States dollars (“U.S. dollar”). The functional currency of the Company and the subsidiary of the Company is the U.S. dollar. Foreign currency transactions are translated into the functional currency using exchange rates prevailing at the dates of the transactions. At the end of each reporting period, monetary assets and liabilities that are denominated in foreign currencies are translated at the rates prevailing at that date. All gains and losses on these foreign currency transactions are charged to profit or loss.

PERMEX PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED SEPTEMBER 30, 2024 AND 2023

2. SIGNIFICANT ACCOUNTING POLICIES (cont’d…)

Income taxes

Income taxes

Current taxes receivable or payable are estimated on taxable income or loss for the current year at the statutory tax rates enacted or substantively enacted at the reporting date.

Deferred income tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Deferred income tax assets and liabilities are measured at the tax rates that have been enacted or substantially enacted at the end of the reporting period and are expected to apply when the related deferred income tax asset is realized or the deferred income tax liability is settled. Deferred income tax assets also result from unused loss carry forwards, resource related pools and other deductions. At the end of each reporting year the Company reassesses unrecognized deferred tax assets. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Deferred income tax assets and deferred income tax liabilities are offset if a legally enforceable right exists to offset current tax assets against current tax liabilities and the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority.

The Company recognizes a tax benefit in the financial statements for an uncertain tax position only if management assesses that the position is more likely than not (i.e., a likelihood greater than 50%) to be allowed by the tax jurisdiction, based solely on the technical merits of the position. The term “tax position,” as defined in the accounting standards for income taxes, refers to a position in a previously filed tax return or a position expected to be taken in a future tax return. This position is reflected in the measurement of current or deferred income tax assets and liabilities for interim or annual periods.

New accounting standards

New accounting standards

In November 2023, the FASB issued ASU 2023 - 07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which becomes effective for fiscal years beginning after December 15, 2024. This update requires public entities to disclose significant expenses for reportable segments in both interim and in annual reporting periods, while entities with only a single reportable segment must now provide all segment disclosures required both in ASC 280 and under the amendments in ASU 2023-07. The Company does not expect the standard to have a material effect on its consolidated financial statements and has begun evaluating disclosure presentation alternatives.

In December 2023, the FASB issued ASU 2023 - 09, Income Taxes (Topic740) Improvements to Income Tax Disclosures, which becomes effective for fiscal years beginning after December 15, 2024. The standard requires companies to disclose specific categories in the income tax rate reconciliation table and the amount of income taxes paid per major jurisdiction. The Company does not expect the standard to have a material effect on its consolidated financial statements and has begun evaluating disclosure presentation alternatives.

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REVENUE (Tables)

12 Months Ended

Sep. 30, 2024

Revenue from Contract with Customer [Abstract]

SCHEDULE OF REVENUE DISAGGREGATED BY PRODUCT TYPE AND GEOGRAPHIC AREAS

The following tables present our revenue from contracts with customers disaggregated by product type and geographic area.

Year ended September 30, 2024	Texas		New Mexico		Total
Crude oil	$	64,611	$	35,609	$	100,220
Natural gas		-		-		-
Revenue from contracts with customers	$	64,611	$	35,609	$	100,220

Year ended September 30, 2023	Texas		New Mexico		Total
Crude oil	$	501,920	$	154,700	$	656,620
Natural gas		9,003		-		9,003
Revenue from contracts with customers	$	510,923	$	154,700	$	665,623

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PROPERTY AND EQUIPMENT (Tables)

12 Months Ended

Sep. 30, 2024

Property, Plant and Equipment [Abstract]

SCHEDULE OF PROPERTY AND EQUIPMENT

Property and equipment consisted of the following:

	September 30, 2024			September 30, 2023
Oil and natural gas properties, at cost	$	10,600,489		$	10,501,244
Less: accumulated depletion		(330,036	)		(289,456	)
Oil and natural gas properties, net		10,270,453			10,211,788
Other property and equipment, at cost		18,505			205,315
Less: accumulated depreciation		(7,710	)		(55,684	)
Other property and equipment, net		10,795			149,631
Property and equipment, net	$	10,281,248		$	10,361,419

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LEASES (Tables)

12 Months Ended

Sep. 30, 2024

Leases

SCHEDULE OF RIGHT OF USE ASSETS AND LEASE LIABILITIES

All of the Company’s right-of-use assets are operating leases related to its office premises. Details of the Company’s right-of-use assets and lease liabilities are as follows:

	September 30, 2024			September 30, 2023
Right-of-use assets	$	-		$	146,912
Lease liabilities
Balance, beginning of the year	$	158,525		$	244,906
Addition		-			-
Liability accretion		12,346			24,221
Lease payments		(113,638	)		(110,602	)
Termination of lease		(57,233	)		-
Balance, end of the year	$	-		$	158,525
Current lease liabilities	$	-		$	77,069
Long-term lease liabilities	$	-		$	81,456
Weighted-average remaining lease term (in years)		-			2.17
Weighted-average discount rate		-	%		12	%

SCHEDULE OF LEASE COST

The following table presents the Company’s total lease cost.

	2024		2023
Operating lease cost	$	63,200	$	118,105
Variable lease expense		51,062		65,245
Sublease income		-		(25,390	)
Net lease cost	$	114,262	$	157,960

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ASSET RETIREMENT OBLIGATIONS (Tables)

12 Months Ended

Sep. 30, 2024

Asset Retirement Obligation Disclosure [Abstract]

SCHEDULE OF ASSETS RETIREMENT OBLIGATIONS

	2024		2023
Asset retirement obligations, beginning of the year	$	260,167	$	236,412
Obligations recognized		27,859		-
Obligations derecognized		-		(287	)
Revisions of estimates		68,159		(7,934	)
Accretion expense		36,792		31,976
	$	392,977	$	260,167

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DEBT (Tables)

12 Months Ended

Sep. 30, 2024

Debt Disclosure [Abstract]

SCHEDULE OF CONVERTIBLE DEBENTURES

As September 30, 2024, the following Convertible Debentures were outstanding:

Principal Amount		Interest rate			Maturity Date
$	500,000		10	%	September 12, 2024
	865,000		10	%	September 12, 2024
$	1,365,000

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LOSS PER SHARE (Tables)

12 Months Ended

Sep. 30, 2024

Earnings Per Share [Abstract]

SCHEDULE OF BASIC AND DILUTED LOSS PER SHARE

The calculation of basic and diluted loss per share for the years ended September 30, 2024 and 2023 was based on the net losses attributable to common shareholders. The following table sets forth the computation of basic and diluted loss per share:

	2024			2023
Net loss	$	(3,989,276	)	$	(4,483,195	)
Weighted average common shares outstanding		551,503			508,813
Basic and diluted loss per share	$	(7.23	)	$	(8.81	)

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EQUITY (Tables)

12 Months Ended

Sep. 30, 2024

Equity [Abstract]

SCHEDULE OF STOCK OPTION TRANSACTIONS

Stock option transactions are summarized as follows:

	Number of options			Weighted Average Exercise Price
Balance, September 30, 2022		21,146		$	53.04
Cancelled		(833	)		42.62
Balance, September 30, 2023		20,313		$	54.23
Cancelled		(10,208	)		55.24
Balance, September 30, 2024		10,105		$	53.21
Exercisable at September 30, 2024		10,105		$	53.21

SCHEDULE OF STOCK OPTIONS OUTSTANDING

As September 30, 2024, the following stock options were outstanding:

Number of Options		Exercise Price		Issuance Date	Expiry Date
	3,230	$	88.88	December 4, 2017	December 4, 2027
	1,250	$	8.88	March 16, 2020	March 16, 2030
	5,625	$	42.62	October 6, 2021	October 6, 2031
	10,105

SCHEDULE OF WARRANTS TRANSACTIONS

Warrant transactions are summarized as follows:

	Number of Warrants			Weighted Average Exercise Price
Balance, September 30, 2022		274,276		$	48.48
Exercised		(68,353	)		11.44
Granted		73,823			18.00
Balance, September 30, 2023		279,746		$	39.79
Granted		401,810			4.08
Cancelled		(500	)		4.08
Expired		(4,393	)		95.90
Balance, September 30, 2024		676,663		$	18.25

SCHEDULE OF WARRANTS OUTSTANDING

As September 30, 2024, the following warrants were outstanding:

Number of Warrants		Exercise Price		Issuance Date	Expiry Date
	149,447	$	50.40	March 29, 2022	March 29, 2027
	73,823	$	18.00	June 30, 2023	June 30, 2028
	147,000	$	4.08	April 16, 2024	April 16, 2029
				(Subsequently cancelled – Note 15)
	254,310	$	4.08	June 12, 2024	June 12, 2029
				(Subsequently cancelled – Note 15)
	52,083	$	35.52	September 30, 2021	September 30, 2031
	676,663

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INCOME TAXES (Tables)

12 Months Ended

Sep. 30, 2024

Income Tax Disclosure [Abstract]

SCHEDULE OF RECONCILIATION OF INCOME TAX

	2024			2023
Loss before income taxes	$	(3,989,276	)	$	(3,939,961	)
Expected income tax recovery at statutory rates	$	(598,000	)	$	(591,000	)
Provincial income tax recovery		(373,000	)		(290,000	)
Effect of income taxes from US operations		(58,000	)		(100,000	)
Change in statutory, foreign tax, foreign exchange rates and other		(3,000	)		(18,000	)
Permanent differences – debt discount		116,000			-
Permanent differences – debt extinguishment		134,000			-
Permanent differences - Other		11,000			3,000
Adjustment to prior years provision versus statutory tax returns		3,000			(43,000	)
Change in valuation allowance		768,000			1,039,000
Deferred income tax recovery	$	-		$	-

SCHEDULE OF PRE TAX LOSS AND INCOME TAXES

Components of the Company’s pre-tax loss and income taxes are as follows:

	2024			2023
Loss for the year
Canada	$	(3,110,348	)	$	(2,418,491	)
US		(878,928	)		(1,521,470	)
	$	(3,989,276	)	$	(3,939,961	)
Expected income tax (recovery)
Canada	$	(589,000	)	$	(659,000	)
US		(177,000	)		(319,000	)
	$	(766,000	)	$	(978,000	)
Deferred income tax
Canada	$	589,000		$	659,000
US		177,000			319,000
	$	766,000		$	978,000
Deferred income tax recovery	$	-		$	-

SCHEDULE OF DEFERRED TAX ASSETS AND LIABILITIES

The significant components of the Company’s deferred tax assets and liabilities are as follows:

	2024			2023
Tax loss carryforwards	$	3,037,000		$	2,313,000
Property and equipment		15,000			39,000
Financing fees		130,000			191,000
Accrued liabilities		129,000			-
		3,311,000			2,543,000
Deferred tax assets valuation allowance		(3,311,000	)		(2,543,000	)
Net deferred tax assets	$	-		$	-

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SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED) (Tables)

12 Months Ended

Sep. 30, 2024

Supplemental Information On Oil And Gas Operations

SCHEDULE OF COST INCURRED IN PRODUCING ACTIVITIES

	12 Months Ended		12 Months Ended
	September 30, 2024		September 30, 2023
Acquisition of proved properties	$	-	$	-
Acquisition of unproved properties		-		-
Development costs		3,227		2,019,639
Exploration costs		-		-
Total costs incurred	$	3,227	$	2,019,639

Results of Operations from Oil and Gas Producing Activities

	12 Months Ended			12 Months Ended
	September 30, 2024			September 30, 2023
Oil and gas revenues	$	116,033		$	688,827
Production costs		(196,428	)		(879,471	)
Exploration expenses		-			-
Depletion, depreciation and amortization		(40,580	)		(104,798	)
Impairment of oil and gas properties		-			-
Result of oil and gas producing operations before income taxes		(120,975	)		(295,442	)
Provision for income taxes		-			-
Results of oil and gas producing activities	$	(120,975	)	$	(295,442	)

SCHEDULE OF PROVED RESERVES

Our proved reserves are summarized in the table below:

	Oil (Barrels)			Natural Gas (Mcf)			BOE (Barrels)
Proved developed and undeveloped reserves:
September 30, 2022		6,237,070			3,001,170			6,737,265
Revisions		(3,588,541	)		(951,270	)		(3,747,086	)
Purchase of proved reserves		-			-			-
Sale reserves		-			-			-
Production		(11,729	)		(7,500	)		(12,979	)
September 30, 2023		2,636,800			2,042,400			2,977,200
Revisions		(939,436	)		(904,200	)		(1,090,136	)
Purchase of proved reserves		-			-			-
Sale reserves		-			-			-
Production		(1,964	)		-			(1,964	)
September 30, 2024		1,695,400			1,138,200			1,885,100
Proved developed reserves:
September 30, 2022		1,153,870			864,770			1,297,998
September 30, 2023		1,027,100			765,300			1,154,650
September 30, 2024		508,700			279,600			555,300
Proved undeveloped reserves:
September 30, 2022		5,083,200			2,136,400			5,439,267
September 30, 2023		1,609,700			1,277,100			1,822,550
September 30, 2024		1,186,700			858,600			1,329,800

SCHEDULE OF NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

	12 Months Ended
	September 30, 2024			September 30, 2023
Future cash inflows	$	134,081,000		$	211,828,000
Future production costs(1)		(31,752,000	)		(40,061,000	)
Future development costs		(17,496,000	)		(17,241,000	)
Future income tax expenses		(19,746,000	)		(39,262,000	)
Future net cash flows		65,087,000			115,264,000
10% annual discount for estimated timing of cash flows		(36,997,000	)		(60,184,000	)
Standardized measure of discounted future net cash flows at the end of the fiscal year	$	28,090,000		$	55,080,000

(1) Production costs include crude oil and natural gas operations expense, production ad valorem taxes, transportation costs and G&A expense supporting the Company’s crude oil and natural gas operations.

SCHEDULE OF AVERAGE HYDROCARBON PRICES

Average hydrocarbon prices are set forth in the table below.

	Average Price		Natural
	Crude Oil (Bbl)		Gas (Mcf)
Year ended September 30, 2022 (1)	$	91.72	$	5.79
Year ended September 30, 2023 (1)	$	78.54	$	3.42
Year ended September 30, 2024 (1)	$	78.64	$	2.21

(1) Average prices were based on 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from October through September during each respective fiscal year.

SCHEDULE OF CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS

	12 Months Ended
	September 30, 2024			September 30, 2023
Standardized measure of discounted future net cash flows at the beginning of the year	$	55,080,000		$	144,729,000
Extensions, discoveries and improved recovery, less related costs		-			-
Sales of minerals in place		-			-
Purchase of minerals in place		-			-
Revisions of previous quantity estimates		(25,208,000	)		(103,529,000	)
Net changes in prices and production costs		(4,323,000	)		(52,170,000	)
Accretion of discount		7,400,000			19,862,000
Sales of oil produced, net of production costs		80,000			191,000
Changes in future development costs		(107,000	)		27,173,000
Changes in timing of future production		(15,706,000	)		(16,145,000	)
Net changes in income taxes		10,874,000			34,969,000
Standardized measure of discounted future net cash flows at the end of the year	$	28,090,000		$	55,080,000

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BACKGROUND (Details Narrative)	12 Months Ended
	Sep. 30, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Date of incorporation	Apr. 24, 2017

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SIGNIFICANT ACCOUNTING POLICIES (Details Narrative) - USD ($)		3 Months Ended	12 Months Ended
	Nov. 01, 2024	Jan. 14, 2025	Sep. 30, 2024	Sep. 30, 2023
Property, Plant and Equipment [Line Items]
Loss incurred			$ 16,189,652
Working capital deficit			5,857,870
Proceeds from issuance of long-term debt			1,365,000
Proceeds from debt financing subscriptions			2,250,000
Settlement of convertible debenture				38,291
Maturity date			Sep. 12, 2024
Accrued interest			$ 59,788	1,182
Cash Equivalents, at Carrying Value			0	0
Impairment charge			$ 0	$ 0
Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives			3 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives			5 years
Subsequent Event [Member]
Property, Plant and Equipment [Line Items]
Subscription proceeds		$ 601,601
Gross proceeds from convertible debenture financing		4,276,389
Settlement of convertible debenture		$ 1,365,000
Accrued interest	$ 59,788

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SCHEDULE OF REVENUE DISAGGREGATED BY PRODUCT TYPE AND GEOGRAPHIC AREAS (Details) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 100,220	$ 665,623
TEXAS
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	64,611	510,923
NEW MEXICO
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	35,609	154,700
Crude Oil [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	100,220	656,620
Crude Oil [Member] | TEXAS
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	64,611	501,920
Crude Oil [Member] | NEW MEXICO
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	35,609	154,700
Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		9,003
Natural Gas [Member] | TEXAS
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers		9,003
Natural Gas [Member] | NEW MEXICO
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers

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REVENUE (Details Narrative) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue	$ 100,220	$ 665,623
Trade Accounts Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenue	$ 26,873	$ 48,165

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CONCENTRATION OF CREDIT RISK (Details Narrative) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Concentration Risk [Line Items]
Non trade receivables current	$ 18,060	$ 5,420
Credit losses on receivables	9,587
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Customer [Member]
Concentration Risk [Line Items]
Trade receivables	$ 26,873	$ 73,021
Revenue Benchmark [Member] | Customer Concentration Risk [Member] | Two Customer [Member]
Concentration Risk [Line Items]
Concentration risk percentage	100.00%	99.00%

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SCHEDULE OF PROPERTY AND EQUIPMENT (Details) - USD ($)	Sep. 30, 2024	Sep. 30, 2023
Property, Plant and Equipment [Abstract]
Oil and natural gas properties, at cost	$ 10,600,489	$ 10,501,244
Less: accumulated depletion	(330,036)	(289,456)
Oil and natural gas properties, net	10,270,453	10,211,788
Other property and equipment, at cost	18,505	205,315
Less: accumulated depreciation	(7,710)	(55,684)
Other property and equipment, net	10,795	149,631
Property and equipment, net	$ 10,281,248	$ 10,361,419

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PROPERTY AND EQUIPMENT (Details Narrative) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Property, Plant and Equipment [Abstract]
Depletion and depreciation	$ 82,215	$ 154,834
Write-offs of property and equipment	$ 62,046

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SCHEDULE OF RIGHT OF USE ASSETS AND LEASE LIABILITIES (Details) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Property, Plant and Equipment [Line Items]
Right-of-use assets		$ 146,912
Current lease liabilities		77,069
Long-term lease liabilities		81,456
Office Premises [Member]
Property, Plant and Equipment [Line Items]
Right-of-use assets		146,912
Beginning balance	158,525	244,906
Addition
Liability accretion	12,346	24,221
Lease payments	(113,638)	(110,602)
Termination of lease	(57,233)
Ending balance		158,525
Current lease liabilities		77,069
Long-term lease liabilities		$ 81,456
Weighted-average remaining lease term (in years)		2 years 2 months 1 day
Weighted-average discount rate		12.00%

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SCHEDULE OF LEASE COST (Details) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Leases
Operating lease cost	$ 63,200	$ 118,105
Variable lease expense	51,062	65,245
Sublease income		(25,390)
Net lease cost	$ 114,262	$ 157,960

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LEASES (Details Narrative) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Loss on termination of lease	$ (38,825)
Lease Agreement [Member] | Office Premises [Member]
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Lease term	November 2025
Loss on termination of lease	$ 38,825

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SCHEDULE OF ASSETS RETIREMENT OBLIGATIONS (Details) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations, beginning of the year	$ 260,167	$ 236,412
Obligations recognized	27,859
Obligations derecognized		(287)
Revisions of estimates	68,159	(7,934)
Accretion expense	36,792	31,976
Asset retirement obligations, ending of the year	$ 392,977	$ 260,167

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ASSET RETIREMENT OBLIGATIONS (Details Narrative) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation, revision of estimate	$ 68,159	$ (7,934)
Asset retirement obligation, liabilities incurred		66,354
Asset retirement obligation liabilities settled loss		66,067
Reclamation deposits	75,000	145,000
Reclamation deposit redemption	$ 70,000

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SCHEDULE OF CONVERTIBLE DEBENTURES (Details) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Apr. 28, 2023
Short-Term Debt [Line Items]
Principal Amount			$ 209,497
Interest rate	10.00%	6.00%
Maturity Date	Sep. 12, 2024
Senior Secured Convertible Debenture [Member]
Short-Term Debt [Line Items]
Principal Amount	$ 1,365,000
Senior Secured Convertible Debenture [Member] | September 12, 2024 [Member]
Short-Term Debt [Line Items]
Principal Amount	$ 500,000
Interest rate	10.00%
Maturity Date	Sep. 12, 2024
Senior Secured Convertible Debenture [Member] | September Twelve Twenty Twenty Four One [Member]
Short-Term Debt [Line Items]
Principal Amount	$ 865,000
Interest rate	10.00%
Maturity Date	Sep. 12, 2024

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DEBT (Details Narrative)		1 Months Ended		12 Months Ended
	Nov. 01, 2024 USD ($) $ / shares shares	Oct. 31, 2024 USD ($) shares	Sep. 30, 2024 USD ($) $ / shares shares	Sep. 30, 2024 USD ($) $ / shares shares	Sep. 30, 2023 USD ($)	Sep. 30, 2023 CAD ($)	Apr. 28, 2023 USD ($)
Short-Term Debt [Line Items]
Gross proceeds				$ 1,365,000
Principal loan amount							$ 209,497
Common share purchase warrants | shares			676,663	676,663
Debt extinguishment and loss				$ 495,051
Fair value of the amended warrants				$ 494,219
Warrants and rights outstanding, term			5 years	5 years
Proceeds allocated to warrants				$ 431,666
Interest rate			10.00%	10.00%	6.00%
Debt maturity date				Sep. 12, 2024
Conversion price | $ / shares			$ 3.40	$ 3.40
Received loan from former director				$ 45,000
Unpaid principal loan amount			$ 115,936	115,936	$ 125,936
Principal loan amount				$ 59,788	1,182
Subsequent Event [Member]
Short-Term Debt [Line Items]
Principal loan amount		$ 1,365,000
Common share purchase warrants | shares		401,310
Debt extinguishment and loss		$ (105,349)
Interest rate	10.00%
Principal loan amount	$ 59,788
Measurement Input, Risk Free Interest Rate [Member]
Short-Term Debt [Line Items]
Warrants and rights outstanding, measurement input			0.0341	0.0341
Measurement Input, Price Volatility [Member]
Short-Term Debt [Line Items]
Warrants and rights outstanding, measurement input			1.2869	1.2869
Measurement Input, Expected Dividend Rate [Member]
Short-Term Debt [Line Items]
Warrants and rights outstanding, measurement input			0	0
Measurement Input, Discount Rate [Member] | Warrant [Member]
Short-Term Debt [Line Items]
Unamortized discount of original warrants			$ 832	$ 832
Senior Secured Convertible Debenture [Member]
Short-Term Debt [Line Items]
Principal loan amount			$ 1,365,000	$ 1,365,000
Common share purchase warrants | shares			401,310	401,310
Aggregate amount			$ 50,008	$ 50,008
Convertible Debt [Member]
Short-Term Debt [Line Items]
Repayments of loan					$ 38,291	$ 52,454
Private Placement [Member]
Short-Term Debt [Line Items]
Convertible debentures issued | shares			18,635	1,365
Gross proceeds				$ 1,365,000
Private Placement [Member] | Senior Secured Convertible Debenture [Member]
Short-Term Debt [Line Items]
Convertible debentures issued | shares				500
Principal loan amount			$ 1,000	$ 1,000
Common share purchase warrants | shares			294	294
Warrant exercisable period				5 years
Exercise price of warrants or rights | $ / shares			$ 4.08	$ 4.08
Common share purchase warrants | shares			1	1
Warrants per unit | shares			294	294
Private Placement [Member] | Convertible Debenture [Member]
Short-Term Debt [Line Items]
Principal loan amount			$ 1,000	$ 1,000
Common share purchase warrants | shares			523	523
Warrant exercisable period			5 years
Exercise price of warrants or rights | $ / shares			$ 1.91	$ 1.91
Proceeds from subscription			$ 2,250,000	$ 2,250,000
Received loan from former director				$ 4,276,389
Private Placement [Member] | Convertible Debenture [Member] | Subsequent Event [Member]
Short-Term Debt [Line Items]
Principal loan amount	$ 1,000
Common share purchase warrants | shares	523
Warrant exercisable period	5 years
Exercise price of warrants or rights | $ / shares	$ 1.91
Gross proceeds	$ 4,276,389

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RELATED PARTY TRANSACTIONS (Details Narrative) - USD ($)			12 Months Ended
	Apr. 29, 2024	May 01, 2022	Sep. 30, 2024	Sep. 30, 2023	Oct. 31, 2024	Oct. 01, 2024	Aug. 31, 2024
Employee settlment description	Further, the terms of this employment agreement provide that if Mr. Taillon’s employment with the Company is terminated without “cause” (as defined in the agreement) than Mr. Taillon is entitled to a severance payment equal to two years of base salary and a bonus equal to 50% of his annual base salary.
Annual base salary, percentage			20.00%
Fair value of vehicle							$ 35,155
Settlement liabilities current			$ 145,000
Subsequent Event [Member]
Lump sum settlment payment					$ 100,000
Monthly payments						$ 7,500
Employee Agreement [Member]
Management salary			229,167	$ 250,000
Bradley Taillon [Member] | Employee Agreement [Member]
Annual base salary	$ 250,000
Management salary			122,312
One-time sign-on bonus			50,000
Bradley Taillon [Member] | Employee Agreement [Member] | Minimum [Member]
Management salary	50,000
Bradley Taillon [Member] | Employee Agreement [Member] | Maximum [Member]
Management salary	$ 750,000
Mr.Taillon [Member] | Employee Agreement [Member]
Description of officer annual bonus	Mr. Taillon is also eligible on an annual basis for a cash bonus of up to 100% of annual salary and additional performance bonuses ranging from $50,000 to $750,000 upon the closing of a qualified financing with proceeds to the Company of $1 million or greater.
Mehran Ehsan [Member] | Employee Agreement [Member]
Annual base salary			$ 250,000
Description of officer annual bonus			Mr. Ehsan was also eligible on an annual basis for a cash bonus of up to 100% of annual salary, subject to the discretion of the board of directors.
Chief Financial Officer [Member] | Employee Agreement [Member]
Annual base salary		$ 50,000
Description of officer annual bonus		The CFO is also eligible on an annual basis for a cash bonus of up to 100% of annual salary, subject to the discretion of the board of directors. The employment agreement may be terminated with a termination payment equal to two months of base salary.
Management salary			$ 50,000	$ 50,000

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SCHEDULE OF BASIC AND DILUTED LOSS PER SHARE (Details) - USD ($)		12 Months Ended
		Sep. 30, 2024	Sep. 30, 2023
Earnings Per Share [Abstract]
Net loss		$ (3,989,276)	$ (4,483,195)
Weighted average common shares outstanding, basic	[1]	551,503	508,813
Weighted average common shares outstanding, diluted	[1]	551,503	508,813
Basic loss per share		$ (7.23)	$ (8.81)
Diluted loss per share		$ (7.23)	$ (8.81)

[1] The number of shares has been restated to reflect the 4:1 reverse stock split effective on October 23, 2023 (Note 1). All historical share and per share amounts reflected in this report have been adjusted to reflect the reverse stock split.

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LOSS PER SHARE (Details Narrative) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Earnings Per Share [Abstract]
Number of options	10,105	20,313
Number of warrants	676,663	279,746	274,276
Convertible debentures	$ 1,365,000
Convertible common shares	401,471

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SCHEDULE OF STOCK OPTION TRANSACTIONS (Details) - $ / shares	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Equity [Abstract]
Number of options, beginning balance	20,313	21,146
Weighted average exercise price, beginning balance	$ 54.23	$ 53.04
Cancelled	(10,208)	(833)
Weighted average exercise price, cancelled	$ 55.24	$ 42.62
Number of options, Ending balance	10,105	20,313
Weighted average exercise price, ending balance	$ 53.21	$ 54.23
Exercisable	10,105
Weighted average exercise price, exercisable	$ 53.21

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SCHEDULE OF STOCK OPTIONS OUTSTANDING (Details) - $ / shares	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Offsetting Assets [Line Items]
Number of options	10,105	20,313	21,146
Exercise Price	$ 53.21	$ 54.23	$ 53.04
Stock Option One [Member]
Offsetting Assets [Line Items]
Number of options	3,230
Exercise Price	$ 88.88
Issuance date	Dec. 04, 2017
Expiry date	Dec. 04, 2027
Stock Option Three [Member]
Offsetting Assets [Line Items]
Number of options	1,250
Exercise Price	$ 8.88
Issuance date	Mar. 16, 2020
Expiry date	Mar. 16, 2030
Stock Option Four [Member]
Offsetting Assets [Line Items]
Number of options	5,625
Exercise Price	$ 42.62
Issuance date	Oct. 06, 2021
Expiry date	Oct. 06, 2031

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SCHEDULE OF WARRANTS TRANSACTIONS (Details) - $ / shares	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Equity [Abstract]
Number of warrants, beginning balance	279,746	274,276
Weighted Average Exercise Price, beginning balance	$ 39.79	$ 48.48
Exercised		(68,353)
Weighted average exercise price, exercised		$ 11.44
Granted	401,810	73,823
Weighted average exercise price, granted	$ 4.08	$ 18.00
Cancelled	(500)
Weighted average exercise price, cancelled	$ 4.08
Expired	(4,393)
Weighted average exercise price, granted	$ 95.90
Number of warrants, ending balance	676,663	279,746
Weighted Average Exercise Price, ending balance	$ 18.25	$ 39.79

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SCHEDULE OF WARRANTS OUTSTANDING (Details)	12 Months Ended
	Sep. 30, 2024 $ / shares shares
Class of Warrant or Right [Line Items]
Number of warrants	676,663
Warrant One [Member]
Class of Warrant or Right [Line Items]
Number of warrants	149,447
Exercise price | $ / shares	$ 50.40
Issuance date	Mar. 29, 2022
Expiry date	Mar. 29, 2027
Warrant Two [Member]
Class of Warrant or Right [Line Items]
Number of warrants	73,823
Exercise price | $ / shares	$ 18.00
Issuance date	Jun. 30, 2023
Expiry date	Jun. 30, 2028
Warrant Three [Member]
Class of Warrant or Right [Line Items]
Number of warrants	147,000
Exercise price | $ / shares	$ 4.08
Issuance date	Apr. 16, 2024
Expiry date	Apr. 16, 2029
Warrant Four [Member]
Class of Warrant or Right [Line Items]
Number of warrants	254,310
Exercise price | $ / shares	$ 4.08
Issuance date	Jun. 12, 2024
Expiry date	Jun. 12, 2029
Warrant Five [Member]
Class of Warrant or Right [Line Items]
Number of warrants	52,083
Exercise price | $ / shares	$ 35.52
Issuance date	Sep. 30, 2021
Expiry date	Sep. 30, 2031

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EQUITY (Details Narrative) - USD ($)				6 Months Ended	9 Months Ended	12 Months Ended
		Oct. 23, 2023	Jun. 30, 2023	Sep. 30, 2023	Jun. 30, 2023	Sep. 30, 2024	Sep. 30, 2023
Accumulated Other Comprehensive Income (Loss) [Line Items]
Common stock, shares authorized						Unlimited	Unlimited
Common stock, par value				$ 0		$ 0	$ 0
Common stock, shares issued	[1]			551,503		551,503	551,503
Common stock, shares outstanding	[1]			551,503		551,503	551,503
Stockholders equity reverse stock split		4:1
Number of warrants share exercise price						676,663
Warrant sterm						5 years
Stock issued during period shares new issues						401,471
Payments of Stock Issuance Costs							$ 136,623
Payments for repurchase of warrants			$ 544,164
Deemed dividend					$ 543,234		543,234
Fair value adjustments of warrants			$ 930				(22,570)
Percentage issued and outstanding for common stock						10.00%
Expected term						10 years
Aggregate intrinsic value of warrants outstanding
Exercise price range, minimum						$ 8.88
Exercise price range, maximum						$ 88.80
Weighted average remaining contractual life						5 years 7 months 6 days
Recognized share-based payment expense							$ 318
Incentive Warrants [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Share-Based Compensation Arrangement by Share-Based Payment Award, Fair Value Assumptions, Risk Free Interest Rate			4.21%
Share-Based Compensation Arrangement by Share-Based Payment Award, Fair Value Assumptions, Expected Term			3 years 9 months
Share-Based Compensation Arrangement by Share-Based Payment Award, Fair Value Assumptions, Expected Volatility Rate			137.62%
Share-Based Compensation Arrangement by Share-Based Payment Award, Fair Value Assumptions, Expected Dividend Rate			0.00%
Finder Warrants [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Share-Based Compensation Arrangement by Share-Based Payment Award, Fair Value Assumptions, Risk Free Interest Rate			3.68%
Share-Based Compensation Arrangement by Share-Based Payment Award, Fair Value Assumptions, Expected Term			5 years
Share-Based Compensation Arrangement by Share-Based Payment Award, Fair Value Assumptions, Expected Volatility Rate			128.81%
Share-Based Compensation Arrangement by Share-Based Payment Award, Fair Value Assumptions, Expected Dividend Rate			0.00%
Warrant Exercise Incentive Program [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Number of warrants share exercise price				253,966			253,966
Stock issued during period shares new issues			68,353
Shares Issued, Price Per Share			$ 11.44		$ 11.44
Proceeds from Issuance of Common Stock			$ 781,953
Net proceeds			645,330
Payments of Stock Issuance Costs			$ 62,556
Number of warrants			5,470
Value of incentive warrants			$ 449,005
Value of finders warrants			35,919
Legal Fees			$ 74,066
Warrant Exercise Incentive Program [Member] | Incentive Warrants [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Warrant sterm				5 years			5 years
Price per share				$ 18.00			$ 18.00
Warrant Exercise Incentive Program [Member] | Maximum [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Warrant exercise price							50.40
Warrant Exercise Incentive Program [Member] | Minimum [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Warrant exercise price							$ 11.44

[1] The number of shares has been restated to reflect the 4:1 reverse stock split effective on October 23, 2023 (Note 1). All historical share and per share amounts reflected in this report have been adjusted to reflect the reverse stock split.

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SCHEDULE OF RECONCILIATION OF INCOME TAX (Details) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Income Tax Disclosure [Abstract]
Loss before income taxes	$ (3,989,276)	$ (3,939,961)
Expected income tax recovery at statutory rates	(598,000)	(591,000)
Provincial income tax recovery	(373,000)	(290,000)
Effect of income taxes from US operations	(58,000)	(100,000)
Change in statutory, foreign tax, foreign exchange rates and other	(3,000)	(18,000)
Permanent differences – debt discount	116,000
Permanent differences – debt extinguishment	134,000
Permanent differences - Other	11,000	3,000
Adjustment to prior years provision versus statutory tax returns	3,000	(43,000)
Change in valuation allowance	768,000	1,039,000
Deferred income tax recovery

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SCHEDULE OF PRE TAX LOSS AND INCOME TAXES (Details) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Net loss	$ (3,989,276)	$ (3,939,961)
Expected income tax (recovery)	(766,000)	(978,000)
Deferred income tax (recovery)	766,000	978,000
Deferred income tax recovery
CANADA
Net loss	(3,110,348)	(2,418,491)
Expected income tax (recovery)	(589,000)	(659,000)
Deferred income tax (recovery)	589,000	659,000
UNITED STATES
Net loss	(878,928)	(1,521,470)
Expected income tax (recovery)	(177,000)	(319,000)
Deferred income tax (recovery)	$ 177,000	$ 319,000

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SCHEDULE OF DEFERRED TAX ASSETS AND LIABILITIES (Details) - USD ($)	Sep. 30, 2024	Sep. 30, 2023
Income Tax Disclosure [Abstract]
Tax loss carryforwards	$ 3,037,000	$ 2,313,000
Property and equipment	15,000	39,000
Financing fees	130,000	191,000
Accrued liabilities	129,000
Total gross deferred tax assets	3,311,000	2,543,000
Deferred tax assets valuation allowance	(3,311,000)	(2,543,000)
Net deferred tax assets

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INCOME TAXES (Details Narrative) - USD ($)	Sep. 30, 2024	Sep. 30, 2023
Tax loss carryforwards	$ 3,037,000	$ 2,313,000
C A and U S [Member]
Tax loss carryforwards	11,991,000
CANADA
Tax loss carryforwards	9,421,000	7,019,000
UNITED STATES
Tax loss carryforwards	2,569,000	$ 2,367,000
Tax loss carryforwards state tax losses	$ 290,000

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CONTINGENCIES (Details Narrative)	Sep. 30, 2024 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Loss contingency claims from trade vendor	$ 545,505
Loss contingency accrual product liability net	$ 499,162

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SUBSEQUENT EVENTS (Details Narrative) - USD ($)			1 Months Ended		12 Months Ended
	Nov. 01, 2024	Oct. 02, 2024	Oct. 31, 2024	Sep. 30, 2024	Sep. 30, 2024	Sep. 30, 2023	Apr. 28, 2023	Sep. 30, 2022
Subsequent Event [Line Items]
Exercise price				$ 53.21	$ 53.21	$ 54.23		$ 53.04
Share-Based Compensation Arrangement by Share-Based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term					10 years
Proceeds from issuance of debt					$ 45,000
Accrued interest					59,788	$ 1,182
Debt face amount							$ 209,497
Proceeds from issuance of warrants						$ 781,953
Interest rate				10.00%	10.00%	6.00%
Debt extinguishment of loss					$ (495,051)
Private Placement [Member] | Warrant [Member]
Subsequent Event [Line Items]
Proceeds from issuance of warrants					2,236,551
Private Placement [Member] | Convertible Debenture [Member]
Subsequent Event [Line Items]
Proceeds from issuance of debt					4,276,389
Proceeds from subscription					2,250,000
Debt face amount				$ 1,000	$ 1,000
Common share purchase warrants				523	523
Warrant exercisable period				5 years
Exercise price of warrants or rights				$ 1.91	$ 1.91
Subsequent Event [Member]
Subsequent Event [Line Items]
Accrued interest	$ 1,365,000
Accrued interest	$ 59,788
Debt face amount			$ 1,365,000
Common share purchase warrants			401,310
Interest rate	10.00%
Debt extinguishment of loss			$ 105,349
Subsequent Event [Member] | Convertible Debenture [Member]
Subsequent Event [Line Items]
Proceeds from issuance of debt	$ 1,424,788
Subsequent Event [Member] | New Debenture [Member]
Subsequent Event [Line Items]
Principal amount			$ 59,788
Subsequent Event [Member] | Private Placement [Member] | Convertible Debenture [Member]
Subsequent Event [Line Items]
Debt face amount	$ 1,000
Common share purchase warrants	523
Warrant exercisable period	5 years
Exercise price of warrants or rights	$ 1.91
Director and Officer [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Purchase common shares		65,000
Exercise price		$ 2.44
Share-Based Compensation Arrangement by Share-Based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term		10 years

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SCHEDULE OF COST INCURRED IN PRODUCING ACTIVITIES (Details) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Supplemental Information On Oil And Gas Operations
Acquisition of proved properties
Acquisition of unproved properties
Development costs	3,227	2,019,639
Exploration costs
Total costs incurred	3,227	2,019,639
Oil and gas revenues	116,033	688,827
Production costs	(196,428)	(879,471)
Exploration expenses
Depletion, depreciation and amortization	(40,580)	(104,798)
Impairment of oil and gas properties
Result of oil and gas producing operations before income taxes	(120,975)	(295,442)
Provision for income taxes
Results of oil and gas producing activities	$ (120,975)	$ (295,442)

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SCHEDULE OF PROVED RESERVES (Details)	12 Months Ended
	Sep. 30, 2024 bbl	Sep. 30, 2024 Boe bbl	Sep. 30, 2024 bbl Mcf	Sep. 30, 2023 bbl	Sep. 30, 2023 Boe bbl	Sep. 30, 2023 bbl Mcf	Sep. 30, 2024 Boe	Sep. 30, 2024 Mcf	Sep. 30, 2023 Boe	Sep. 30, 2023 Mcf	Sep. 30, 2022 bbl	Sep. 30, 2022 Boe	Sep. 30, 2022 Mcf
Supplemental Information On Oil And Gas Operations
Beginning balance	2,636,800		2,042,400	6,237,070		3,001,170
Beginning balance, BOE (Barrels)		2,977,200			6,737,265
Revisions	(939,436)		(904,200)	(3,588,541)		(951,270)
Revisions, BOE (Barrels)		(1,090,136)			(3,747,086)
Purchase of proved reserves
Purchase of proved reserves, BOE (Barrels)
Sale reserves
Sale reserves, BOE (Barrels)
Production	(1,964)			(11,729)		(7,500)
Production, BOE (Barrels)		(1,964)			(12,979)
Ending balance	1,695,400		1,138,200	2,636,800		2,042,400
Ending balance, BOE (Barrels)		1,885,100			2,977,200
Proved developed reserves	508,700	508,700	508,700	1,027,100	1,027,100	1,027,100		279,600		765,300	1,153,870		864,770
Proved developed reserves, BOE (Barrels)							555,300		1,154,650			1,297,998
Proved undeveloped reserves	1,186,700	1,186,700	1,186,700	1,609,700	1,609,700	1,609,700		858,600		1,277,100	5,083,200		2,136,400
Proved undeveloped reserves, BOE (Barrels)							1,329,800		1,822,550			5,439,267

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SCHEDULE OF NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES (Details) - USD ($)		Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Supplemental Information On Oil And Gas Operations
Future cash inflows		$ 134,081,000	$ 211,828,000
Future production costs	[1]	(31,752,000)	(40,061,000)
Future development costs		(17,496,000)	(17,241,000)
Future income tax expenses		(19,746,000)	(39,262,000)
Future net cash flows		65,087,000	115,264,000
10% annual discount for estimated timing of cash flows		(36,997,000)	(60,184,000)
Standardized measure of discounted future net cash flows at the end of the fiscal year		$ 28,090,000	$ 55,080,000	$ 144,729,000

[1] Production costs include crude oil and natural gas operations expense, production ad valorem taxes, transportation costs and G&A expense supporting the Company’s crude oil and natural gas operations.

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SCHEDULE OF AVERAGE HYDROCARBON PRICES (Details) - $ / shares		Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Oil [Member]
Oil and Gas, Proved Reserve, Quantity [Line Items]
Average Price	[1]	$ 78.64	$ 78.54	$ 91.72
Natural Gas [Member]
Oil and Gas, Proved Reserve, Quantity [Line Items]
Average Price	[1]	$ 2.21	$ 3.42	$ 5.79

[1] Average prices were based on 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from October through September during each respective fiscal year.

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SCHEDULE OF CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS (Details) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Supplemental Information On Oil And Gas Operations
Standardized measure of discounted future net cash flows at the beginning of the year	$ 55,080,000	$ 144,729,000
Extensions, discoveries and improved recovery, less related costs
Sales of minerals in place
Purchase of minerals in place
Revisions of previous quantity estimates	(25,208,000)	(103,529,000)
Net changes in prices and production costs	(4,323,000)	(52,170,000)
Accretion of discount	7,400,000	19,862,000
Sales of oil produced, net of production costs	80,000	191,000
Changes in future development costs	(107,000)	27,173,000
Changes in timing of future production	(15,706,000)	(16,145,000)
Net changes in income taxes	10,874,000	34,969,000
Standardized measure of discounted future net cash flows at the end of the year	$ 28,090,000	$ 55,080,000