As filed with the Securities and Exchange Commission on June 28, 2022

Registration No. 333-

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

PERMEX PETROLEUM CORPORATION

(Exact name of Registrant as specified in its charter)

100 Crescent Court, Suite 700

Dallas, Texas, 75201

(214) 459-2782

(Address, including zip code, and telephone number, including area code, of Registrant’s principal executive offices)

Mehran Ehsan

Permex Petroleum Corporation

100 Crescent Court, Suite 700

Dallas, Texas, 75201

(214) 459-2782

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act, check the following box. ☒

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

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

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 to Section 7(a)(2)(B) of the Securities Act. ☐

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. The selling shareholders may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

98,970,113

Common Shares

Permex Petroleum Corporation

This prospectus relates to the resale by certain selling shareholders of Permex Petroleum Corporation, a corporation organized under the laws of British Columbia, Canada (the “Company”), identified in this prospectus of up to 98,970,113 common shares (the “Resale Shares”) of the Company, no par value, including 51,841,488 Resale Shares issuable upon exercise of outstanding warrants. All of the Resale Shares were purchased from the Company in a private placement transaction.

The Resale Shares may be sold by the selling shareholders to or through underwriters or dealers, directly to purchasers or through agents designated from time to time. For additional information regarding the methods of sale you should refer to the section entitled “Plan of Distribution” in this prospectus.

The prices at which the selling shareholders may sell the Resale Shares will be determined by the prevailing market price for the Company’s common shares or in privately negotiated transactions. The Company will not receive any proceeds from the sale of the Resale Shares by the selling shareholders; provided, however, the Company will receive the proceeds from any cash exercise of warrants.

The Company will bear all costs relating to the registration of the Resale Shares, other than any selling shareholder’s legal or accounting costs or commissions.

The Company’s common shares are presently listed on the Canadian Securities Exchange and the Frankfurt Stock Exchange under the symbols “OIL” and “75P”, respectively, and quoted on the OTCQB tier of the OTC Markets Group, Inc. under the symbol “OILCF.” The closing price of the Company’s common shares on June 24, 2022, as reported by the OTCQB was $0.129 per share.

Investing in the Company’s common shares involves a high degree of risk. See the section entitled “Risk Factors” beginning on page 14 of this prospectus and elsewhere in this prospectus for a discussion of information that should be considered in connection with an investment in the Company’s common shares.

The Company may amend or supplement this prospectus from time to time by filing amendments or supplements as required. You should read the entire prospectus and any amendments or supplements carefully before you make your investment decision.

The Company is an “emerging growth company” as defined under the federal securities laws and, as such, may elect to comply with certain reduced public company reporting requirements. See “Prospectus Summary - Implications of Being an Emerging Growth Company.”

Neither the United States Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Prospectus dated               , 2022

TABLE OF CONTENTS

You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered or made available to you. We have not and the selling shareholders have not authorized anyone to provide you with different information. The selling shareholders are offering to sell, and seeking offers to buy, our common shares only in jurisdictions where offers and sales are permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of our common shares.

For investors outside the United States: Neither we nor the selling shareholders have done anything that would permit this offering or possession or distribution of this prospectus in any jurisdiction, other than the United States, where action for that purpose is required. Persons outside the United States who come into possession of this prospectus must inform themselves about, and observe any restrictions relating to, the offering of our common shares and the distribution of this prospectus outside the United States.

This prospectus is a part of a registration statement on Form S-1 that we filed with the Securities and Exchange Commission. The selling shareholders may from time to time sell the common shares covered by this prospectus and, in certain circumstances, we or the selling shareholders may provide a supplement to this prospectus that will contain certain specific information about the terms of a particular offering by one or more of the selling shareholders or to add information to, or update or change information contained in this prospectus. You should read this prospectus or any supplement to this prospectus before deciding to invest in our common shares. You may obtain this information without charge by following the instructions under “Where You Can Find Additional Information” appearing elsewhere in this prospectus.

GLOSSARY OF TERMS

Unless otherwise indicated in this 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 prospectus.

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.

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

“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.

“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.

PROSPECTUS SUMMARY

This summary highlights information contained in this prospectus. It does not contain all of the information that you should consider in making your investment decision. Before investing in our common shares, you should read this entire prospectus carefully, including the sections entitled “Risk Factors,” “Business” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes. Except as otherwise required by the context, 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 subsidiary. Certain operational terms used in this prospectus are defined in the “Glossary of Terms.” 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.

Company Overview

We are 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. We focus 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, we own and operate various oil and gas properties located in Texas and New Mexico. In addition, we hold various royalty interests in 73 wells and 5 permitted wells across 3,800 acres within the Permian Basin of West Texas and southeast New Mexico. Moreover, we own and operate more than 78 oil and gas wells, have more than 11,700 net acres of production oil and gas assets, 67 shut-in opportunities, 17 salt water disposal wells eliminating water disposal fees and decreasing OPEX and 2 water supply wells allowing for waterflood secondary recovery.

Oil and Gas Properties

The Company hired MKM Engineering, who prepared for the Company an Appraisal of Certain Oil and Gas Interests owned by Permex Petroleum Corporation located in New Mexico and Texas as of September 30, 2021 (the “2021 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, 2020 (the “2020 Appraisal Report” and together with the 2021 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 the registration statement for which this prospectus is a part of.

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 response 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 prospectus.

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.

The following tables show a summary of our reserves as of September 30, 2021 and September 30, 2020 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, 2021.

Composite Proved Reserve Estimates and Economic Forecasts for the year ended September 30, 2020.

Composite Probable Reserve Estimates and Economic Forecasts for the year ended September 30, 2021

Composite Probable Reserve Estimates and Economic Forecasts for the year ended September 30, 2020

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.

Conversion of Undeveloped Acreage

The Company’s process for converting undeveloped acreage to developed reserve is tied to whether there is any drilling being conducted on the acreage in question. During the fiscal year ended September 30, 2021, the Company did not commence drilling on any undeveloped acreage, no undeveloped reserves were converted into proved developed reserves, and there were no other material changes that occurred. The Company has also did not make any investments in, or make any progress towards, converting proved undeveloped reserves to proved developed reserves during the year ended September 30, 2021. The Company also has not begun drilling on any undeveloped acreage or make any investments in undeveloped reserves during 2022 as of the date hereof. The Company has not taken any actions towards developing proved undeveloped reserves due to the fact that the Company is a growth stage company, that is currently focused on expanding production on its currently producing wells.

Drilling Activities

The Company did not drill any wells during the last three fiscal years. As at September 30, 2021, the Company had 95 gross wells and 17.29 net productive wells, with 89 wells producing oil and six wells producing natural gas, and the Company’s gross developed acreage totaled 5,177 and net developed acreage totaled 3,942 with the following geographic breakdown:

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 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 3% of these leases have a two year expiry date from the date of this prospectus.

Sales and Production

The average sales prices of the Company’s oil and gas products sold in the fiscal years ended September 30, 2021, 2020 and 2019 was $46.86, $38.51, and $51.79, respectively.

The Company’s net production quantities by final product sold in the fiscal years ended September 30, 2021, 2020, and 2019 was 30,623.69 Boe, 20,112.44 Boe, and 1,112.87 Boe, respectively.

The Company’s average production costs per unit for the fiscal years ended September 30, 2021, 2020, and 2019, was $23.56, $27.93, and $32.59, respectively.

Texas Properties

Breedlove “B” Clearfork Leases

In September 2021, we, through our wholly-owned subsidiary, Permex Petroleum US Corporation, acquired 100% Working Interest and 81.75% Net Revenue Interest in the Breedlove “B” Clearfork leases. 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. It is bounded on the north by Dawson County, on the east by Howard County, on the south by Glasscock and Midland Counties, and on the west by Andrews County. There is a total of 25 vertical wells of which 12 are producers, 4 are saltwater disposal wells and 9 that are shut-in opportunities. In January 2022, we began the pilot re-entry on the Carter Clearfork well #5, which is one of 67 shut-in wells that we currently own. In addition, we have begun the permitting process for two locations on the Breedlove property for drilling and development. Upon approval of the permits by the regulatory body, we expect to compete in the Spraberry and Wolfcamp formations with possible fracking.

Pittcock Leases

The Pittcock Leases are situated in Stonewall County which 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. We hold 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. We hold 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 to the offset wells being the Pittcock wells located east boundary of the Windy Jones Property. We hold a 100% working interest in the Windy Jones Property and a 78.9% net revenue interest.

Mary Bullard Property

We acquired the Mary Bullard Property in August 2017. The Mary Bullard Property is located in Stonewall County, about 5 ½ miles south west 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. We hold a 100% working interest in the Mary Bullard Property and a 78.625% net revenue interest.

New Mexico Properties

In December 2017, Permex Petroleum US Corporation, our wholly-owned subsidiary, acquired the West Henshaw Property and the Oxy Yates Property.

West Henshaw Property

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. We hold a 100% working interest in the West Henshaw Property and a 72% net revenue interest.

In January 2022, we began the pilot re-entry on the West Henshaw well #15-3. The recompletion was successful and came online at an initial rate of 30 barrels of oil per day (“bopd”) and has stabilized at 15 bopd. Management believes the production rates from this mature, long-life well to continue with less than 10% decline year over year.

In April 2022, we began the re-entry on the West Henshaw well #6-10. The recompletion was successful and came online at an initial rate of 15 bopd and has stabilized at 10 bopd. Management believes the production rates from this mature, long-life well to continue with less than 10% decline year over year.

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. We hold a 100% working interest in the Oxy Yates Property and a 77% net revenue interest.

Royalty Interest Properties

During the year ended September 30, 2021,we acquired royalty interests in 73 producing oil and gas wells located in Texas and New Mexico.

Business Strategy

The principal elements of our business strategy include the following:

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.

Risk Factor Summary

Our business is subject to a number of risks of which you should be aware before making an investment decision. You should carefully consider all of the information set forth in this prospectus and, in particular, should evaluate the specific factors set forth under “Risk Factors” in deciding whether to invest in our common shares. Among these important risks are the following:

Corporate History

We were incorporated on April 24, 2017 under the laws of British Columbia, Canada. At March 31, 2022, we have one wholly-owned subsidiary, Permex Petroleum US Corporation, a corporation incorporated under the laws of New Mexico (Permex U.S.). 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 U.S. owns and operates oil and gas properties in New Mexico (Henshaw Property and the Oxy Yates Property).

Implications of Being an Emerging Growth Company

We are an “emerging growth company,” as defined in Section 2(a) of the Securities Act of 1933, as amended (the “Securities Act”), as modified by the Jumpstart Our Business Startups Act of 2012 (“JOBS Act”). As such, we are eligible to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002, as amended (“Sarbanes-Oxley Act”), and the requirement to present only two years of audited financial statements and only two years of related Management’s Discussion and Analysis of Financial Condition and Results of Operations in the registration statement of which this prospectus forms a part. We are currently utilizing or intend to utilize both of these exemptions. We have not made a decision whether to take advantage of any other exemptions available to emerging growth companies. We do not know if some investors will find our common shares less attractive as a result of our utilization of these or other exemptions. The result may be a less active trading market for our common shares and our share price may be more volatile.

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, such 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 consolidated 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.

We will remain an “emerging growth company” until the earliest of (a) the last day of the first fiscal year in which our annual gross revenues exceed $1.07 billion, (b) the date that we become a “large accelerated filer” as defined in Rule 12b-2 under the Securities Exchange Act of 1934, as amended, (c) the date on which we have issued more than $1.0 billion in nonconvertible debt during the preceding three-year period or (d) the last day of our fiscal year containing the fifth anniversary of the date on which we complete our initial public offering of securities.

We have elected to take advantage of certain of the reduced disclosure obligations in this prospectus and in our filings with the SEC that are incorporated by referenced herein. As a result, the information that we provide to our shareholders may be different than you might receive from other public reporting companies in which you hold equity interests.

THE OFFERING

The following summary is provided solely for convenience and is not intended to be complete. You should read the full text and more specific details contained elsewhere in this prospectus.

The number of common shares shown above to be outstanding after this offering is based on 115,956,026 common shares outstanding as of June 24, 2022. This number of common shares excludes:

RISK FACTORS

Investing in our common shares involves a high degree of risk. You should carefully consider the risks and information below and elsewhere in this prospectus, including our consolidated financial statements and the related notes thereto, before making an investment decision. We describe risks below that we currently believe are the material risks of our business, our industry and our common shares. These are not the only risks we face. We are subject to risks that are currently unknown to us, or that we may currently believe are remote or immaterial. If any of these risks or events occurs, our business, financial condition and operating results could be harmed. In that case, the trading price of our common shares could decline, and you might lose all or part of your investment in our common shares.

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 may 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.

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 indebtedness could adversely affect our ability to raise additional capital to fund operations.

We currently have one outstanding secured convertible debenture in the original principal amount of $79,000 (C$100,000) (excluding interest accrued thereon) issued to Mehran Ehsan, our Chief Executive Officer, President and director, which is secured by all of our right, title and interest in the Properties (as defined in the Security Agreement between us the Mehran Ehsan dated February 21, 2020) together with all engineering reports and intellectual property related to, or generated by us, in connection with the Properties (collectively, the “Collateral”). The secured debenture remains outstanding as of June 24, 2022.

If we cannot generate sufficient cash flow from operations to service our debt, we may need to, among other things, dispose of some or all of the Collateral or issue equity to obtain necessary funds. We do not know whether we will be able to do any of this on a timely basis, on terms satisfactory to us, or at all. Our indebtedness could have important consequences, including:

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 have been volatile, 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:

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:

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.

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 recently acquired assets or 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 our acquisitions will depend in part upon 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:

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we have performed reviews of the subject properties that we believe to be generally consistent with industry practices. The reviews are 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 are typically 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 of the 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.

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:

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 (“PHMSA”), 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.

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 92% of our estimated net proved reserves volumes were classified as proved undeveloped as of September 30, 2021. 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 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.

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, 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.

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 E&P companies of purposefully obscuring consequences of combusting hydrocarbon.

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 stock 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 or transportation capacity constraints, (iv) market limitations, (v) availability of equipment and personnel, (vi) water shortages or other drought related conditions or (vii) interruption of the processing or transportation 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.

Increased attention to environmental, social and governance (“ESG”) matters may impact our business.

Increasing attention to climate change, increasing societal expectations on companies to address climate change, increasing investor and societal expectations regarding voluntary ESG disclosures, and potential increasing consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our access to capital markets. Increasing attention to climate change, for example, may result in demand shifts for natural gas and oil products and additional governmental investigations and private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital, or negative tax or other cost consequences.

Under some analyses, the world already produces more fossil fuel from existing sources than can be consumed over remaining resources service lives, if incremental global warming is to be kept under 1.5 degrees Celsius. Financing may be increasingly challenging, as pension funds (e.g., for major municipalities such as Boston, MA) and financial institutions divest fossil fuel investments.

The COVID-19 pandemic has had, and may continue to have, a material adverse effect on our financial condition and results of operations.

We face risks related to public health crises, including the COVID-19 pandemic. The effects of the COVID-19 pandemic, including travel bans, prohibitions on group events and gatherings, shutdowns of certain businesses, curfews, shelter-in-place orders and recommendations to practice social distancing in addition to other actions taken by both businesses and governments, resulted in a significant and swift reduction in international and U.S. economic activity. The collapse in the demand for oil caused by this unprecedented global health and economic crisis contributed to the significant decrease in crude oil prices in 2020 in general and resulted in shut down of our wellbores which had and could in the future continue to have a material adverse impact on our financial condition and results of operations.

Since the beginning of 2021, the distribution of COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded. However, we continue to monitor the effects of the pandemic on our operations. As a result of the ongoing COVID-19 pandemic, our operations, and those of our operating partners, have and may continue to experience delays or disruptions and temporary suspensions of operations and increased volatility. In addition, our results of operations and financial condition have been and may continue to be adversely affected by the ongoing COVID-19 pandemic.

The extent to which our operating and financial results are affected by COVID-19 will depend on various factors and consequences beyond our control, such as the emergence of more contagious and harmful variants of the COVID-19 virus, the duration and scope of the pandemic, additional actions by businesses and governments in response to the pandemic, and the speed and effectiveness of responses to combat the virus. COVID-19, and the volatile regional and global economic conditions stemming from the pandemic, could also aggravate the other risk factors that we identify herein. While the effects of the COVID-19 pandemic have lessened recently in the United States, we cannot predict the duration or future effects of the pandemic, or more contagious and harmful variants of the COVID-19 virus, and such effects may materially adversely affect our results of operations and financial condition in a manner that is not currently known to us or that we do not currently consider to present significant risks to our operations.

The loss of any member of our management team, upon whose knowledge, relationships with industry participants, leadership and technical expertise we rely could diminish our ability to conduct our operations and harm our ability to execute our business plan.

Our success depends heavily upon the continued contributions of those members of our management team whose knowledge, relationships with industry participants, leadership and technical expertise would be difficult to replace. In particular, our ability to successfully acquire additional properties, to increase our reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements depends on developing and maintaining close working relationships with industry participants. In addition, our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment is dependent on our management team’s knowledge and expertise in the industry. To continue to develop our business, we rely on our management team’s knowledge and expertise in the industry. The members of our management team may terminate their employment with our Company at any time. If we were to lose members of our management team, we may not be able to replace the knowledge or relationships that they possess and our ability to execute our business plan could be materially harmed.

We are substantially dependent on a limited number of customers

For the years ended September 30, 2021 and 2020, we had one and one significant purchaser, respectively, that accounted for approximately 49% and 45%, respectively, of our total oil, natural gas and NGL 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. Additionally, there are no assurances that we will be able to expand our customer base. If we are unable to attract and maintain an adequate customer base to generate revenues, we will have to suspend or cease operations.

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.

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, which could have an adverse effect on our expected production, other operations and financial condition.

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, certain of these changes were considered for inclusion in the proposed “Build Back Better Act” and 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.

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.

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 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.

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. In November 15, 2021, the EPA proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. EPA hopes to finalize the proposed regulations by the end of 2022. Once finalized, the regulations are likely to be subject to legal challenge, and will also need to be incorporated into the states’ implementation plans, which will need to be approved by the EPA in individual rulemakings that could also be subject to legal challenge. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to our operations. 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 common shares. 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.

Risks Related to this Offering and our Common Shares

The market price of our common shares 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 common shares to sell their securities at an advantageous price. Market price fluctuations in our common shares 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 common shares. 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.

Accordingly, the market price of our common shares 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 common shares 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 common shares may be materially adversely affected.

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

There is no assurance that an investment in our common shares will earn any positive return. An investment in our common shares 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 common shares 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.

There is a limited market for our common shares.

Our common shares are listed for trading on the Canadian Securities Exchange and the Frankfurt Stock Exchange and are quoted over-the-counter in the United States on the OTCQB of the OTC Markets Group, Inc. The over-the-counter markets provide less liquidity than U.S. national securities exchanges, such as the New York Stock Exchange or Nasdaq. Accordingly, a market for our common shares may become highly illiquid and holders of our common shares may be unable to sell or otherwise dispose of their common shares at desirable prices or at all.

Outstanding and future issuances of debt securities, which would rank senior to our common shares upon bankruptcy or liquidation, may adversely affect the level of return holders of common shares may be able to receive. In the future, we may increase our capital resources by offering additional debt securities. Upon bankruptcy or liquidation, holders of our debt securities and lenders would receive distributions of our available assets prior to any distributions being made to holders our common shares. As our decision to issue debt securities or borrow money from lenders will depend in part on market conditions, we cannot predict or estimate the amount, timing, or nature of any such future offerings or borrowings. Holders of our common shares must bear the risk that current and future securities including the issuance of debt securities may adversely affect the level of return, if any, that the holders of our common shares may receive.

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 options, warrants and a convertible debenture and may continue to issue additional securities in the future. The exercise and/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 June 24, 2022, we have issued and outstanding options to purchase 5,575,000 common shares with a weighted average exercise price of $0.24 per share, warrants to purchase 65,825,806 common shares with a weighted average exercise price of $0.21 per share, and a debenture in the original principal amount of $79,000 (C$100,000) (excluding interest thereon) convertible into 666,667 common shares and warrants to purchase an additional 666,667 common shares. In addition, we have 6,020,603 common shares available for future issuance under our 2017 and 2022 Stock Option Plans. 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. Furthermore, the mere existence of a significant number of common shares issuable upon exercise and/or conversion 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.

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.

General Risk Factors

We are an “emerging growth company” and will be able to avail ourselves of reduced disclosure requirements applicable to emerging growth companies, which could make our common shares less attractive to investors.

We are an “emerging growth company,” as defined in 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 of 2002, as amended, 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 cannot predict if investors will find our common shares attractive because we may rely on these exemptions. If some investors find our common shares less attractive as a result, there may be a less active trading market for our common shares and our stock price may be more volatile. 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.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical fact included in this prospectus, 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 prospectus, 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:

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, incident to the exploration for and development, production and sale of natural gas. 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 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 prospectus 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 prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

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 prospectus.

MARKET FOR OUR COMMON STOCK AND RELATED STOCKHOLDER MATTERS

Market Information

Our common shares currently trades on the OTCQB Marketplace in the United States under the symbol “OILCF” on the Canadian Securities Exchange in Canada under the symbol “OIL” and under the Frankfort Stock Exchange under the symbol “75P”,

Shareholders

As of June 24, 2022, there were 115,956,026 common shares issued and outstanding, held by approximately 66 holders of record, although there are a much larger number of beneficial owners.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table summarizes information about our equity compensation plans as of September 30, 2021.

DIVIDENDS AND 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 do not currently pay dividends. Accordingly, we may, but do not anticipate, declaring or paying any dividends for the foreseeable future.

CAPITALIZATION

The following table sets forth our cash and cash equivalents and our capitalization as of March 31, 2022:

You should read this table in conjunction with the sections titled and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes included elsewhere in this prospectus.

The number of common shares is based on  115,956,026 common shares issued and outstanding as of March 31, 2022, and excludes the following as of such date:

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 prospectus. Some of the information contained in this discussion and analysis or set forth elsewhere in this prospectus, 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 prospectus 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.

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 various oil and gas properties located in Texas and New Mexico. In addition, the Company holds various royalty interests in 73 wells and 5 permitted wells across 3,800 acres within the Permian Basin of West Texas and southeast New Mexico. Moreover, the Company owns and operates more than 78 oil and gas wells, has more than 11,700 net acres of production oil and gas assets, 67 shut-in opportunities, 17 salt water disposal wells eliminating water disposal fees and decreasing OPEX and 2 water supply wells allowing for waterflood secondary recovery.

Key Activities:

Impact of Covid-19

In March 2020 the World Health Organization declared coronavirus COVID-19 a global pandemic. This contagious disease outbreak, which has continued to spread, and any related adverse public health developments, has adversely affected workforces, economies, and financial markets globally, potentially leading to an economic downturn. Specifically, the effects of the COVID-19 pandemic, including travel bans, prohibitions on group events and gatherings, shutdowns of certain businesses, curfews, shelter-in-place orders and recommendations to practice social distancing in addition to other actions taken by both businesses and governments, resulted in a significant and swift reduction in international and U.S. economic activity. The collapse in the demand for oil caused by this unprecedented global health and economic crisis contributed to the significant decrease in crude oil prices in 2020 in general and resulted in shut down of the Company’s wellbores which had and could in the future continue to have a material adverse impact on the Company’s financial condition and results of operations. As a result of the ongoing COVID-19 pandemic, the Company’s operations, and those of its operating partners, have and may continue to experience delays or disruptions and temporary suspensions of operations and increased volatility. In addition, the Company’s results of operations and financial condition have been and may continue to be adversely affected by the ongoing COVID-19 pandemic; however, it is not possible for the Company to predict the duration or magnitude of the adverse results of the outbreak and its effects on the Company’s business or ability to raise funds at this time. The Company is closely monitoring developments and adapting its business plans accordingly.

Oil and Gas Properties

The Company hired MKM Engineering, who prepared for the Company the Appraisal Reports. Each of the Appraisal Reports used standard engineering practices generally accepted by the petroleum industry and conform to SEC Pricing. The Appraisal Reports are each filed as an exhibit to the registration statement for which this prospectus is a part of. 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 the registration statement for which this prospectus is a part of.

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 response 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 prospectus.

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.

The following tables show a summary of our reserves as of September 30, 2021 and September 30, 2020 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, 2021.

Composite Proved Reserve Estimates and Economic Forecasts for the year ended September 30, 2020.

Composite Probable Reserve Estimates and Economic Forecasts for the year ended September 30, 2021

Composite Probable Reserve Estimates and Economic Forecasts for the year ended September 30, 2020

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.

Conversion of Undeveloped Acreage

The Company’s process for converting undeveloped acreage to developed reserve is tied to whether there is any drilling being conducted on the acreage in question. During the fiscal year ended September 30, 2021, the Company did not commence drilling on any undeveloped acreage, no undeveloped reserves were converted into proved developed reserves, and there were no other material changes that occurred. The Company has also did not make any investments in, or make any progress towards, converting proved undeveloped reserves to proved developed reserves during the year ended September 30, 2021. The Company also has not begun drilling on any undeveloped acreage or make any investments in undeveloped reserves during 2022 as of the date hereof. The Company has not taken any actions towards developing proved undeveloped reserves due to the fact that the Company is a growth stage company, that is currently focused on expanding production on its currently producing wells.

Drilling Activities

The Company did not drill any wells during the last three fiscal years. As at September 30, 2021, the Company had 95 gross wells and 17.29 net productive wells, with 89 wells producing oil and six wells producing natural gas, and the Company’s gross developed acreage totaled 5,177 and net developed acreage totaled 3,942 with the following geographic breakdown:

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 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 3% of these leases have a term that expires within two years of the date of this prospectus.

Sales and Production

The average sales prices of the Company’s oil and gas products sold in the fiscal years ended September 30, 2021, 2020 and 2019 was $46.86, $38.51, and $51.79, respectively.

The Company’s net production quantities by final product sold in the fiscal years ended September 30, 2021, 2020, and 2019 was 30,623.69 Boe, 20,112.44 Boe, and 1,112.87 Boe, respectively.

The Company’s average production costs per unit for the fiscal years ended September 30, 2021, 2020, and 2019, was $23.56, $27.93, and $32.59, respectively.

Breedlove “B” Clearfork Leases – 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 25 vertical wells of which 12 are producers, 4 are saltwater disposal wells and 9 that are shut-in opportunities.

Permex holds a 100% working interest and an 81.75% net revenue interest in the Breedlove “B” Clearfork Property.

Pittcock Leases – Texas

The Pittcock Leases are situated in Stonewall County. Stonewall County is in Northwest Texas, in the central part of the North Central Plains and consist of the Pittcock North property, the Pittcock South property and the Windy Jones Property.

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. Permex 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. Permex holds a 100% working interest in the lease, and a 71.90% net revenue interest.

The Windy Jones Property consists of forty acres and includes two injection wells and two suspended oil wells. The sole purpose of the Windy Jones property is to provide waterflood to the offset wells being the Pittcock wells located east boundary of the Windy Jones property. Permex holds a 100% working interest in the Windy Jones Property, and a 78.9% net revenue interest.

Mary Bullard Property - Texas

The Mary Bullard Property is located in Stonewall County, about 5 ½ miles south west of Aspermont, Texas. 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. Permex holds a 100% working interest in the Mary Bullard Property, and a 78.625% net revenue interest.

West Henshaw Property and Oxy Yates 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. Permex holds a 100% working interest in the West Henshaw Property, and a 72% net revenue interest.

The Oxy Yates Property is located in Eddy County, approximately eight miles north of Carlsbad, New Mexico in the Delaware Basin. 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. Permex holds a 100% working interest in the Oxy Yates Property, and a 77% net revenue interest.

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, 2021 and 2020.

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

Net losses for the years ended September 30, 2021 and 2020 were mainly attributable to general administrative expenses (2021 - $590,239, 2020 - $498,752) and loss on disposal of properties (2021 - $613,457, 2020 - $879,070). The decrease in revenue in fiscal 2021 and 2020 is due to the significant decline in oil prices in the middle of the fiscal 2020. Oil production on all the Company’s properties were shut down for four months in fiscal 2020 due to a steep decline in the price of oil during 2020. The Company sold its interest in ODC San Andres Unit and W.J. “A” Taylor leases in October 2020. All other oil and gas wells remained shut down until May 2021. The increase in total assets in fiscal 2021 is due to the acquisition of Breedlove “B” Clearfork properties. The decrease in non-current liabilities in fiscal 2020 is due to the reclassification of decommissioning obligations related to ODC San Andres Unit and W.J. “A” Taylor leases to current liabilities held for sale. The increase in non-current liabilities in fiscal 2021 is due to the recognition of decommissioning obligations related to the newly acquired Breedlove “B” Clearfork properties.

Discussion of Operations

Years Ended September 30, 2021 and 2020

During the year ended September 30, 2021, the Company reported a net loss of $1,245,057 as compared to a net loss of $1,249,202 for the year ended September 30, 2020. Revenue from oil and gas production decreased 93% to $46,703 (2020 - $682,786). The decrease is the result of the sale of ODC San Andres Unit and W.J. “A” Taylor leases in October 2020 and the complete shut down of production from July 2020 in response to the steep decline in oil price. During the last six months of 2021, the Company has been working to bring the Pittcock North, Mary Bullard and Henshaw properties back online. The Pittcock North and Mary Bullard wells generated the first oil sales in June 2021. The royalty income of $37,922 (2020 - $Nil) is generated from royalty interests acquired in early 2021. The Company has acquired royalty interests in 73 wells located in Texas and New Mexico for a total investment of $179,095.

The general administrative expenses excluding depletion and depreciation and share-based payment expenses for the ended September 30, 2021 were $526,890 (2020 - $457,286) and were generally consistent with fiscal 2020. Some of the significant expense items are summarized as follows:

Share-based compensation expenses of $2,870 (2020 - $4,175), a non-cash charge, are the estimated fair value of the stock options granted and vested during the period. The Company used the Black-Scholes option pricing model for the fair value calculation.

During the year ended September 30, 2021, the Company assessed a loss of $613,457 on the sale of the Peavy leases and office equipment (2020 - $879,070 on the ODC and Taylor leases). The Company also realized a loss of $50,165 (2020 - $Nil) on forfeiture of reclamation deposit.

Three Months Ended March 31, 2022 and 2021

During the three months ended March 31, 2022, the Company reported a net loss of $144,953 as compared to a net loss of $196,023 for the three months ended March 31, 2021. Revenue for the second quarter consisted of oil and gas sales of $228,497 (2021 - $40) and royalty income of $13,389 (2021 - $nil). Revenue from the Company’s newly acquired Breedlove “B” Clearfork leases accounted for 64% of the total oil and gas sales. The Company also brought Pittcock North, Mary Bullard, and West Henshaw wells back online during the second quarter. The direct producing and operating expenses were $115,000, approximately 51% of the gross sales. The general administrative expenses excluding depletion and depreciation, and share-based payment expenses for the three months ended March 31, 2022 were $213,783 (2021 - $132,526). The variance was mainly attributable to accounting and audit fees of $51,280 (2021 - $18,397), investor relations of $18,266 (2021 - $1,351), legal fees of $18,435 (2021 - $nil), and management fees of $59,393 (2021 - $37,513). The increase is mainly due to the increased field and general corporate activities as a result of the increased oil and gas productions and the brokered financing completed in the second quarter.

Six Months Ended March 31, 2022 and 2021

During the six months ended March 31, 2022, the Company reported a net loss of $967,709 as compared to a net loss of $307,356 for the six months ended March 31, 2021. Revenue for the first six months consisted of oil and gas sales of $318,487 (2021 - $3,094) and royalty income of $29,848 (2021 - $nil). Revenue from the Company’s newly 5 acquired Breedlove “B” Clearfork leases accounted for 67.5% of the total oil and gas sales. The Company also brought Pittcock North, Mary Bullard, and West Henshaw wells back online during the second quarter. For the three and six months, the company has produced 35 bopd and 43 bopd, respectively. The direct producing and operating expenses were $196,879, approximately 62% of the gross sales.

The general administrative expenses excluding depletion and depreciation and share-based payment expenses for the six months ended March 31, 2022 were $418,575 (2021 - $218,489). The variance was mainly attributable to:

Liquidity and Capital Resources

As at March 31, 2022, the Company had a cash balance of $6,727,758, an increase of $6,701,952 from the cash balance of $25,806 on September 30, 2021. During the six months ended March 31, 2022, cash used in the operating activities is $245,954. The Company spent $75,834 on capital expenditures on its oil and gas assets and $27,774 on office lease payments. The Company received net proceeds of $7,050,714 from private placement financings and paid outstanding interest of $18,960 on the debenture loan.

The Company had a working capital of $6,243,776 as at March 31, 2022 compared to a working capital deficiency of $465,129 as at September 30, 2021.

As at September 30, 2021, the Company had a cash balance of $25,806, an increase of $20,289 from the cash balance of $5,517 on September 30, 2020. During the year ended September 30, 2021, cash used in operating activities was $720,987. The Company spent $250,581 on capital expenditures on its oil and gas assets and $43,932 on office lease payments. The Company received net proceeds of $1,123,244 from the sale of ODC San Andres Unit and W.J. “A” Taylor leases. The Company repaid debenture loan of $79,000 and a related party loan of $8,455 during fiscal 2021.

The Company had a working capital deficiency of $465,129 as at September 30, 2021 compared to working capital of $227,815 as at September 30, 2020.

Although the Company expects to invest additional capital on the continued development of its oil and gas operations, the Company currently does not have material commitments for capital expenditures. As of both March 31, 2022 and the date of this prospectus, the Company has sufficient working capital to meet its anticipated operating and capital requirements. The Company will continue to monitor the current economic and financial market conditions and evaluate their impact on the Company’s liquidity and future prospects.

Related Party Transactions

Year Ended September 30, 2021 and 2020

During the year ended September 30, 2020, the Company issued a total of $150,000 (C$200,000) in convertible debentures to the CEO and a director of the Company on October 17, 2019 and February 21, 2020, respectively, for cash. The debentures are secured by an interest in all of the Company’s right, title, and interest in all of its oil and gas assets, have a maturity date of September 30, 2021 and February 20, 2022, and bear interest at a rate of 12% per annum, payable on maturity. The debentures are convertible at the holder’s option into units of the Company at $0.12 (C$0.15) per unit. Each unit will be comprised of one common share of the Company and one share purchase warrant; each warrant entitles the holder to acquire one additional common share for a period of three years at an exercise price of $0.16. During the year ended September 30, 2021, the Company repaid $79,000 (C$100,000) of the convertible debenture together with accrued interest of $13,090. During the year ended September 30, 2021 and 2020, the Company accrued interest of $9,480 and $13,991, respectively, and is included within amounts due to related party on the consolidated balance sheets. As at September 30, 2021, $78,500 (C$100,000) of debenture loan remained outstanding and the interest accrued on the loan was $15,176 (2020 - $14,104).

The Company entered into the following transactions relating to key management personnel and entities over which they have control or significant influence during the year ended September 30, 2021:

The Company has entered into an employment agreement with the CEO of the Company for an annual base salary of $150,000, with no specified term. The employment agreement may be terminated with a termination payment equal to twelve months of accrued base salary and a bonus equal to 20% of the annual salary. Effective October 1, 2021, the annual base salary has been increased to $200,000.

Six Months Ended March 31, 2022 and 2021

As at March 31, 2022, the Company had a convertible debenture of $79,000 (C$100,000) due to the CEO. The debentures are secured by an interest in all of the Company’s right, title, and interest in all of its oil and gas assets, have a maturity date of August 20, 2022, and bear interest at a rate of 12% per annum, payable on maturity. The debentures are convertible at the holder’s option into units of the Company at $0.12 (C$0.15) per unit. Each unit will be comprised of one common share of the Company and one share purchase warrant; each warrant entitles the holder to acquire one additional common share for a period of three years at an exercise price of $0.16. During the six months ended March 31, 2022 and 2021, the Company recorded interest of $3,688 and $9,768, respectively, and is included within amounts due to related party on the consolidated balance sheets.

During the six month period ended March 31, 2022, the Company incurred management fees of $109,773 (2021 - $75,116) to a company controlled by the CEO of the Company.

The Company had entered into an employment agreement with the CEO of the Company for an annual base salary of $200,000, with no specified term. The employment agreement may be terminated with a termination payment equal to twelve months of base salary and a bonus equal to 20% of the annual salary.

Subsequent to March 31, 2022, the Company amended the employment with the CEO of the Company for an annual base salary of $250,000, with no specified term. The CEO is also eligible on an annual basis for a cash bonus of up to 100% of annual salary. The employment agreement may be terminated with a termination payment equal to three years of base salary and a bonus equal to 20% of the annual base salary.

Subsequent to March 31, 2022, the Company entered into an employment 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. The employment agreement may be terminated with a termination payment equal to two months of base salary.

 Critical Accounting Estimates

The preparation of the Company’s consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of expenses during the period. Actual results could differ from these estimates. The Company’s management reviews these estimates and underlying assumptions on an ongoing basis, based on experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Revisions to estimates are adjusted for prospectively in the period in which the estimates are revised. Significant areas requiring the use of management estimates include:

Decommissioning obligations

Decommissioning obligations require the use of management’s best estimates of future decommissioning expenditures, expected timing of expenditures and future inflation rates. A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risk specific to the liability. Provisions are not recognized for future operating losses.

Provisions for decommissioning associated with the Company’s oil and gas operations are based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows may differ from estimates due to changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean up technology. Estimates are made using internal and external information.

Depreciation

Equipment is amortized over the estimated useful life of the assets. Changes in the estimated useful lives or depreciation rate used could significantly increase or decrease the amount of depreciation recorded during the period and the carrying value of equipment.

Petroleum and natural gas interests

Reserves resources are used in the unit-of-production calculation for depreciation and depletion and the impairment analysis, which affects net loss. There are numerous uncertainties inherent in estimating petroleum and natural gas (“P&NG”) reserves. Estimating reserves is complex, requiring many judgments based on geological, geophysical, engineering and economic data. Changes in these judgments could have a material impact on the estimated reserves. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available and as the economic environment changes.

Share-based payments

The determination of the fair value of stock options and agent’s warrants using stock pricing models, require the input of highly subjective assumptions, including the expected price volatility. Changes in the subjective input assumptions could materially affect the fair value estimate.

Financial Instruments

The Company classified its financial instruments as follows: cash, trade and other receivables, and reclamation deposits as subsequently measured at amortized cost; and trade and other payables, amounts due to related parties, loan payable, and convertible debentures – loan component as subsequently measured at amortized cost financial liabilities.

The carrying amount of cash, trade and other receivables, reclamation deposits, trade and other payables, amounts due to related parties, loan payable, and convertible debentures carried at amortized cost is a reasonable approximation of fair value due to the relatively short period to maturity of these financial instruments and/or the rate of interest being charged.

Financial risk management

The Company’s financial risks arising from its financial instruments are credit risk, liquidity risk, foreign currency exchange risk, interest rate risk and commodity price risk. The Company’s exposures to these risks and the policies on how to mitigate these risks are set out below. Management monitors and manages these exposures to ensure appropriate measures are implemented on a timely basis and in an effective manner.

Credit risk

Credit risk is the risk of potential loss to the Company if the counter party to a financial instrument fails to meet its contractual obligations. The credit risk of the Company is associated with cash, trade and other receivables, and reclamation deposits. The credit risk with respect to its cash and reclamation deposits is minimal as they are held with high-credit quality financial institutions. The Company’s Goods and Services Tax recoverable is due from the Canadian Government. Management does not expect these counterparties to fail to meet their obligations. The Company does not anticipate any default of its trade receivables, as it transacts with creditworthy customers and management does not expect any losses from non-performance by these customers.

Liquidity risk

Liquidity risk is the risk that the Company will not meet its obligations associated with its financial liabilities as they fall due. The Company performs cash flow forecasting to ensure sufficient cash is available to fund its projects and operations. As at September 30, 2021, the Company has current assets of $84,941 and current liabilities of $550,070. The Company’s financial liabilities include accrued expenses and trade and other payables which have contractual maturities of 30 days or are due on demand and debenture loan due within the next 12 months.

At present, the Company’s operations do not generate positive cash flows. The Company’s primary source of funding has been the issuance of equity securities through private placements and revenue from oil and gas production. Despite previous success in acquiring these financings, there is no guarantee of obtaining future financings.

Foreign exchange rate risk

Foreign currency exchange risk is the risk that fair value or future cash flows of a financial instrument will fluctuate because of changes in foreign exchange rates. The Company’s administrative expenditures are transacted in Canadian dollars. The Company funds its oil and gas operations in the United States by using United States dollars (“US dollars”) converted from its Canadian bank accounts. At September 30, 2021, the Company had financial assets of $5,846 and financial liabilities of $106,456 denominated in Canadian dollars. A 10% strengthening of the US dollar would affect net loss by approximately $10,000. The Company does not hedge its foreign exchange risk.

Interest rate risk

The Company is exposed to interest rate risk arising from cash held in Canadian financial institutions. The interest rate risk on cash is not considered significant due to its short-term nature and maturity. The exposure to interest rates for the Company is considered minimal. The Company has not used any financial instrument to hedge potential fluctuations in interest rates.

Commodity price risk

Commodity price risk is the risk that future cash flows will fluctuate as a result of changes in the price of oil and natural gas. Commodity prices are impacted by world economic events that affect supply and demand, which are generally beyond the Company’s control. Changes in crude oil prices may significantly affect the Company’s results of operations, cash generated from operating activities, capital spending and the Company’s ability to meet its obligations. The Company manages this risk by constantly monitoring commodity prices and factoring them into operational decisions, such as contracting or expanding its capital expenditures program.

Outstanding Share Data

The Company had the following common shares, stock options and warrants outstanding as of June 24, 2022.

BUSINESS

Overview

We are 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. We focus 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, we own and operate various oil and gas properties located in Texas and New Mexico. In addition, we hold various royalty interests in 73 wells and 5 permitted wells across 3,800 acres within the Permian Basin of West Texas and southeast New Mexico. Moreover, we own and operate more than 78 oil and gas wells, have more than 11,700 net acres of production oil and gas assets, 67 shut-in opportunities, 17 salt water disposal wells eliminating water disposal fees and decreasing OPEX and 2 water supply wells allowing for waterflood secondary recovery.

Oil and Gas Properties

The Company hired MKM Engineering, who prepared for the Company 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 the registration statement for which this prospectus is a part of.

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 response 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 prospectus.

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.

The following tables show a summary of our reserves as of September 30, 2021 and September 30, 2020 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, 2021.

Composite Proved Reserve Estimates and Economic Forecasts for the year ended September 30, 2020.

Composite Probable Reserve Estimates and Economic Forecasts for the year ended September 30, 2021

Composite Probable Reserve Estimates and Economic Forecasts for the year ended September 30, 2020