Permex Petroleum Corp - Annual Report: 2022 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

Commission file number: 000-41558

PERMEX PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (469) 804-1306

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

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

None

(Title of class)

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

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

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

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

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act):

Yes ☐ No ☒

The aggregate market value of common shares held by non-affiliates of the registrant as of March 31, 2022 was approximately $7,329,774.

The number of outstanding shares of the registrant’s common shares as of February 10, 2023 was 1,932,604.

DOCUMENTS INCORPORATED BY REFERENCE

None

PERMEX PETROLEUM CORPORATION

FORM 10-K

PERMEX PETROLEUM CORPORATION

FORM 10-K

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

GLOSSARY OF TERMS

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

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

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

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

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

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

“MBoe” One thousand barrels of oil equivalent.

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

“MMCF.” one million cubic feet.

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

Terms used to describe our interests in wells and acreage:

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

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

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

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

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

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

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

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

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

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

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

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

“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.

MARKET AND INDUSTRY INFORMATION

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

FORWARD LOOKING STATEMENTS

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

Forward-looking statements may include statements about:

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

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

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

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

PART I

ITEM 1. BUSINESS

Overview

We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas properties on private, state and federal land in the United States, primarily in the Permian Basin region of West Texas and Southeast New Mexico which includes the Midland – Central 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 as well as royalty interests in 73 wells and five permitted wells across 3,800 acres within the Permian Basin. Overall, we own and operate more than 78 oil and gas wells, have more than 11,700 net acres of production oil and gas assets, 62 shut-in opportunities, 17 salt water disposal wells and two water supply wells allowing for waterflood secondary recovery.

Corporate History

We were incorporated on April 24, 2017 under the laws of British Columbia, Canada. At September 30, 2022, we have one wholly-owned subsidiary, Permex Petroleum US Corporation (“Permex U.S.”), a corporation incorporated under the laws of New Mexico. We own and operate oil and gas properties in Texas (Breedlove “B” Property, Pittcock North Property, Pittcock South Property and Mary Bullard Property), and Permex U.S. owns and operates oil and gas properties in New Mexico (Henshaw Property and the Oxy Yates Property).

Oil and Gas Properties

The Company hired MKM Engineering, who prepared the Appraisal Reports. MKM Engineering is independent with respect to Permex as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. MKM Engineering’s estimates of the Company’s proved and probable reserves in each of the Appraisal Reports were prepared according to generally accepted petroleum engineering and evaluation principles, and each of the Appraisal Reports conform to SEC Pricing. The Appraisal Reports are each filed as an exhibit to this Annual Report.

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

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

The following tables show a summary of our reserves as of September 30, 2022 and September 30, 2021 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, 2022

Composite Proved 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, 2022

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

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 acreage is tied to whether there is any drilling being conducted on the acreage in question. During the fiscal year ended September 30, 2022, the Company made investment in and made progress towards, converting proved undeveloped reserves to proved developed reserves. The Company began drilling on undeveloped acreage and made investments in undeveloped reserves from September 30, 2022 to the date hereof.

An aggregate of 5,083 MBO and 2,136 MMCF, of the Company’s proved undeveloped reserves as of September 30, 2022, are part of a development plan that has been adopted by management that calls for these undeveloped reserves to be drilled within the next five years, thus resulting in the conversion of such proved undeveloped reserves to developed status within five years of initial disclosure at September 30, 2022.

Proved Undeveloped Reserves Additions

From September 30, 2021 to September 30, 2022, the Company had no proved undeveloped reserve additions. The specific changes to the Company’s proved undeveloped reserves from September 30, 2021 to September 30, 2022 were as follows:

Financing of Proved and Probable Undeveloped Reserves

The Company currently estimates that the total cost to develop the Company’s proved undeveloped reserves of 5,083.2 MBbl of oil and 2,136.4 Mcf of natural gas as of September 30, 2022 is $68,818,530. The Company expects to finance these capital costs through a combination of current cash on hand, debt financing through a line of credit or similar debt instrument, one or more offerings of debt or equity, and from cash generated from estimated revenues from sales of oil and natural gas produced at the Company’s wells.

The Company currently estimates that the total cost to develop the Company’s probable undeveloped reserves of 7,334.3 MBbl of oil and 10,307.1 Mcf of natural gas as of September 30, 2022 is $107,884,900. The Company expects to finance these capital costs through a combination of joint ventures, farm-in agreements, direct participation programs, one or more offerings of equity, a debt offering or entering into a line of credit, and from cash generated from estimated revenues from sales of oil and natural gas produced at the Company’s wells.

Drilling Activities

The Company drilled one well during the last three fiscal years. As at September 30, 2022, the Company held leases for 78 gross wells and had leases and royalty interests in an aggregate of 102 gross productive wells (including 73 wells that we acquired royalty interests in 2021). The Company’s gross developed acreage totaled 5,177 and net developed acreage totaled 3,942 with the following property 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 5% of these leases have an expiry date that is less than two years from the date of this Annual Report.

Sales and Production

The average sales prices of the Company’s oil and gas products sold in the fiscal years ended September 30, 2022, 2021, and 2020 was $89.14, $54.19, and $38.51, respectively.

The Company’s net production quantities by final product sold in the fiscal years ended September 30, 2022, 2021, and 2020, was 12,597.45 Boe, 1,182.70 Boe, and 17,772.14 Boe, respectively.

The Company’s average production costs per unit for the fiscal years ended September 30, 2022, 2021, and 2020, was $65.82, and $40.94, and $32.59, respectively.

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

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

Breedlove

Henshaw

Pittcock & Mary Bullard

ODC San Andres

Texas Properties

Breedlove “B” Clearfork Leases

In September 2021, we, through our wholly-owned subsidiary, Permex U.S., acquired a 100% Working Interest and an 81.75% Net Revenue Interest in the Breedlove “B” Clearfork leases located in Martin County, Texas. We issued 416,666 common shares and 208,333 share purchase warrants as consideration for this acquisition. 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. The re-entry involved targeting the Clearfork formation at a depth of 7,200 feet. Due to the high water concentrating in the fluid entry, management will be installing appropriate flow-lines from this well to the injections wells on the property prior to putting the well back on pump. By doing so management is avoiding unnecessary operating expenses from water disposal in third party disposal facilities.

Pittcock Leases

The Pittcock Leases are situated in Stonewall County. Stonewall County is in Northwest Texas, in the central part of the North Central Plains and consists of the Pittcock North property, the Pittcock South property and the Windy Jones Property. It is bounded on the north by King County, on the east by Haskell County, on the south by Fisher and Jones Counties, and on the west by Kent County. The Pittcock North property covers 320 acres held by production. There is currently one producing well, ten shut-in wells, two saltwater disposal wells, and a water supply well. 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 for a cash consideration of approximately $50,000. 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 U.S., our wholly-owned subsidiary, acquired the West Henshaw Property and the Oxy Yates Property for $170,000 from Permex Petroleum Company LLC (“PPC”). An additional $95,000 was transferred by us to PPC to purchase reclamation bonds in connection with the future operation of the properties.

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, one out of the 67 shut-in wells we currently owns. The re-entry and re-stimulation involved the West Henshaw property targeting the Grayburg formation at a depth of 2,850 feet. The recompletion was successful and came online at an initial rate of 30 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 re-entry and re-stimulation involved the West Henshaw property targeting the Grayburg formation at a depth of 2,850 feet. 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.

The remaining 67 shut-in wells that we plan to re-enter have potential to yield similar results increasing our total daily production solely by re-entering shut-in wells.

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 for $179,095. There are no changes to the royalty interests held by the Company in fiscal 2022.

Recent Developments

On November 2, 2022, we effected a 1-for-60 reverse split of our outstanding Common shares. No fractional shares were issued in connection with the reverse stock split and all such fractional interests were rounded up to the nearest whole number of Common shares. The conversion and/or exercise prices of our issued and outstanding convertible securities, including shares issuable upon exercise of outstanding stock options and warrants, conversion of our outstanding convertible notes and conversions of preferred stock have been adjusted accordingly. All information presented in this Annual Report has been retrospectively restated to give effect to our 1-for-60 reverse split of our outstanding Common shares, and unless otherwise indicated, all such amounts and corresponding conversion price and/or exercise price data set forth in this Annual Report has been adjusted to give effect to such reverse stock split.

In November 2022, we announced that drilling commenced on our Eoff PPC#3 well on our Breedlove Oilfield, that the target depth of 8,100 ft (2468 meters) was achieved and that the casing was run to total depth. The electric wireline logging sequence of the wellbore was also completed, and we believed the results to be positive as all indications from the drilling show to be favorable as multiple zones have been found which allows us to proceed with the next steps of perforation and completion.

Business Strategy

The principal elements of our business strategy include the following:

Industry Operating Environment

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

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

Development

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

Competition

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

Marketing and Customers

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

Our oil production is being sold to Energy Transfer Partners and HollyFrontier at prices tied to Argus. Our natural gas production is being sold to DCP Operating Company LP under Henry Hub gas spot prices.

For the years ended September 30, 2022 and 2021, we had three and one significant purchaser that accounted for approximately 83% and 90%, respectively, of our total oil, and natural gas revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows.

Title to Properties

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

Seasonality

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

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

Principal Agreements Affecting Our Ordinary Business

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

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

Governmental Regulation and Environmental Matters

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

Regulation of Oil and Natural Gas Production

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

Regulation of Transportation of Oil

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

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

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

Regulation of Transportation and Sales of Natural Gas

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

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

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

Environmental Matters

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

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

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

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

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

On November 2, 2021, the Environmental Protection Agency (“EPA”) proposed to revise and add to the NSPS program rules. These rules, if adopted, could have a significant impact on the upstream and midstream oil and gas sectors. The proposed rule would formally reinstate methane emission limitations for existing and modified facilities in the oil and gas sector. Methane is a greenhouse gas. The proposed rules also would regulate, for the first time under the NSPS program, existing oil and gas facilities. Specifically, EPA’s proposed new rule would require states to implement plans that meet or exceed federally established emission reduction guidelines for oil and natural gas facilities. About a year after that proposal, the EPA proposed rules that strengthened and expanded the November 2021 proposal. The November 2022 EPA statement would require more monitoring of small, high-polluting wells, tracking of “super-emitters”, inspection of abandoned wells until their closure, further reduction in flaring, and use of zero-emissions control equipment on hydrocarbon equipment. Comments regarding the November 2022 proposal will be presented to the EPA in January, 2023, after which the EPA may act.

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

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

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

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

The CWA and certain state regulations prohibit the discharge of produced water, sand, drilling fluids, drill cuttings, sediment and certain other substances related to the oil and gas industry into certain coastal and offshore waters without an individual or general National Pollutant Discharge Elimination System discharge permit. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. CWA jurisdiction depends on the definition of WOTUS. On December 7, 2021, EPA and the Corps of Engineers proposed a rule to revise the definition of WOTUS, that would potentially expand CWA jurisdiction to include more features in areas where oil and gas operations are conducted. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. In 2021, the United States Supreme Court held that the CWA requires a discharge permit if the addition of pollutants through groundwater is the functional equivalent of a direct discharge from the point source into navigable waters. Costs may be associated with the treatment of wastewater and/or developing and implementing storm water pollution prevention plans.

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

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

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

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

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

Climate Change

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

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

The SEC in 2022 proposed rules requiring disclosure of how climate-related risks are likely to materially impact publicly-traded enterprises’ finances, strategies and outlook and the impact of climate-related events upon a company’s consolidated financial statements’ line items. Final action on this proposed rule is pending. Companies must also identify “transition” strategies. Compliance with the proposed rule would increase our costs.

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

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

The FERC has issued policy statements articulating how it will quantify natural GHG emissions, departing from past practices.

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

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

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

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

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

Operational Hazards and Insurance

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

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

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

Employees

As of February 10, 2023, we had two full time and no part time employees. We may hire additional personnel as appropriate. We also use the services of independent consultants and contractors to perform various professional services.

Additional Information

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

ITEM 1A. RISK FACTORS

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

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 (CAD$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 was repaid in December 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 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 share price may be adversely affected.

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

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

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

All of our producing properties are geographically concentrated in the Permian and Delaware Basins. As a result, we may be disproportionately exposed to various factors, including, among others: (i) the impact of regional supply and demand factors, (ii) delays or interruptions of production from wells in such areas caused by governmental regulation, (iii) processing 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 share 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, 2022 and 2021, we had three and one significant purchaser that accounted for approximately 83% and 90%, 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 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 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.

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

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

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

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

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

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

Risks Related to our Common Shares

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

Securities markets have a high level of price and volume volatility, and the market price of securities of many companies has experienced substantial volatility in the past. This volatility may affect the ability of holders of our securities to sell their securities at an advantageous price. Market price fluctuations in our securities may be due to our operating results, failing to meet expectations of securities analysts or investors in any period, downward revision in securities analysts’ estimates, adverse changes in general market conditions or economic trends, acquisitions, dispositions, or other material public announcements by us or our competitors, along with a variety of additional factors. These broad market fluctuations may adversely affect the market price of our securities. 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 securities may decline even if our operating results, underlying asset values, or prospects have not changed. Additionally, these factors as well as other related factors may cause decreases in asset values that are deemed to be other than temporary, which may result in impairment losses. There can be no assurance that continuing fluctuations in the price and volume of our securities will not occur. If such increased levels of volatility and market turmoil continue, our operations could be adversely impacted and the trading price of our securities may be materially adversely affected.

Following our reverse stock split, the resulting market price of our Common shares may not attract new investors, including institutional investors, and may not satisfy the investing requirements of those investors. Consequently, the trading liquidity of our common shares may not improve.

Although we believe that a higher market price of our common shares may help generate greater or broader investor interest, there can be no assurance that our reverse stock split completed on November 2, 2022, will result in a share price that will attract new investors, including institutional investors. In addition, there can be no assurance that the market price of our common shares will satisfy the investing requirements of those investors. As a result, the trading liquidity of our common shares may not necessarily improve.

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.

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 February 10, 2023, we have issued and outstanding options to purchase 84,583 common shares with a weighted average exercise price of $13.26 per share and warrants to purchase 1,097,096 common shares with a weighted average exercise price of $12.12 per share. In addition, we have 107,777 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.

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

Our executive officers, directors and principal shareholders and their affiliates beneficially hold, in the aggregate, approximately 37.24% of our outstanding common shares. These shareholders, acting together, are able to significantly influence all matters requiring shareholder approval. For example, these shareholders would be able to significantly influence elections of directors, amendments of our organizational documents, or approval of any merger, sale of assets, or other major corporate transaction. This may prevent or discourage unsolicited acquisition proposals or offers for our common shares that you may feel are in your best interest as one of our shareholders.

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

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

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

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

General Risk Factors

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

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

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

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

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

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

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Executive Office

Our executive office is located at 2911 Turtle Creek Blvd, Suite 925, Dallas, Texas 75219 and consists of 2,765 square feet of leased space. We believe our current office space is sufficient to meet our needs and that additional office space can be obtained if necessary.

Oil and Gas Properties

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

ITEM 3. LEGAL PROCEEDINGS

Although the Company from time to time may be involved with disputes, claims and litigation related to the conduct of its business, there are no material legal proceedings pending to which the Company is a party or to which any of its property is subject, and the Company’s management does not know of any such action being contemplated.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

Market Information

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

We have applied to list our common shares on the NYSE American under the symbol “OILCF”. The approval of our listing of our common shares is a condition of closing this offering. No assurance can be given that our application will be accepted.

Shareholders

As of February 7, 2023, there were 1,932,604 common shares issued and outstanding, held by approximately 49 holders of record, although there are a much larger number of beneficial owners.

Dividend Policy

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

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

Equity Compensation Plans

The following table summarizes information about our equity compensation plans as of September 30, 2022.

Recent Sales of Unregistered Securities

On March 28 and 29, 2022, the Company closed a brokered private placement of an aggregate of 785,477 units at a price of $9.60 per unit for gross proceeds of $7,540,580. Each unit is comprised of one common share and one common share purchase warrant. Each warrant is exercisable into one common share of the Company for a period of five years at an exercise price of $12.60 per share. ThinkEquity LLC acted as sole placement agent for the private placement and it and/or its designees received five year warrants to purchase up to 78,548 common shares of the Company at an exercise price of $12.60 per share. The offering was exempt from registration under Section 4(a)(2) of the Securities Act and Rule 506(b) of Regulation D promulgated by the SEC for purchasers located in the United States and Regulation S promulgated under the Securities Act for purchasers located outside of the United States.

Issuer Purchases of Equity Securities

None.

ITEM 6. [Reserved]

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

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

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

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, 62 shut-in opportunities, 17 salt water disposal wells allowing for waterflood secondary recovery.

Key Activities:

Recent Developments

On November 2, 2022, we effected a 1-for-60 reverse split of our outstanding common shares. No fractional shares were issued in connection with the reverse stock split and all such fractional interests were rounded up to the nearest whole number of common shares. The conversion and/or exercise prices of our issued and outstanding convertible securities, including shares issuable upon exercise of outstanding stock options and warrants, conversion of our outstanding convertible notes and conversions of preferred stock have been adjusted accordingly. All information presented in this Annual Report has been retrospectively restated to give effect to our 1-for-60 reverse split of our outstanding common shares, and unless otherwise indicated, all such amounts and corresponding conversion price and/or exercise price data set forth in this Annual Report has been adjusted to give effect to such reverse stock split.

In November 2022, we announced that drilling commenced on our Eoff PPC#3 well on our Breedlove Oilfield, that the target depth of 8,100 ft (2468 meters) was achieved and that the casing was run to total depth. The electric wireline logging sequence of the wellbore was also completed, and we believed the results to be positive as all indications from the drilling show to be favorable as multiple zones have been found which allows us to proceed with the next steps of perforation and completion.

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.

JOBS Act

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

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

Subject to certain conditions set forth in the JOBS Act, as an “emerging growth company,” we intend to rely on certain of these exemptions, including, without limitation, (i) providing an auditor’s attestation report on our system of internal controls over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act and (ii) complying with any requirement that may be adopted by the Public Company Accounting Oversight Board regarding mandatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit and the financial statements, known as the auditor discussion and analysis. We will remain an “emerging growth company” until the earliest of (i) the last day of the fiscal year in which we have total annual gross revenues of $1.07 billion or more; (ii) the last day of our fiscal year following the fifth anniversary of the date of our initial public offering; (iii) the date on which we have issued more than $1 billion in nonconvertible debt during the previous three years; or (iv) the date on which we are deemed to be a large accelerated filer under the rules of the SEC.

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, 2022 and 2021.

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

Net losses for the years ended September 30, 2022 and 2021 were mainly attributable to operating expenses (2022 - $3,778,693, 2021 - $1,324,361) and other income/expense (2022 - income of $185,618, 2021 - expense of $13,506), partially offset by revenue from oil and gas sales and royalty income (2022 - $878,459, 2021 - $84,625). The increase in total assets in fiscal 2022 is due to net proceeds of $7,044,472 raised from private placement financings. The change in non-current liabilities in fiscal 2022 is mainly due to the changes in estimates on asset retirement obligations.

Results of Operations

Selected Operating Data

Annual Sales and Production Results

The average sales prices of the Company’s oil and gas products sold in the fiscal years ended September 30, 2022, 2021, and 2020 was $89.14, $54.19, and $38.51, respectively.

The Company’s net production quantities by final product sold in the fiscal years ended September 30, 2022, 2021, and 2020, was 12,597.45 Boe, 1,182.70 Boe, and 17,772.14 Boe, respectively.

The Company’s average production costs per unit for the fiscal years ended September 30, 2022, 2021, and 2020, was $65.82, $40.94, and $32.59, respectively.

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

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

Breedlove

Henshaw

Pittcock & Mary Bullard

ODC San Andres

During the year ended September 30, 2022, the Company reported a net loss of $2,714,616 as compared to a net loss of $1,253,242 for the year ended September 30, 2021. The net loss for fiscal 2022 was mainly attributable to operating expenses of $3,778,693 compared to operating expenses of $1,324,361 in fiscal 2021, being partially offset by revenue from oil and gas sales and royalty income of $878,459 in fiscal 2022 compared to $84,625 in fiscal 2021.

The Company reported oil and gas sales revenue of $815,391 in fiscal 2022 compared with revenue of $46,703 in 2021. The increase was mainly due to revenue generated from sales of oil and gas extracted from our Breedlove “B” Clearfork properties that were acquired at the end of fiscal 2021, which accounted for 70% of the Company’s oil and gas sales in the current year. The Company also brought Pittcock North, Mary Bullard, and West Henshaw wells back online during the second quarter of fiscal 2022. Net oil-equivalent production by final product sold in fiscal 2022 average 34.51 barrels per day, compared with 3.24 barrels per day in fiscal 2021.

The production expenses for fiscal 2022 were $829,194 compared with $59,671 in fiscal 2021. The increase was mostly due to the increase in production in 2022 compared to 2021 combined with increased maintenance expenses related to bringing the West Henshaw wells back online in 2022.

The general and administrative expenses excluding share-based payment expenses for fiscal 2022 were $2,250,060, compared with $493,511 in fiscal 2021. This increase in 2022 from 2021 was mainly due to the increase in capital raising and marketing activities during 2022. Specifically, the variance in 2022 from 2021 was mainly attributable to:

Depreciation and depletion expenses (2022 - $105,503, 2021 - $60,479) increased in fiscal 2022 from 2021 primarily due to Breedlove acquisition at the end of fiscal 2021 and increased production.

The Company also incurred share-based compensation expenses of $546,335 in fiscal 2022 compared to $2,870 in fiscal 2021, mostly as a result of the Company granting 3,300,000 stock options to the Company’s directors and consultants in October 2021. Share-based compensation expenses are a non-cash charge that 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.

Liquidity and Capital Resources

As at September 30, 2022, the Company had a cash balance of $3,300,495, an increase of $3,274,689 from the cash balance of $25,806 on September 30, 2021. During the year ended September 30, 2022, cash used in operating activities was $2,024,023. The Company invested $1,685,999 in capital expenditures on its oil and gas assets in fiscal 2022, compared to $265,717 invested in fiscal 2021. Financing activities provided the Company with cash of $6,984,711 mostly as a result of the Company receiving net proceeds of $7,044,472 from private placement financings, being partially offset by the repayment of a loan using $23,600 of cash.

The Company had a working capital of $2,051,127 as at September 30, 2022 compared to a working capital deficiency of $465,129 as at September 30, 2021.

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 September 30, 2022 and the date of our Annual Report on Form 10-K for the year ended September 30, 2022, the Company believes it has sufficient working capital to meet its anticipated operating and capital requirements over the next 12 months. 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.

Critical Accounting Estimates

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

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm

To the Shareholders and Directors of

Permex Petroleum Corporation

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheet of Permex Petroleum Corporation (the “Company”) as of September 30, 2021, and the related consolidated statements of loss and comprehensive loss, equity, and cash flows for the year ended September 30, 2021, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2021, and the results of its operations and its cash flows for the year ended September 30, 2021, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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

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

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

We have served as the Company’s auditor from 2017 to 2022.

July 14, 2022 (February, 9, 2023 as to the effects of the reverse stock split discussed in Note 1)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of

Permex Petroleum Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheet of Permex Petroleum Corporation (the “Company”) as of September 30, 2022, the related consolidated statements of loss and comprehensive loss, equity and cash flows for the year ended September 30, 2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2022, and the results of its operations and its cash flows for the year ended September 30, 2022, in conformity with accounting principles generally accepted in the United States of America.

Explanatory Paragraph – Going Concern

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

Basis for Opinion

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

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

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

/s/ Marcum llp

Marcum llp

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

Houston, Texas
February 10, 2023

PERMEX PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

AS AT SEPTEMBER 30

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

PERMEX PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF LOSS AND COMPREHENSIVE LOSS

YEARS ENDED SEPTEMBER 30

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

PERMEX PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY