Permex Petroleum (OILCF) 10-Q2023 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the Quarterly Period Ended June 30, 2023

OR

For the transition period from to

Commission File Number: 001-41558

Permex Petroleum Corporation

(Exact name of registrant as specified in its charter)

(469) 804-1306

(Registrant’s telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

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

Indicate by checkmark 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 checkmark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☒ No ☐

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

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

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

As of August 21, 2023, there were 2,206,014 common shares of the registrant issued and outstanding.

PERMEX PETROLEUM CORPORATION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2023

TABLE OF CONTENTS

EXPLANATORY NOTE

Unless otherwise indicated or the context otherwise requires, all references in this Quarterly Report on Form 10-Q (this “Report”) to “we,” “us,” “our,” “Permex,” and the “Company” are to Permex Petroleum Corporation., a corporation existing under the laws of the Province of British Columbia, Canada, and our wholly-owned subsidiary.

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

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

“MBoe” One thousand barrels of oil equivalent.

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

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

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

Terms used to describe our interests in wells and acreage:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

“NYMEX.” The New York Mercantile Exchange.

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

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

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

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

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

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

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

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

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

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

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

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

CAUTIONARY NOTICE REGARDING FORWARD LOOKING STATEMENTS

We desire to take advantage of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. This Report contains a number of forward-looking statements that reflect management’s current views and expectations with respect to our business, strategies, products, future results and events, and financial performance. All statements made in this Report other than statements of historical fact, including statements that address operating performance, the economy, events or developments that management expects or anticipates will or may occur in the future, including the adequacy of funds from operations, cash flows and financing, potential strategic transactions, statements regarding future operating results and non-historical information, are forward-looking statements. In particular, the words such as “believe,” “expect,” “intend,” “anticipate,” “estimate,” “may,” “will,” “can,” “plan,” “predict,” “could,” “future,” “continue,” variations of such words, and similar expressions identify forward-looking statements, but are not the exclusive means of identifying such statements and their absence does not mean that the statement is not forward-looking.

When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” in our annual report on Form 10-K for the fiscal year ended September 30, 2022. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about:

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production and sale of natural gas. These risks include, but are not limited to, commodity price volatility, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Risk Factors” in our annual report on Form 10-K for the fiscal year ended September 30, 2022.

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 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 Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Report. Notwithstanding the foregoing, any public statements or disclosures by us following this Report that modify or impact any of the forward-looking statements contained in this Report will be deemed to modify or supersede such statements in this Report.

PART 1 – FINANCIAL INFORMATION

PERMEX PETROLEUM CORPORATION

CONDENSED INTERIM CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

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

PERMEX PETROLEUM CORPORATION

CONDENSED INTERIM CONSOLIDATED STATEMENTS OF LOSS

(UNAUDITED)

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

PERMEX PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)

Three months ended June 30

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

PERMEX PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)

Nine months ended June 30

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

PERMEX PETROLEUM CORPORATION

CONDENSED INTERIM CONSOLIDATED STATEMENTS OF CASH FLOWS

NINE MONTHS ENDED JUNE 30

(UNAUDITED)

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

PERMEX PETROLEUM CORPORATION

NOTES TO CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

THREE AND NINE MONTHS ENDED JUNE 30, 2023

(UNAUDITED)

1. BACKGROUND

Permex Petroleum Corporation (the “Company”) was incorporated on April 24, 2017 under the laws of British Columbia, Canada and maintains its head office at Suite 925, 2911 Turtle Creek Blvd, Dallas, Texas, 75219. Its registered office is located at 10^th floor, 595 Howe Street, Vancouver, British Columbia, Canada, V6C 2T5. The Company is primarily engaged in the acquisition, development and production of oil and gas properties in the United States. The Company’s oil and gas interests are located in Texas and New Mexico, USA. The Company is listed on the Canadian Securities Exchange (the “CSE”) under the symbol “OIL” and on the OTCQB under the symbol “OILCF”.

On October 26, 2022, the Company’s board of directors approved a reverse stock split of the Company’s issued and outstanding common stock at a 1 for 60 ratio, which was effective November 2, 2022. The par value and authorized shares of common stock were not adjusted as a result of the reverse stock split. All issued and outstanding common stock, options, and warrants to purchase common stock and per share amounts contained in the financial statements have been retroactively adjusted to reflect the reverse stock split for all periods presented.

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

The unaudited condensed consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“US GAAP”) and applicable rules and regulations of the United States Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. In the opinion of management, the condensed consolidated financial statements include all adjustments necessary, which are of a normal and recurring nature, for the fair presentation of the Company’s financial position and of the results of operations and cash flows for the periods presented. These interim results are not necessarily indicative of the results to be expected for the fiscal year ending September 30, 2023 or for any other interim period or for any other future fiscal year. These condensed consolidated financial statements should be read in conjunction with the Company’s audited financial statements and footnotes for the fiscal year ended September 30, 2022.

Principles of Consolidation

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

PERMEX PETROLEUM CORPORATION

NOTES TO CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

THREE AND NINE MONTHS ENDED JUNE 30, 2023

(UNAUDITED)

2. Significant Accounting Policies (cont’d…)

Going concern of operations

These consolidated financial statements have been prepared on a going concern basis which assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business. The Company has incurred losses since inception in the amount of $12,133,756 and has not yet achieved profitable operations. The Company has been relying on equity financing and loans from related parties to fund its operation in the past. While the Company has been successful in securing financing to date, there can be no assurances that it will be able to do so in the future. The aforementioned factors raise substantial doubt about the Company’s ability to continue as a going concern within one year after the date that the financial statements are issued.

Management plans to fund operations of the Company with its current working capital and through increasing production from its oil and gas leases. The Company also expects to raise additional funds through equity financings. There are no written agreements in place for such funding or issuance of securities and there can be no assurance that such will be available in the future. Management believes that this plan provides an opportunity for the Company to continue as a going concern.

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

Use of Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities at the date of the financial statements and the reported amount of revenue and expenses during the reporting period. Management evaluates these estimates and judgments on an ongoing basis and bases its estimates on experience, current and expected future conditions, third-party evaluations and various other assumptions that management believes are reasonable under the circumstances. Significant estimates have been used by management in conjunction with the following: (i) the fair value of assets when determining the existence of impairment factors and the amount of impairment, if any; (ii) the costs of site restoration when determining decommissioning liabilities; (iii) the useful lives of assets for the purposes of depletion and depreciation; (iv) petroleum and natural gas reserves; and (v) share-based payments. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, and makes adjustments when facts and circumstances dictate. These estimates are based on information available as of the date of the financial statements; therefore, actual results could differ from those estimates.

New accounting standards

There are not currently any new or pending accounting standards that are expected to have a significant impact on the Company’s consolidated financial statements.

PERMEX PETROLEUM CORPORATION

NOTES TO CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

THREE AND NINE MONTHS ENDED JUNE 30, 2023

(UNAUDITED)

3. REVENUE

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

As of June 30, 2023 and September 30, 2022, receivable from contracts with customers, included in trade and other receivables, were $52,201 and $56,639, respectively.

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

SCHEDULE OF REVENUE DISAGGREGATED BY PRODUCT TYPE AND GEOGRAPHIC AREAS

4. CONCENTRATION OF CREDIT RISK

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

The majority of the Company’s receivable balance is concentrated in trade receivables, with a balance of $94,380 as of June 30, 2023 (September 30, 2022 - $91,928). Two customers represented $57,744 (61%) of the trade receivable balance. The Company routinely assesses the financial strength of its customers. The non-trade receivable balance consists of goods and services tax (“GST”) recoverable of $2,235. GST recoverable is due from the Canadian Government. It is in management’s opinion that the Company is not exposed to significant credit risk. To date, the Company has not recognized any credit losses on its receivables.

PERMEX PETROLEUM CORPORATION

NOTES TO CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

THREE AND NINE MONTHS ENDED JUNE 30, 2023

(UNAUDITED)

5. PROPERTY AND EQUIPMENT

Property and equipment consisted of the following:

SCHEDULE OF PROPERTY AND EQUIPMENT

Depletion and depreciation expense was $120,459 and $161,988 for the nine month periods ended June 30, 2023 and June 30, 2022, respectively. Depletion and depreciation expense for the three month periods ended June 30, 2023 and June 30, 2022 was $37,286 and $73,093, respectively.

6. LEASES

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

SCHEDULE OF RIGHT OF USE OPERATING LEASES

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

SCHEDULE OF LEASE COST

As of June 30, 2023, maturities of the Company’s operating lease liabilities are as follows:

SCHEDULE OF FUTURE LEASE PAYMENTS

PERMEX PETROLEUM CORPORATION

NOTES TO CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

THREE AND NINE MONTHS ENDED JUNE 30, 2023

(UNAUDITED)

7. ASSET RETIREMENT OBLIGATIONS

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

SCHEDULE OF ASSET RETIREMENT OBLIGATIONS

During the year ended September 30, 2022, the Company had revision of estimates totalling $371,212 primarily due to changes in future cost estimates and retirement dates for its oil and gas assets.

Reclamation deposits

As of June 30, 2023, the Company held reclamation deposits of $145,000 (September 30, 2022 - $145,000), which are expected to be released after all reclamation work has been completed with regard to its oil and natural gas interests.

PERMEX PETROLEUM CORPORATION

NOTES TO CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

THREE AND NINE MONTHS ENDED JUNE 30, 2023

(UNAUDITED)

8. DEBT

Convertible debenture – Related party

As of September 30, 2022, the Company had a debenture loan of $73,000 (CAD$100,000) from the CEO of the Company outstanding. The debenture loan was secured by an interest in all of the Company’s right, title, and interest in all of its oil and gas assets, bore interest at a rate of 12% per annum and had a maturity date of December 20, 2022. The debenture was convertible at the holder’s option into units of the Company at $6.57 (CAD$9.00) per unit. Each unit would be comprised of one common share of the Company and one share purchase warrant; each warrant entitled the holder to acquire one additional common share for a period of three years at an exercise price of $8.76 (CAD $12.00).

During the year ended September 30, 2022, the Company repaid $34,709 of the loan (CAD$47,546). In November 2022, the Company repaid the remaining principal loan amount of $38,291 (CAD$52,454).

The Company recorded interest of $nil and $1,182 for the three and nine months ended June 30, 2023. The Company recorded interest of $2,597 and $6,285 for the three and nine months ended June 30, 2022.

Loan payable

In May 2020, the Company opened a Canada Emergency Business Account (“CEBA”) and received a loan of $28,640 (CAD$40,000) from the Canadian Government. The CEBA program was established to provide interest-free loans of up to CAD$60,000 to small businesses to help them cover operating costs during the COVID-19 pandemic. The loan was unsecured and non-interest bearing with a repayment deadline of December 31, 2023. During the year ended September 30, 2022, the Company repaid the loan balance of $23,600 (CAD$30,000) and recognized a gain of $7,800 (CAD$10,000) on the forgiven amount.

9. RELATED PARTY TRANSACTIONS

The convertible debenture loan from the CEO of the Company mentioned in Note 8 was repaid during the nine months ended June 30, 2023.

10. LOSS PER SHARE

The calculation of basic and diluted loss per share for the three and nine month periods ended June 30, 2023 and 2022 was based on the net losses attributable to common shareholders. The following table sets forth the computation of basic and diluted loss per share:

SCHEDULE OF BASIC AND DILUTED LOSS PER SHARE

For the three and nine months ended June 30, 2023, 81,250 stock options and 1,118,942 warrants were excluded from the diluted weighted average number of common shares calculation as their effect would have been anti-dilutive. For the three and nine months ended June 30, 2022, 92,917 stock options and 1,097,096 warrants were excluded from the diluted weighted average number of common shares calculation as their effect would have been anti-dilutive.

PERMEX PETROLEUM CORPORATION

NOTES TO CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

THREE AND NINE MONTHS ENDED JUNE 30, 2023

(UNAUDITED)

11. EQUITY

Common stock

The Company has authorized an unlimited number of common shares with no par value. At June 30, 2023 and September 30, 2022, the Company had 2,206,014 common shares issued and outstanding after giving effect to the 60:1 reverse stock split.

During the nine months ended June 30, 2023, the Company announced a warrant exercise incentive program (the “Program”) whereby the Company amended the exercise prices of 1,015,869 warrants (the “Eligible Warrants”) from $12.60 per share to $2.86 per share if the holders of the Eligible Warrants exercised the Eligible Warrants before June 30, 2023 (the “Program Period”). In addition to the repricing, the Company offered, to each warrant holder who exercised the Eligible Warrants during the Program Period, the issuance of one additional common share purchase warrant for each warrant exercised during the Program Period (each, an “Incentive Warrant”). Each Incentive Warrant entitles the warrant holder to purchase one common share of the Company for a period of 5 years from the date of issuance, at a price of $4.50 per Share.

On June 30, 2023, the Company issued 273,410 common shares at a price of $2.86 per share from the exercise of the Eligible Warrants pursuant to the Program for gross proceeds of $781,953 (net proceeds of $688,092). In connection with the Program, the Company issued 273,410 Incentive Warrants. The Company also incurred $62,556 and issued 21,872 warrants as a finders’ fee to its investment bank. The finder’s warrants are on the same terms as the Incentive Warrants. The Incentive Warrants and finder’s warrants were valued at $449,005 and $35,919, respectively, using the Black-Scholes option pricing model (assuming a risk-free interest rate of 3.68%, an expected life of 5 years, annualized volatility of 128.81% and a dividend rate of 0%). The repricing of the Eligible Warrants is accounted for as a modification under ASC 815-40-35-14 through 18. The effect of the modification is $544,164, measured as the excess of the fair value of the repriced warrants over the fair value of the original warrants immediately before it was modified and the fair value of the incentive warrants issued as an additional inducement to exercise the warrants. The fair values were measured using the Black-Scholes option pricing model (assuming a risk-free interest rate of 4.21%, an expected life of 3.75 years, annualized volatility of 137.62% and a dividend rate of 0%). The Company recognized a deemed dividend of $543,234 for the fair value of the Incentive Warrants and the portion of inducement related to the equity-classified warrants. The effect of the repricing of the liability-classified warrants was $930 and was recorded in the statement of loss. The Company also incurred legal and other expenses of $31,305 in connection with the Program.

During the year ended September 30, 2022, the Company:

Share-based payments

Stock options

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

PERMEX PETROLEUM CORPORATION

NOTES TO CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

THREE AND NINE MONTHS ENDED JUNE 30, 2023

(UNAUDITED)

11. EQUITY (cont’d…)

Share-based payments (cont’d…)

Stock option transactions are summarized as follows:

SCHEDULE OF STOCK OPTION TRANSACTIONS

The aggregate intrinsic value of options outstanding and exercisable as at June 30, 2023 was $nil (September 30, 2022 - $nil).

The options outstanding as of June 30, 2023 have exercise prices in the range of $2.25 to $22.50 and a weighted average remaining contractual life of 6.91 years.

During the nine months ended June 30, 2023 and 2022, the Company recognized share-based payment expense of $318 and $604,861, respectively, for the portion of stock options that vested during the period. The share-based payment expense for the three months ended June 30, 2023 and 2022 was $nil and $185, respectively. The following weighted average assumptions were used for the Black-Scholes valuation of stock options granted:

SCHEDULE OF WEIGHTED AVERAGE ASSUMPTIONS USED IN THE FAIR VALUE

As June 30, 2023, the following stock options were outstanding:

SCHEDULE OF STOCK OPTIONS OUTSTANDING

PERMEX PETROLEUM CORPORATION

NOTES TO CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

THREE AND NINE MONTHS ENDED JUNE 30, 2023

(UNAUDITED)

11. EQUITY (cont’d…)

Warrants

Warrant transactions are summarized as follows:

SCHEDULE OF WARRANTS TRANSACTIONS

As June 30, 2023, the following warrants were outstanding:

SCHEDULE OF WARRANTS OUTSTANDING

22,059 warrants issued with private placement units during fiscal 2022 have an exercise price denominated in CAD. These warrants were initially valued at $202,009 using the Black-Scholes option pricing model (assuming a risk-free interest rate of 0.98%, an expected life of 2 years, annualized volatility of 153.02% and a dividend rate of 0%) and recorded as a warrant liability. The fair value of these warrants were remeasured at each reporting period and a gain on fair value of $178,509 was recorded during the year ended September 30, 2022. During the nine months ended June 30, 2023, a gain on fair value of $23,500 was recorded (2022 - $152,869). During the three months ended June 30, 2023, a gain on fair value of $1,066 was recorded (2022 - $72,838).

The following weighted average assumptions were used for the Black-Scholes valuation of warrants as at June 30, 2023 and September 30, 2022:

SCHEDULE OF VALUATION OF WARRANTS

This Report contains forward-looking statements. These statements relate to future events or our future financial performance. These statements are only predictions. Actual events or results may differ materially. In evaluating these statements, you should specifically consider various factors, including the risks outlined at the beginning of this Report under “Cautionary Notice Regarding Forward-Looking Statements” the risks outlined under the heading “Risk Factors” in our annual report on Form 10-K for the fiscal year ended September 30, 2022 and in our other reports we file with the SEC. These factors may cause our actual results to differ materially from any forward-looking statements. All amounts in this report are in U.S. dollars, unless otherwise noted.

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

Company Overview

The Company was incorporated on April 24, 2017 under the laws of British Columbia, Canada. The Company is an independent energy company engaged in the acquisition, exploration, development and production of oil and gas properties on private, state and federal land in the United States, primarily in the Permian Basin which includes the Midland Basin and Delaware Basin. The Company focuses on acquiring producing assets at a discount to market, increasing production and cash-flow through recompletion and re-entries, secondary recovery and lower risk infill drilling and development. Currently, the Company owns and operates 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 has more than 11,700 net acres of producing oil and gas assets, 62 shut-in opportunities, and 17 salt water disposal wells allowing for waterflood secondary recovery.

Key activities:

Oil And Gas Properties

Breedlove “B” Clearfork Leases - Texas

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. 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 - Texas

The Pittcock Leases are situated in Stonewall County. Stonewall County is in Northwest Texas, in the central part of the North Central Plains and 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 - Texas

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.

West Henshaw Property - New Mexico

The West Henshaw Property is located in Eddy County, New Mexico, 12 miles northeast of Loco Hills in the Delaware Basin. Eddy County is in Southeast New Mexico. It is bounded by Chaves County to the north, Otero County to the east, Loving County, Texas to the south, and Lea County to the west. The West Henshaw Property covers 1,880 acres held by production. There are two producing wells, seven shut-in wells and four saltwater disposal wells. 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.

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.

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 - New Mexico

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.

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. The Company has started development and conversion of its undeveloped acreage located in Martin County, Texas. The PPC Eoff #3 well, operated by Permex Petroleum, is the first of two permitted wells to be drilled by Permex on the 7,780 gross acre Breedlove oilfield. Drilling of the first well commenced on September 14, 2022. Management furthermore expects to commence lateral drilling and completion of the well by September 2023, subject to the Company acquiring the necessary financing.

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. Management currently anticipates spending approximately $10 million in capital expenditures towards developing the Company’s proved undeveloped reserves during the 2023 fiscal year, subject to the Company acquiring the necessary financing.

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 June 30, 2023, 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 Report.

Results of Operations

Sales and Production

The average sales prices of the Company’s oil and gas products sold in the nine months ended June 30, 2023 and 2022, and the fiscal year ended September 30, 2022 was $72.59/Boe, $88.39/Boe, and $89.14/Boe, respectively. The average sales prices of the Company’s oil and gas products sold in the three months ended June 30, 2023 and 2022 was $66.91/Boe and $102.05/Boe, respectively.

The Company’s net production quantities by final product sold in the nine months ended June 30, 2023 and 2022, and the fiscal year ended September 30, 2022 was 10,260.71 Boe, 8,903.60 Boe, and 12,597.45 Boe, respectively. The Company’s net production quantities by final product sold in the three months ended June 30, 2023 and 2022 was 3,258.07 Boe and 3,404.75 Boe, respectively.

The Company’s average production costs per unit for the nine months ended June 30, 2023 and 2022, and the fiscal year ended September 30, 2022, was $74.33/Boe, $37.33/Boe, and $65.82/Boe, respectively. The Company’s average production costs per unit for the three months ended June 30, 2023 and 2022 was $72.29/Boe and $39.79/Boe, 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

Operating Results

Three Months Ended June 30, 2023 and 2022

During the three months ended June 30, 2023, the Company reported a net loss of $909,593 as compared to a net loss of $888,669 for the three months ended June 30, 2022 mostly as a result of decreased revenue during the third quarter of 2023 compared to the same quarter in 2022.

The Company reported oil and gas sales revenue of $156,716 in the third quarter of the current fiscal year compared with revenue of $258,757 in the same quarter during the last fiscal year. The decrease was mainly due to the decrease in oil and gas prices in the current quarter to $66.91/Boe from $102.05/Boe in the comparative quarter. Net oil-equivalent production by final product sold in the current quarter averaged 35.80 barrels per day, compared with 25.87 barrels per day in the same quarter of the previous fiscal year.

The Company’s total operating expenses for the three months ended June 30, 2023 was $1,072,760 compared to $1,247,531 for the same period in 2022. The decrease in total operating expenses in the third quarter of 2023 compared to the third quarter of 2022 was mainly attributable to decreased general and administrative expenses in the current quarter to $788,659 compared to $1,053,070 for the comparative quarter. The most significant decrease was marketing and promotion expenses, which decreased by $380,453 from $469,096 in the third quarter of 2022 to $88,643 in the third quarter of 2023.

Nine Months Ended June 30, 2023 and 2022

During the nine months ended June 30, 2023, the Company reported a net loss of $3,330,107 as compared to a net loss of $1,797,785 for the nine months ended June 30, 2022. The increase in net loss for the first three quarters of the current fiscal year compared to the same period in 2022 was mainly attributable to operating expenses increasing to $3,929,106 in the first nine months of the current fiscal year compared to operating expenses of $2,572,367 in the same period in the previous fiscal year, combined with revenue from oil and gas sales and royalty income of $559,599 in the first nine months of the current fiscal years compared to $625,057 in the same period during our 2022 fiscal year.

The Company reported oil and gas sales revenue of $541,459 in the first three quarters of the current fiscal year compared with revenue of $577,244 in the same period during the last fiscal year. The decrease was mainly due to the decrease in oil and gas prices in the current period to $72.59/Boe from $88.39/Boe in the comparative period, being partially offset by increased production during first nine months of the Company’s current fiscal year. The production from Breedlove “B” Clearfork properties and Henshaw property increased 10% and 88%, respectively, from the comparative period. Net oil-equivalent production by final product sold in the current period averaged 37.59 barrels per day, compared with 32.49 barrels per day in the same period of the previous fiscal year.

The production expenses for the nine months ended June 30, 2023 were $762,668 compared with $332,346 in the nine months ended June 30, 2022. The increase was mostly due to the increase in production in the current fiscal period compared to the same period in the previous fiscal year combined with increased maintenance expenses on the Breedlove and West Henshaw wells.

The general and administrative expenses excluding share-based payment expenses for the nine months ended June 30, 2023 were $3,013,987, compared with $1,462,183 in the nine months ended June 30, 2022. The increase was mainly due to the increase in property development and corporate activities in general during in the current fiscal period. Specifically, the variance in the first nine months of the current fiscal year from the same period in the previous fiscal year was mainly attributable to:

Liquidity and Capital Resources

As at June 30, 2023, the Company had a cash balance of $764,386, a decrease of $2,536,109 from the cash balance of $3,300,495 on September 30, 2022. During the nine months ended June 30, 2023, cash used in operating activities was $1,936,206. The Company invested $1,249,704 in capital expenditures on its oil and gas assets in the first nine months of the current fiscal year, compared to $201,698 invested in the comparative nine months of the previous fiscal year. The Company raised net proceeds of $688,092 from the exercise of warrants and repaid $38,291 of a debenture loan.

The Company had a working capital deficiency of $2,501,571 as at June 30, 2023 compared to a working capital of $2,051,127 as at September 30, 2022.

Management has currently budgeted approximately $10 million in capital expenditures for the 2024 fiscal year, which the Company plans to finance principally from one or more equity financings and/or a line or credit. The amount and timing of capital expenditures will depend on several factors including, but not limited to, the speed with which we are able to drill and complete our wells, our ability to complete an equity financing or to secure a suitable line of credit, commodity prices, supply/demand considerations and attractive rates of return. There are no guarantees that we will be able to acquire the necessary funds to meet our budgeted capital expenditures, and any postponement of our planned development of our proved undeveloped reserves could materially affect our business, financial condition and results of operations.

Although the Company has budgeted investments of additional capital in the continued development of our oil and gas operations, the Company currently does not have any material commitments for capital expenditures. However, as of the date of our Quarterly Report on Form 10-Q for the nine months ended June 30, 2023, the Company does not have sufficient working capital to meet its anticipated operating and capital requirements over the next 12 months and, consequently, the Company is currently evaluating options to support its funding requirements over this time period, including but not limited to, completing a financing transaction. The Company will also 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 accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amount of assets and liabilities at the date of the financial statements and the reported amount of revenue and expenses during the reporting period. Management evaluates these estimates and judgments on an ongoing basis and bases its estimates on experience, current and expected future conditions, third-party evaluations and various other assumptions that management believes are reasonable under the circumstances. Significant estimates have been used by management in conjunction with the following: (i) the fair value of assets when determining the existence of impairment factors and the amount of impairment, if any; (ii) the costs of site restoration when determining decommissioning liabilities; (iii) the useful lives of assets for the purposes of depletion and depreciation; (iv) petroleum and natural gas reserves; and (v) share-based payments. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, and makes adjustments when facts and circumstances dictate. These estimates are based on information available as of the date of the financial statements; therefore, actual results could differ from those estimates.

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.

The Company is not required to provide the information required by this Item as it is a “smaller reporting company,” as defined in Rule 12b-2 of the Exchange Act.

We maintain disclosure controls and procedures (as such terms are defined under Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) that are designed to ensure that the information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b) as of the end of the period covered by this Report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of June 30, 2023.

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

Changes in internal controls

There were no changes in our internal controls over financial reporting during the three months ended June 30, 2023 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Limitations on Effectiveness of Controls and Procedures

In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

PART II – OTHER INFORMATION

We may be involved from time to time in various claims and legal actions arising in the ordinary course of business, including proceedings involving employee claims, contract disputes, product liability and other general liability claims, as well as trademark, copyright, and related claims and legal actions. We are not currently a party to any material legal proceedings and we are not aware of any pending or threatened legal proceeding against us that we believe could have a material adverse effect on our business, operating results, cash flows or financial condition.

There have been no material changes to the factors disclosed in Item 1A. Risk Factors in our annual report on Form 10-K for the fiscal year ended September 30, 2022.

* Filed herewith.

** Furnished herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.