Form 424B3 Permex Petroleum Corp
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Filed Pursuant to Rule 424(b)(3)
Registration No. 333-265883
PROSPECTUS
98,970,113
Common Shares
Permex Petroleum Corporation
This prospectus relates to the resale by certain selling shareholders of Permex Petroleum Corporation, a corporation organized under the laws of British Columbia, Canada (the “Company”), identified in this prospectus of up to 98,970,113 common shares (the “Resale Shares”) of the Company, no par value, including 51,841,488 Resale Shares issuable upon exercise of outstanding warrants. All of the Resale Shares were purchased from the Company in a private placement transaction.
The Resale Shares may be sold by the selling shareholders to or through underwriters or dealers, directly to purchasers or through agents designated from time to time. For additional information regarding the methods of sale you should refer to the section entitled “Plan of Distribution” in this prospectus.
The prices at which the selling shareholders may sell the Resale Shares will be determined by the prevailing market price for the Company’s common shares or in privately negotiated transactions. The Company will not receive any proceeds from the sale of the Resale Shares by the selling shareholders; provided, however, the Company will receive the proceeds from any cash exercise of warrants.
The Company will bear all costs relating to the registration of the Resale Shares, other than any selling shareholder’s legal or accounting costs or commissions.
The Company’s common shares are presently listed on the Canadian Securities Exchange and the Frankfurt Stock Exchange under the symbols “OIL” and “75P”, respectively, and quoted on the OTCQB tier of the OTC Markets Group, Inc. under the symbol “OILCF.” The closing price of the Company’s common shares on August 5, 2022, as reported by the OTCQB was $0.104 per share.
Investing in the Company’s common shares involves a high degree of risk. See the section entitled “Risk Factors” beginning on page 15 of this prospectus and elsewhere in this prospectus for a discussion of information that should be considered in connection with an investment in the Company’s common shares.
The Company may amend or supplement this prospectus from time to time by filing amendments or supplements as required. You should read the entire prospectus and any amendments or supplements carefully before you make your investment decision.
The Company is an “emerging growth company” as defined under the federal securities laws and, as such, may elect to comply with certain reduced public company reporting requirements. See “Prospectus Summary - Implications of Being an Emerging Growth Company.”
Neither the United States Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
Prospectus dated August 12, 2022
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TABLE OF CONTENTS
You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered or made available to you. We have not and the selling shareholders have not authorized anyone to provide you with different information. The selling shareholders are offering to sell, and seeking offers to buy, our common shares only in jurisdictions where offers and sales are permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of our common shares.
For investors outside the United States: Neither we nor the selling shareholders have done anything that would permit this offering or possession or distribution of this prospectus in any jurisdiction, other than the United States, where action for that purpose is required. Persons outside the United States who come into possession of this prospectus must inform themselves about, and observe any restrictions relating to, the offering of our common shares and the distribution of this prospectus outside the United States.
This prospectus is a part of a registration statement on Form S-1 that we filed with the Securities and Exchange Commission. The selling shareholders may from time to time sell the common shares covered by this prospectus and, in certain circumstances, we or the selling shareholders may provide a supplement to this prospectus that will contain certain specific information about the terms of a particular offering by one or more of the selling shareholders or to add information to, or update or change information contained in this prospectus. You should read this prospectus or any supplement to this prospectus before deciding to invest in our common shares. You may obtain this information without charge by following the instructions under “Where You Can Find Additional Information” appearing elsewhere in this prospectus.
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Unless otherwise indicated in this report, natural gas volumes are stated at the legal pressure base of the state or geographic area in which the reserves are located at 60 degrees Fahrenheit. Crude oil and natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.
The following definitions shall apply to the technical terms used in this prospectus.
Terms used to describe quantities of crude oil and natural gas:
“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGLs.
“Boe.” A barrel of oil equivalent and is a standard convention used to express crude oil, NGL and natural gas volumes on a comparable crude oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil or NGL.
“MBbl.” One thousand barrels of crude oil, condensate or NGLs.
“Mcf.” One thousand cubic feet of natural gas.
“NGLs.” Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.
Terms used to describe our interests in wells and acreage:
“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil, NGLs, and/or natural gas.
“Developed acreage.” Acreage consisting of leased acres spaced or assignable to productive wells. Acreage included in spacing units of infill wells is classified as developed acreage at the time production commences from the initial well in the spacing unit. As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.
“Development well.” A well drilled within the proved area of a crude oil, NGL, or natural gas reservoir to the depth of a stratigraphic horizon (rock layer or formation) known to be productive for the purpose of extracting proved crude oil, NGL, or natural gas reserves.
“Differential.” The difference between a benchmark price of crude oil and natural gas, such as the NYMEX crude oil spot price, and the wellhead price received.
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“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.
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“Undeveloped acreage.” Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil, NGLs, and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage includes net acres held by operations until a productive well is established in the spacing unit.
“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“Wellbore.” The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.
“Working interest.” The right granted to the lessee of a property to explore for and to produce and own crude oil, NGLs, natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
“Workover.” Operations on a producing well to restore or increase production.
Terms used to assign a present value to or to classify our reserves:
“Possible reserves.” The additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.
“Pre-tax PV-10% or PV-10.” The estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the SEC.
“Probable reserves.” The additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but which together with proved reserves, are as likely as not to be recovered.
“Proved reserves.” The quantities of crude oil, NGLs and natural gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
“Proved undeveloped reserves” or “PUDs.” Proved Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
“SEC Pricing” means pricing calculated using oil and natural gas price parameters established by current guidelines of the United States Securities and Exchange Commission (the “SEC”) and accounting rules based on the unweighted arithmetic average of oil and natural gas prices as of the first day of each of the 12 months ended on the given date.
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This summary highlights information contained in this prospectus. It does not contain all of the information that you should consider in making your investment decision. Before investing in our common shares, you should read this entire prospectus carefully, including the sections entitled “Risk Factors,” “Business” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes. Except as otherwise required by the context, references to “Permex,” “the Company,” “we,” “us” and “our” are to Permex Petroleum Corporation, a corporation organized under the laws of British Columbia, Canada, individually, or as the context requires, collectively with its subsidiary. Certain operational terms used in this prospectus are defined in the “Glossary of Terms.” All references to “U.S. Dollars,” “USD” or “$” are to the legal currency of the United States, and all references to “CAD$” and “C$” are to the legal currency of Canada. All references to “M$” are in thousands of dollars.
Company Overview
We are an independent energy company engaged in the acquisition, exploration, development and production of oil and gas properties on private, state and federal land in the United States, primarily in the Permian Basin which includes the Midland Basin and Delaware Basin. We focus on acquiring producing assets at a discount to market, increasing production and cash-flow through recompletion and re-entries, secondary recovery and lower risk infill drilling and development. Currently, we own and operate various oil and gas properties located in Texas and New Mexico. In addition, we hold various royalty interests in 73 wells and 5 permitted wells across 3,800 acres within the Permian Basin of West Texas and southeast New Mexico. Moreover, we own and operate more than 78 oil and gas wells, have more than 11,700 net acres of production oil and gas assets, 67 shut-in opportunities, 17 salt water disposal wells eliminating water disposal fees and decreasing OPEX and 2 water supply wells allowing for waterflood secondary recovery.
Oil and Gas Properties
The Company hired MKM Engineering, who prepared for the Company an Appraisal of Certain Oil and Gas Interests owned by Permex Petroleum Corporation located in New Mexico and Texas as of September 30, 2021 (the “2021 Appraisal Report”) as well as an Appraisal of Certain Oil and Gas Interests owned by Permex Petroleum Corporation located in New Mexico and Texas as of September 30, 2020 (the “2020 Appraisal Report” and together with the 2021 Appraisal Report, the “Appraisal Reports”). MKM Engineering is independent with respect to Permex Petroleum Corporation as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. MKM Engineering’s estimates of the Company’s proved and probable reserves in each of the Appraisal Reports were prepared according to generally accepted petroleum engineering and evaluation principles, and each of the Appraisal Reports conform to SEC Pricing. The Appraisal Reports are each filed as an exhibit to the registration statement for which this prospectus is a part of.
The Appraisal Reports were each specifically prepared by Michele Mudrone, an employee of MKM Engineering, a registered Professional Engineer in the State of Texas, and a member of the Society of Petroleum Engineers. Ms. Mudrone graduated from the Colorado School of Mines with a Bachelor of Science degree in Petroleum Engineering in 1976 and has been employed in the petroleum industry and directly involved in reservoir engineering, petrophysical analysis, reservoir simulation and property evaluation since that time Ms. Mudrone certified in each Appraisal Report that she did not receive, nor expects to receive, any direct or indirect interest in the holdings discussed in the report or in the securities of the Company. Because the Company’s current size, the Company does not have any technical person at the Company response for overseeing the preparation of the reserve estimates presented herein (or have any internal control policies pertaining to estimates of oil and gas reserves) and consequently the Company relies exclusively on the Appraisal Reports in the preparation of the reserve estimates present in this prospectus.
Since all of the Company’s reserves are from conventional reservoirs, MKM Engineering assumed for the purposes of its appraisal reports that the technology to be used to develop the Company’s reserves would include horizontally drilled wells, fracturing, and acidizing.
The following tables show a summary of our reserves as of September 30, 2021 and September 30, 2020 which have been derived from the Appraisal Reports and conform to SEC Pricing.
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Composite Proved Reserve Estimates and Economic Forecasts for the year ended September 30, 2021.
| Proved | Proved Developed Producing |
Proved Non-Producing |
Proved Undeveloped |
|||||||||||||
| Net Reserves | ||||||||||||||||
| Oil/Condensate | MBbl | 6,199.4 | 399.3 | 188.1 | 5,612.0 | |||||||||||
| Natural Gas | Mcf | 3,018.3 | 314.4 | 97.5 | 2,606.4 | |||||||||||
| Revenue | ||||||||||||||||
| Oil/Condensate | M$ | 347,051.0 | 21,920.1 | 10,468.6 | 314,662.3 | |||||||||||
| Natural Gas | M$ | 8,906.8 | 949.0 | 286.9 | 7,670.9 | |||||||||||
| Severance and Ad Valorem Taxes | M$ | 26,171.1 | 1,927.3 | 774.5 | 23,469.3 | |||||||||||
| Operating Expenses | M$ | 43,511.4 | 8,048.8 | 3,057.0 | 32,405.6 | |||||||||||
| Investments | M$ | 71,700.0 | 791.9 | 689.6 | 70,218.5 | |||||||||||
| Operating Income (BFIT) | M$ | 214,575.4 | 12,101.2 | 6,234.4 | 196,239.8 | |||||||||||
| Discounted @ 10% | M$ | 100,772.6 | 6,356.0 | 3,644.6 | 90,772.0 | |||||||||||
Composite Proved Reserve Estimates and Economic Forecasts for the year ended September 30, 2020.
| Proved | Proved Developed Producing |
Proved Non-Producing |
Proved Undeveloped |
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| Net Reserves | ||||||||||||||||
| Oil/Condensate | MBbl | 3,706.4 | 254.9 | 294.5 | 3,157.0 | |||||||||||
| Natural Gas | Mcf | 740.3 | 64.9 | 17.6 | 657.8 | |||||||||||
| Revenue | ||||||||||||||||
| Oil/Condensate | M$ | 149,380.6 | 10,201.3 | 12,077.9 | 127,101.4 | |||||||||||
| Natural Gas | M$ | 1,313.0 | 58.7 | 32.6 | 1,221.7 | |||||||||||
| Severance and Ad Valorem Taxes | M$ | 11,404.2 | 903.6 | 863.4 | 9,637.2 | |||||||||||
| Operating Expenses | M$ | 38,863.8 | 5,590.5 | 2,818.4 | 30,454.9 | |||||||||||
| Investments | M$ | 26,262.9 | 630.1 | 807.0 | 24,825.8 | |||||||||||
| Operating Income (BFIT) | M$ | 74,162.6 | 3,135.8 | 7,621.7 | 63,405.1 | |||||||||||
| Discounted @ 10% | M$ | 29,113.0 | 1,806.4 | 4,057.76 | 23,249.0 | |||||||||||
Composite Probable Reserve Estimates and Economic Forecasts for the year ended September 30, 2021
| Probable | Probable Non- Producing |
Probable Undeveloped |
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| Net Reserves | ||||||||||||
| Oil/Condensate | MBbl | 7,466.5 | 119.8 | 7,346.7 | ||||||||
| Natural Gas | Mcf | 10,252.1 | 6.3 | 10,245.8 | ||||||||
| Revenue | ||||||||||||
| Oil/Condensate | M$ | 411,745.8 | 6,686.4 | 405,059.4 | ||||||||
| Natural Gas | M$ | 30,171.8 | 18.4 | 30,153.4 | ||||||||
| Severance and Ad Valorem Taxes | M$ | 23,511.2 | 478.1 | 23,033.1 | ||||||||
| Operating Expenses | M$ | 50,336.3 | 1,061.2 | 49,275.1 | ||||||||
| Investments | M$ | 102,884.9 | - | 102,884.9 | ||||||||
| Operating Income (BFIT) | M$ | 265,185.3 | 5,165.5 | 260,019.8 | ||||||||
| Discounted @ 10% | M$ | 123,329.8 | 1,957.5 | 121,372.3 | ||||||||
Composite Probable Reserve Estimates and Economic Forecasts for the year ended September 30, 2020
| Probable | Probable Non- Producing |
Probable Undeveloped |
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| Net Reserves | ||||||||||||
| Oil/Condensate | MBbl | 439.4 | 121.9 | 317.5 | ||||||||
| Natural Gas | Mcf | 126.3 | 6.3 | 120.0 | ||||||||
| Revenue | ||||||||||||
| Oil/Condensate | M$ | 17,637.2 | 5,024.7 | 12,612.5 | ||||||||
| Natural Gas | M$ | 232.3 | 12.3 | 220.0 | ||||||||
| Severance and Ad Valorem Taxes | M$ | 1,279.6 | 359.4 | 920.2 | ||||||||
| Operating Expenses | M$ | 2,404.2 | 952.6 | 1,451.6 | ||||||||
| Investments | M$ | - | - | - | ||||||||
| Operating Income (BFIT) | M$ | 14,185.7 | 3,725.0 | 10,460.7 | ||||||||
| Discounted @ 10% | M$ | 5,844.7 | 1,489.9 | 4,354.8 | ||||||||
Probable reserves are unproven reserves that geologic and engineering analyses suggest are more likely than not to be recoverable. They are not comparable to proved reserves and estimates of oil, condensate, and gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Such reserve and revenue estimates are based on the information currently available, the interpretation of which is subject to uncertainties inherent in applying judgmental factors.
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Conversion of Undeveloped Acreage
The Company’s process for converting undeveloped acreage to developed acreage is tied to whether there is any drilling being conducted on the acreage in question. During the fiscal year ended September 30, 2021, the Company did not commence drilling on any undeveloped acreage and no undeveloped reserves were converted into proved developed reserves. The Company has also did not make any investments in, or make any progress towards, converting proved undeveloped reserves to proved developed reserves during the year ended September 30, 2021. The Company also has not begun drilling on any undeveloped acreage or make any investments in undeveloped reserves during 2022 as of the date hereof.
An aggregate of 5,612 MBO and 2,606 MMCF, of the Company’s proved undeveloped reserves as of September 30, 2021, 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, 2021.
Proved Undeveloped Reserves Additions
From September 30, 2020 to September 30, 2021, the Company had proved undeveloped reserve additions of 2,779.78 MBoe, mostly as a result of the acquisition of an aggregate of 6,046 net acres of new properties located in Martin County, Texas during the fiscal year ended 2021, being partially offset by the sales of certain acreage at the Company’s Peavy property in Young County, Texas and the Company’s property in Gaines County, Texas to a third party and a reclassification of 120.85 MBoe from proved undeveloped reserves to probable undeveloped reserves at the Company’s West Henshaw property in Eddy County, New Mexico. This reclassification was the result of a determination in 2021 that certain proved undeveloped reserves on the West Henshaw property were not a direct offset to a producing well and consequently should be categorized as undeveloped probable reserves. The specific changes to the Company’s proved undeveloped reserves from September 30, 2020 to September 30, 2021 were as follows:
| Breedlove | Peavy | Gaines County | Henshaw | Royalty Wells | Total | |||||||||||||||||||
| Beginning balance at September 30, 2020 (MBoe)(1) | — | — | — | — | — | 3,266.59 | ||||||||||||||||||
| Production (MBoe)(1) | — | — | — | — | — | — | ||||||||||||||||||
| Revisions or reclassifications of previous estimates (MBoe)(1) | — | — | — | (120.85 | ) | — | (120.85 | ) | ||||||||||||||||
| Improved Recovery (MBoe)(1) | — | — | — | — | — | — | ||||||||||||||||||
| Extensions and Discoveries (MBoe)(1) | — | — | — | — | — | — | ||||||||||||||||||
| Acquisitions/Purchases (MBoe)(1) | 5,584.14 | — | — | — | 0.23 | 5,584.37 | ||||||||||||||||||
| Sales (MBoe)(1) | — | (70.40 | ) | (2,614.00 | ) | — | — | (2,684.40 | ) | |||||||||||||||
| Price Change (MBoe) | — | — | — | — | — | 0.66 | ||||||||||||||||||
| Ending balance as of September 30, 2021 (MBoe)(1) | — | — | — | — | — | 6,046.37 | ||||||||||||||||||
| (1) | Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended September 30, 2021, the average prices of WTI (Cushing) oil and NYMEX Henry Hub natural gas were $57.69 per Bbl and $2.94 per Mcf, respectively, resulting in an oil-to-gas ratio of over 19 to 1. |
Financing of Proved and Probable Undeveloped Reserves
The Company currently estimates that the total cost to develop the Company’s proved undeveloped reserves of 5,612.0 MBbl of oil and 2,606.4 Mcf of natural gas as of September 30, 2021 is $67,940,950.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 7,346.7 MBbl of oil and 10,245.8 Mcf of natural gas as of September 30, 2021 is $102,884,900. 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 did not drill any wells during the last three fiscal years. As at September 30, 2021, the Company had 95 gross wells and 17.29 net productive wells, with 89 wells producing oil and six wells producing natural gas, and the Company’s gross developed acreage totaled 5,177 and net developed acreage totaled 3,942 with the following geographic breakdown:
| Property | Gross Developed Acreage | Net Developed Acreage | Gross Productive Wells | Net Productive Wells | ||||||||||||
Pittcock | 818 | 664.63 | 1 | 0.81 | ||||||||||||
| Henshaw | 1,880 | 1,353.60 | 2 | 1.44 | ||||||||||||
| Oxy Yates | 680 | 489.60 | 2 | 1.44 | ||||||||||||
| Bullard | 241 | 187.98 | 1 | 0.78 | ||||||||||||
| Breedlove | 1,558 | 1,246.4 | 16 | 12.80 | ||||||||||||
| Royalty Interest Properties | - | - | 73 | 0.01 | ||||||||||||
The Company has 6,000 gross undeveloped acres and 4,800 net undeveloped acres. All of the Company’s undeveloped acreage is on the Company’s Breedlove property.
The Company’s leases are held by production in perpetuity. If a field/lease is undeveloped it typically has a 2, 3 or 5 year term of expiry. The Company has over 340 leases covering undeveloped acreage and less than 3% of these leases have a two year expiry date from the date of this prospectus.
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Sales and Production
The average sales prices of the Company’s oil and gas products sold in the fiscal years ended September 30, 2021, 2020 and 2019 was $46.86, $38.51, and $51.79, respectively.
The Company’s net production quantities by final product sold in the fiscal years ended September 30, 2021, 2020, and 2019 was 30,623.69 Boe, 20,112.44 Boe, and 1,112.87 Boe, respectively.
The Company’s average production costs per unit for the fiscal years ended September 30, 2021, 2020, and 2019, was $23.56, $27.93, and $32.59, respectively.
The breakdown of production and prices between oil/condensate and natural gas was as follows:
| Net Production Volumes | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate (Bbl) | 947 | 16,240 | 25,513 | |||||||||
| Natural Gas (Mcf) | 1,410 | 9,196 | 13,121 | |||||||||
| Average Sales Price | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate ($/Bbl) | 58.36 | 41.09 | 49.67 | |||||||||
| Natural Gas ($/Mcf) | 3.40 | 1.44 | 2.04 | |||||||||
The breakdown of the Company’s production quantities by individual product type for each of the Company’s fields that contain 15% or more of the Company’s total proved reserves expressed on an oil-equivalent-barrels basis was as follows:
Breedlove
| Net Production Volumes | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate (Bbl) | - | - | - | |||||||||
| Natural Gas (Mcf) | 419 | - | - | |||||||||
Henshaw
| Net Production Volumes | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate (Bbl) | - | - | 1,519 | |||||||||
| Natural Gas (Mcf) | - | - | - | |||||||||
McMurtry-Loving
| Net Production Volumes | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate (Bbl) | - | - | 2,634 | |||||||||
| Natural Gas (Mcf) | - | - | - | |||||||||
ODC San Andres
| Net Production Volumes | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate (Bbl) | 14,464 | 11,570 | - | |||||||||
| Natural Gas (Mcf) | 4,982 | 2,605 | - | |||||||||
Texas Properties
Breedlove “B” Clearfork Leases
In September 2021, we, through our wholly-owned subsidiary, Permex Petroleum US Corporation, acquired 100% Working Interest and 81.75% Net Revenue Interest in the Breedlove “B” Clearfork leases. The Breedlove “B” Clearfork properties situated in Martin County, Texas are over 12 contiguous sections for a total of 7,870.23 gross and 7,741.67 net acres, of which 98% is held by production in the core of the Permian Basin. It is bounded on the north by Dawson County, on the east by Howard County, on the south by Glasscock and Midland Counties, and on the west by Andrews County. There is a total of 25 vertical wells of which 12 are producers, 4 are saltwater disposal wells and 9 that are shut-in opportunities. In January 2022, we began the pilot re-entry on the Carter Clearfork well #5, which is one of 67 shut-in wells that we currently own. In addition, we have begun the permitting process for two locations on the Breedlove property for drilling and development. Upon approval of the permits by the regulatory body, we expect to compete in the Spraberry and Wolfcamp formations with possible fracking.
Pittcock Leases
The Pittcock Leases are situated in Stonewall County which is in Northwest Texas, in the central part of the North Central Plains and consists of the Pittcock North property, the Pittcock South property and the Windy Jones Property. It is bounded on the north by King County, on the east by Haskell County, on the south by Fisher and Jones Counties, and on the west by Kent County. The Pittcock North property covers 320 acres held by production. There is currently one producing well, ten shut-in wells, two saltwater disposal wells, and a water supply well. We hold a 100% working interest in the Pittcock North Property and an 81.25% net revenue interest. The Pittcock South property covers 498 acres in four tracts. There are currently 19 shut-in wells and two saltwater disposal wells. We hold a 100% working interest in the lease and a 71.90% net revenue interest. The Windy Jones Property consists of 40 acres and includes two injection wells and two suspended oil wells. The sole purpose of the Windy Jones property is to provide waterflood to the offset wells being the Pittcock wells located east boundary of the Windy Jones Property. We hold a 100% working interest in the Windy Jones Property and a 78.9% net revenue interest.
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Mary Bullard Property
We acquired the Mary Bullard Property in August 2017. The Mary Bullard Property is located in Stonewall County, about 5 ½ miles south west of Aspermont, Texas. It is bounded on the north by King County, on the east by Haskell County, on the south by Fisher and Jones Counties, and on the west by Kent County. The asset is situated on the Eastern Shelf of the Midland Basin in the central part of the North Central Plains. The Mary Bullard Property covers 241 acres held by production and is productive in the Clearfork formation at a depth of approximately 3,200 feet. There is currently one producing well, four shut-in wells, and two water injection wells. We hold a 100% working interest in the Mary Bullard Property and a 78.625% net revenue interest.
New Mexico Properties
In December 2017, Permex Petroleum US Corporation, our wholly-owned subsidiary, acquired the West Henshaw Property and the Oxy Yates Property.
West Henshaw Property
The West Henshaw Property is located in Eddy County, New Mexico, 12 miles northeast of Loco Hills in the Delaware Basin. Eddy County is in Southeast New Mexico. It is bounded by Chaves County to the north, Otero County to the east, Loving County, Texas to the south, and Lea County to the west. The West Henshaw Property covers 1,880 acres held by production. There are two producing wells, seven shut-in wells and four saltwater disposal wells. We hold a 100% working interest in the West Henshaw Property and a 72% net revenue interest.
In January 2022, we began the pilot re-entry on the West Henshaw well #15-3. The recompletion was successful and came online at an initial rate of 30 barrels of oil per day (“bopd”) and has stabilized at 15 bopd. Management believes the production rates from this mature, long-life well to continue with less than 10% decline year over year.
In April 2022, we began the re-entry on the West Henshaw well #6-10. The recompletion was successful and came online at an initial rate of 15 bopd and has stabilized at 10 bopd. Management believes the production rates from this mature, long-life well to continue with less than 10% decline year over year.
Oxy Yates Property
The Oxy Yates Property is located in Eddy County, approximately eight miles north of Carlsbad, New Mexico in the Delaware Basin. It is bounded by Chaves County to the north, Otero County to the east, Loving County, Texas to the south, and Lea County to the west. The Oxy Yates Property covers 680 acres held by production. There is one producing well and nine shut-in wells. The Yates formation is located at an average depth of 1,200 feet and overlies the Seven River formation and underlies the Tansill formation. We hold a 100% working interest in the Oxy Yates Property and a 77% net revenue interest.
Royalty Interest Properties
During the year ended September 30, 2021, we acquired royalty interests in 73 producing oil and gas wells located in Texas and New Mexico.
Business Strategy
The principal elements of our business strategy include the following:
| ● | Grow production and reserves in a capital efficient manner using internally generated levered free cash flow. We intend to allocate capital in a disciplined manner to projects that we anticipate will produce predictable and attractive rates of return. We plan to direct capital to our oil-rich and low-risk development opportunities while focusing on driving cost efficiencies across our asset base with the primary objective of internally funding our capital budget and growth plan. We may also use our capital flexibility to pursue value-enhancing, bolt-on acquisitions to opportunistically improve our positions in existing basins. | |
| ● | Maximize ultimate hydrocarbon recovery from our assets by optimizing drilling, completion and production techniques and investigating deeper reservoirs and areas beyond our known productive areas. While we intend to utilize proven techniques and technologies, we will also continuously seek efficiencies in our drilling, completion and production techniques in order to optimize ultimate resource recoveries, rates of return and cash flows. We will explore innovative enhanced oil recovery (“EOR”) techniques to unlock additional value and have allocated capital towards next generation technologies. For example, we have already completed extensive waterflood EOR studies in Pittcock North and Pittcock South. Through these studies, we will seek to expand our development beyond our known productive areas in order to add probable and possible reserves to our inventory at attractive all-in costs. |
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| ● | Pursue operational excellence with a sense of urgency. We plan to deliver low cost, consistent, timely and efficient execution of our drilling campaigns, work programs and operations. We intend to execute our operations in a safe and environmentally responsible manner, focus on reducing our emissions, apply advanced technologies, and continuously seek ways to reduce our operating cash costs on a per barrel basis. | |
| ● | Pursue strategic acquisitions that maintain or reduce our break-even costs. We intend to actively pursue accretive acquisitions, mergers and dispositions that are intended to improve our margins, returns, and break-even costs of our investment portfolio. Financial strategies associated with these efforts will focus on delivering competitive adjusted per share returns. |
Development
We believe that there is significant value to be created by drilling the identified undeveloped opportunities on our properties in conjunction with the stimulation and rework of our shut-in wells. While our near-term plans are focused towards drilling wells on our existing acreage to develop the potential contained therein, our long-term plans also include continuing to evaluate acquisition and leasing opportunities that can earn attractive rates of return on capital employed.
Risk Factor Summary
Our business is subject to a number of risks of which you should be aware before making an investment decision. You should carefully consider all of the information set forth in this prospectus and, in particular, should evaluate the specific factors set forth under “Risk Factors” in deciding whether to invest in our common shares. Among these important risks are the following:
| ● | If we fail to obtain the capital necessary to fund our operations, we will be unable to continue our operations and you will likely lose your entire investment. Even if we can raise additional funding, we may be required to do so on terms that are dilutive to you. | |
| ● | Our indebtedness could adversely affect our ability to raise additional capital to fund operations. | |
| ● | Oil and gas prices are volatile, and declines in prices may adversely affect our financial position, financial results, cash flows, access to capital and ability to grow. | |
| ● | The actual quantities and present value of our proved oil, gas, and NGL reserves may be less than we have estimated. | |
| ● | Our acquisition strategy may subject us to certain risks associated with the inherent uncertainty in evaluating properties. | |
| ● | 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. | |
| ● | Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations. | |
| ● | Our future success depends on our ability to replace reserves. | |
| ● | Our business depends on third-party transportation and processing facilities and other assets that are owned by third parties. | |
| ● | 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. | |
| ● | 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. | |
| ● | We may incur losses as a result of title defects in the properties in which we invest. | |
| ● | 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. | |
| ● | Our operations are concentrated in the Permian and Delaware Basins, making us vulnerable to risks associated with operating in a limited geographic area. | |
| ● | Increased attention to environmental, social and governance matters may impact our business. |
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| ● | The COVID-19 pandemic has had, and may continue to have, a material adverse effect on our financial condition and results of operations. | |
| ● | 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. | |
| ● | Our business is highly regulated and governmental authorities can delay or deny permits and approvals or change legal requirements governing our operations, including well stimulation, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and delay our implementation of, or cause us to change, our business strategy. | |
| ● | Failure to comply with environmental laws and regulations could result in substantial penalties and adversely affect our business. | |
| ● | The market price of our common shares is volatile and may not accurately reflect the long term value of our Company. | |
| ● | 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. |
Corporate History
We were incorporated on April 24, 2017 under the laws of British Columbia, Canada. At June 30, 2022, we have one wholly-owned subsidiary, Permex Petroleum US Corporation, a corporation incorporated under the laws of New Mexico (Permex U.S.). We own and operate oil and gas properties in Texas (Breedlove “B” Property, Pittcock North Property, Pittcock South Property, and Mary Bullard Property), and Permex U.S. owns and operates oil and gas properties in New Mexico (Henshaw Property and the Oxy Yates Property).
Implications of Being an Emerging Growth Company and a Smaller Reporting Company
We are an “emerging growth company,” as defined in Section 2(a) of the Securities Act of 1933, as amended (the “Securities Act”), as modified by the Jumpstart Our Business Startups Act of 2012 (“JOBS Act”). As such, we are eligible to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002, as amended (“Sarbanes-Oxley Act”), and the requirement to present only two years of audited financial statements and only two years of related Management’s Discussion and Analysis of Financial Condition and Results of Operations in the registration statement of which this prospectus forms a part. We are currently utilizing or intend to utilize both of these exemptions. We have not made a decision whether to take advantage of any other exemptions available to emerging growth companies. We do not know if some investors will find our common shares less attractive as a result of our utilization of these or other exemptions. The result may be a less active trading market for our common shares and our share price may be more volatile.
In addition, Section 107 of the JOBS Act also provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, such an “emerging growth company” can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have chosen to take advantage of the extended transition periods available to emerging growth companies under the JOBS Act for complying with new or revised accounting standards until those standards would otherwise apply to private companies provided under the JOBS Act. As a result, our consolidated financial statements may not be comparable to those of companies that comply with public company effective dates for complying with new or revised accounting standards.
We will remain an “emerging growth company” until the earliest of (a) the last day of the first fiscal year in which our annual gross revenues exceed $1.07 billion, (b) the date that we become a “large accelerated filer” as defined in Rule 12b-2 under the Securities Exchange Act of 1934, as amended, (c) the date on which we have issued more than $1.0 billion in nonconvertible debt during the preceding three-year period or (d) the last day of our fiscal year containing the fifth anniversary of the date on which we complete our initial public offering of securities.
We have elected to take advantage of certain of the reduced disclosure obligations in this prospectus and in our filings with the SEC that are incorporated by referenced herein. As a result, the information that we provide to our shareholders may be different than you might receive from other public reporting companies in which you hold equity interests.
We are also a “smaller reporting company” as defined under the Securities Act and Exchange Act. We may continue to be a smaller reporting company so long as either (i) the market value of shares of our common stock held by non-affiliates is less than $250 million or (ii) our annual revenue was less than $100 million during the most recently completed fiscal year and the market value of shares of our common stock held by non-affiliates is less than $700 million. 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 under the requirements of (ii) above, we would not be required to obtain an attestation report on internal control over financial reporting issued by our independent registered public accounting firm.
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THE OFFERING
The following summary is provided solely for convenience and is not intended to be complete. You should read the full text and more specific details contained elsewhere in this prospectus.
| Common shares offered by selling shareholders | 98,970,113 common shares, including 51,841,488 common shares issuable upon exercise of outstanding warrants. | |
| Offering price | Market price or privately negotiated prices. | |
| Common shares outstanding after this offering | 115,956,026. | |
| Use of proceeds | We will not receive any proceeds from the sale of the Resale Shares by the selling shareholders; provided, however, we will receive the proceeds from any cash exercise of warrants. See “Use of Proceeds” | |
| Risk factors | Investing in our common shares involves a high degree of risk. See “Risk Factors” in this prospectus for a discussion of factors you should carefully consider before investing in our common shares. | |
| OTCQB symbol | “OILCF” |
The number of common shares shown above to be outstanding after this offering is based on 115,956,026 common shares outstanding as of August 2, 2022. This number of common shares excludes:
| ● | 5,575,000 common shares issuable upon the exercise of outstanding options, with a weighted average exercise price of $0.24 per share; | |
| ● | 65,825,806 common shares issuable upon the exercise of outstanding warrants, with a weighted average exercise price of $0.21 per share; | |
| ● | 666,667 common shares issuable upon conversion of an outstanding secured convertible debenture in the principal amount of $79,000 (C$100,000); and | |
| ● | 6,020,603 common shares available for future issuance under our 2017 and 2022 Stock Option Plans. |
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Investing in our common shares involves a high degree of risk. You should carefully consider the risks and information below and elsewhere in this prospectus, including our consolidated financial statements and the related notes thereto, before making an investment decision. We describe risks below that we currently believe are the material risks of our business, our industry and our common shares. These are not the only risks we face. We are subject to risks that are currently unknown to us, or that we may currently believe are remote or immaterial. If any of these risks or events occurs, our business, financial condition and operating results could be harmed. In that case, the trading price of our common shares could decline, and you might lose all or part of your investment in our common shares.
Risks Related to Our Financial Position and Need for Capital
If we fail to obtain the capital necessary to fund our operations, we will be unable to continue our operations and you will likely lose your entire investment.
We are in the early stages of our operations and have not generated revenue in excess of our expenses. We will likely operate at a loss until our business becomes established, and we may require additional financing in order to fund future operations and expansion plans. Our ability to secure any required financing to sustain operations will depend in part upon prevailing capital market conditions and the success of our operations. There can be no assurance that we will be successful in our efforts to secure any additional financing or additional financing on terms satisfactory to us. If adequate funds are not available, or are not available on acceptable terms, we may be required to scale back our current business plan or cease operations.
Even if we can raise additional funding, we may be required to do so on terms that are dilutive to you.
The capital markets have been unpredictable in the recent past. In addition, it is generally difficult for early stage companies to raise capital under current market conditions. The amount of capital that a company such as ours is able to raise often depends on variables that are beyond our control. As a result, we may not be able to secure financing on terms attractive to us, or at all. If we are able to consummate a financing arrangement, the amount raised may not be sufficient to meet our future needs and may be dilutive to our current shareholders. If adequate funds are not available on acceptable terms, or at all, our business, including our results of operations, financial condition and our continued viability will be materially adversely affected.
We have a limited operating history.
We have a limited operating history and our business is subject to all of the risks inherent in the establishment of a new business enterprise. Our likelihood of success must be considered in light of the problems, expenses, difficulties, complications and delays frequently encountered in connection with development and expansion of a new business enterprise. If we are unable to achieve profitability, we may be unable to continue our operations.
Our indebtedness could adversely affect our ability to raise additional capital to fund operations.
We currently have one outstanding secured convertible debenture in the original principal amount of $79,000 (C$100,000) (excluding interest accrued thereon) issued to Mehran Ehsan, our Chief Executive Officer, President and director, which is secured by all of our right, title and interest in the Properties (as defined in the Security Agreement between us the Mehran Ehsan dated February 21, 2020) together with all engineering reports and intellectual property related to, or generated by us, in connection with the Properties (collectively, the “Collateral”). The secured debenture remains outstanding as of August 2, 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:
| ● | our ability to obtain additional debt or equity financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes may be limited; | |
| ● | a portion of our cash flows from operations may be dedicated to the payment of principal and interest on the indebtedness and will not be available for other purposes, including operations, capital expenditures and future business opportunities; and | |
| ● | we may be vulnerable during a downturn in general economic conditions or in our business, or may be unable to carry on capital spending that is important to our growth. |
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:
| ● | changes in global supply and demand for oil and natural gas; | |
| ● | the actions of the Organization of Petroleum Exporting Countries; | |
| ● | political conditions, including embargoes, in or affecting other oil-producing activity; | |
| ● | the level of global oil and natural gas exploration and production activity; | |
| ● | the level of global oil and natural gas inventories; | |
| ● | weather conditions; | |
| ● | technological advances affecting energy consumption; and | |
| ● | the price and availability of alternative fuels. |
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Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.
Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for oil and, to a lesser extent, natural gas that we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In addition, we may need to record asset carrying value write-downs if prices fall. A significant decline in the prices of natural gas or oil could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.
The actual quantities and present value of our proved oil, gas, and NGL reserves may be less than we have estimated.
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their value. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Because of the high degree of judgment involved, the accuracy of any reserve estimate is inherently imprecise, and a function of the quality of available data and the engineering and geological interpretation. Our reserves estimates are based on 12-month average prices, except where contractual arrangements exist; therefore, reserves quantities will change when actual prices increase or decrease. In addition, results of drilling, testing, and production may substantially change the reserve estimates for a given reservoir over time. The estimates of our proved reserves and estimated future net revenues also depend on a number of factors and assumptions that may vary considerably from actual results, including:
| ● | historical production from the area compared with production from other areas; | |
| ● | the effects of regulations by governmental agencies, including changes to severance and excise taxes; | |
| ● | future operating costs and capital expenditures; and | |
| ● | workover and remediation costs. |
For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of those reserves and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserves estimates may be subject to upward or downward adjustment, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates.
Additionally, because some of our reserves estimates are calculated using volumetric analysis, those estimates are less reliable than the estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure. In addition, realization or recognition of proved undeveloped reserves will depend on our development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.
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:
| ● | recoverable reserves; | |
| ● | future oil and natural gas prices and their appropriate differentials; | |
| ● | availability and cost of transportation of production to markets; | |
| ● | availability and cost of drilling equipment and of skilled personnel; | |
| ● | development and operating costs including access to water and potential environmental and other liabilities; and | |
| ● | regulatory, permitting and similar matters. |
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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:
| ● | declines in oil or natural gas prices, as occurred in 2020 in connection with the COVID-19 pandemic; | |
| ● | infrastructure limitations; | |
| ● | the high cost, shortages or delays of equipment, materials and services; | |
| ● | unexpected operational events, pipeline ruptures or spills, adverse weather conditions, facility malfunctions or title problems; | |
| ● | compliance with environmental and other governmental requirements; | |
| ● | regulations, restrictions, moratoria and bans on injection wells and water disposal; | |
| ● | unusual or unexpected geological formations; | |
| ● | environmental hazards, such as oil, natural gas or well fluids spills or releases, pipeline or tank ruptures and discharges of toxic gas; | |
| ● | fires, blowouts, craterings and explosions; | |
| ● | uncontrollable flows of oil, natural gas or well fluids; | |
| ● | changes in the cost of decommissioning or plugging wells; | |
| ● | maintenance of quality, purity and thermal quality standards both for commodity sales and purposes of transportation; | |
| ● | members of the public have engaged in physical confrontations or acts of sabotage to impede or prevent transportation of hydrocarbons; and | |
| ● | pipeline capacity curtailments. |
In addition to causing curtailments, delays and cancellations of drilling and producing operations, many of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.
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Our future success depends on our ability to replace reserves.
Because the rate of production from oil and natural gas properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional oil and natural gas reserves. Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as our reserves are produced. Future oil and natural gas production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot assure you that we will be able to find or acquire and develop additional reserves at an acceptable cost. We may acquire significant amounts of unproved property to further our development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We seek to acquire both proved and producing properties as well as undeveloped acreage that we believe will enhance growth potential and increase our earnings over time. However, we cannot assure you that all of these properties will contain economically viable reserves or that we will not abandon our initial investments. Additionally, we cannot assure you that unproved reserves or undeveloped acreage that we acquire will be profitably developed, that new wells drilled on our properties will be productive or that we will recover all or any portion of our investments in our properties and reserves.
Our business depends on third-party transportation and processing facilities and other assets that are owned by third parties.
The marketability of our oil and natural gas depends in part on the availability, proximity, capacity and cost of pipeline and gathering systems, processing facilities, oil trucking and barging fleets and rail transportation assets as well as storage facilities owned by third parties. The lack of available capacity on these systems and facilities, whether as a result of proration, growth in demand outpacing growth in capacity, physical damage, scheduled maintenance or other reasons could result in a substantial increase in costs, declines in realized commodity prices, the shut-in of producing wells or the delay or discontinuance of development plans for our properties. In addition, our wells may be drilled in locations that are serviced to a limited extent, if at all, by gathering and transportation pipelines, which may or may not have sufficient capacity to transport production from all of the wells in the area. As a result, we rely on third-party oil trucking to transport a significant portion of our production to third-party transportation pipelines, rail loading facilities and other market access points. In addition, concerns about the safety and security of oil and gas transportation by pipeline may result in public opposition to pipeline development or continued operation and increased regulation of pipelines by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), and therefore less capacity to transport our products by pipeline. Any significant curtailment in gathering system or pipeline capacity, or the unavailability of sufficient third-party trucking or rail capacity, could adversely affect our business, results of operations and financial condition. Our contracts for downstream transportation service include those that may be adjusted on a month-to-month basis, impacting underlying economics of our production. Our downstream contract transportation counterparties include entities that are far larger than we are and have greater market share in their markets than is the case for us in our markets.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.
Approximately 92% of our estimated net proved reserves volumes were classified as proved undeveloped as of September 30, 2021. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.
Weather conditions, which could become more frequent or severe due to climate change, could adversely affect our ability to conduct drilling, completion and production activities in the areas where we operate.
Our exploration and development activities and equipment can be adversely affected by severe weather such as well freeze-offs, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. Our planning for normal climatic variation, insurance programs, and emergency recovery plans may inadequately mitigate the effects of such weather conditions, and not all such effects can be predicted, eliminated, or insured against. In addition, demand for oil and gas are, to a degree, dependent on weather and climate, which impact the price we receive for the commodities we produce. These constraints could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.
We may incur losses as a result of title defects in the properties in which we invest.
The existence of a material title deficiency can render a lease worthless. In the course of acquiring the rights to develop natural gas, we typically execute a lease agreement with payment to the lessor subject to title verification. In many cases, we incur the expense of retaining lawyers to verify the rightful owners of the gas interests prior to payment of such lease bonus to the lessor. There is no certainty, however, that a lessor has valid title to their lease’s gas interests. In those cases, such leases are generally voided and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. Prior to the drilling of a natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Accordingly, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss. Additionally, hydrocarbons or other fluids in one reservoir may migrate to another stratum or reservoir, resulting in disputes regarding ownership, the entitlement to produce, and responsibility for consequences of such migration of the fluids.
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We conduct business in a highly competitive industry.
The oil and natural gas industry is highly competitive. The key areas in respect of which we face competition include: acquisition of assets offered for sale by other companies; access to capital (debt and equity) for financing and operational purposes; purchasing, leasing, hiring, chartering or other procuring of equipment that may be scarce; and employment of qualified and experienced skilled management and oil and natural gas professionals. Competition in our markets is intense and depends, among other things, on the number of competitors in the market, their financial resources, their degree of geological, geophysical, engineering and management expertise and capabilities, their pricing policies, their ability to develop properties on time and on budget, their ability to select, acquire and develop reserves and their ability to foster and maintain relationships with the relevant authorities. Our competitors also include those entities with greater technical, physical and financial resources. In some markets, our products compete with other sources of energy, or other fuels (e.g., hydroelectricity) that may from time to time become more abundant or experience decreased prices. Finally, companies and certain private equity firms not previously investing in oil and natural gas may choose to acquire reserves to establish a firm supply or simply as an investment. Any such companies will also increase market competition which may directly affect us. If we are unsuccessful in competing against other companies, our business, results of operations, financial condition or prospects could be materially adversely affected.
Decommissioning costs are unknown and may be substantial. Unplanned costs could divert resources from other projects.
We may become responsible for costs associated with plugging, abandoning and reclaiming wells, pipelines and other facilities that we use for production of oil and natural gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We accrue a liability for decommissioning costs associated with our wells, but have not established any cash reserve account for these potential costs in respect of any of our properties. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.
Fuel conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices, and the increased competitiveness of alternative energy sources could reduce demand for oil and natural gas. Additionally, the increased competitiveness of alternative energy sources (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells and biofuels) could reduce demand for oil and natural gas and, therefore, our revenues.
Additionally, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Furthermore, certain other stakeholders have pressured commercial and investment banks to stop funding oil and gas projects. With the continued volatility in oil and natural gas prices, and the possibility that interest rates will rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially shale producers. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results. Some states attorneys general have accused large legacy E&P companies of purposefully obscuring consequences of combusting hydrocarbon.
The impact of the changing demand for oil and natural gas services and products, together with a change in investor sentiment, may have a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, if we are unable to achieve the desired level of capital efficiency or free cash flow within the timeframe expected by the market, our stock price may be adversely affected.
Major utilities, sometimes at the instigation of states or investors, have announced plans to radically reduce emissions, or goals to achieve “net-zero” carbon emissions by deadlines as early as 2035.
Diminution of available markets (for instance by bans on the consumption of natural gas as a fuel for power plants) or prohibitions on use of natural gas in new construction as early as 2027 also may affect our markets, profitability and cash flow.
Our operations are concentrated in the Permian and Delaware Basins, making us vulnerable to risks associated with operating in a limited geographic area.
All of our producing properties are geographically concentrated in the Permian and Delaware Basins. As a result, we may be disproportionately exposed to various factors, including, among others: (i) the impact of regional supply and demand factors, (ii) delays or interruptions of production from wells in such areas caused by governmental regulation, (iii) processing or transportation capacity constraints, (iv) market limitations, (v) availability of equipment and personnel, (vi) water shortages or other drought related conditions or (vii) interruption of the processing or transportation natural gas. This concentration in a limited geographic area also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife and unexpected events that may occur in the regions such as natural disasters, seismic events, industrial accidents or labor difficulties. Any one of these factors has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expirations. Any of the risks described above could have a material adverse effect on our business, financial condition, results of operations and cash flow.
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Increased attention to environmental, social and governance (“ESG”) matters may impact our business.
Increasing attention to climate change, increasing societal expectations on companies to address climate change, increasing investor and societal expectations regarding voluntary ESG disclosures, and potential increasing consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our access to capital markets. Increasing attention to climate change, for example, may result in demand shifts for natural gas and oil products and additional governmental investigations and private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital, or negative tax or other cost consequences.
Under some analyses, the world already produces more fossil fuel from existing sources than can be consumed over remaining resources service lives, if incremental global warming is to be kept under 1.5 degrees Celsius. Financing may be increasingly challenging, as pension funds (e.g., for major municipalities such as Boston, MA) and financial institutions divest fossil fuel investments.
The COVID-19 pandemic has had, and may continue to have, a material adverse effect on our financial condition and results of operations.
We face risks related to public health crises, including the COVID-19 pandemic. The effects of the COVID-19 pandemic, including travel bans, prohibitions on group events and gatherings, shutdowns of certain businesses, curfews, shelter-in-place orders and recommendations to practice social distancing in addition to other actions taken by both businesses and governments, resulted in a significant and swift reduction in international and U.S. economic activity. The collapse in the demand for oil caused by this unprecedented global health and economic crisis contributed to the significant decrease in crude oil prices in 2020 in general and resulted in shut down of our wellbores which had and could in the future continue to have a material adverse impact on our financial condition and results of operations.
Since the beginning of 2021, the distribution of COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded. However, we continue to monitor the effects of the pandemic on our operations. As a result of the ongoing COVID-19 pandemic, our operations, and those of our operating partners, have and may continue to experience delays or disruptions and temporary suspensions of operations and increased volatility. In addition, our results of operations and financial condition have been and may continue to be adversely affected by the ongoing COVID-19 pandemic.
The extent to which our operating and financial results are affected by COVID-19 will depend on various factors and consequences beyond our control, such as the emergence of more contagious and harmful variants of the COVID-19 virus, the duration and scope of the pandemic, additional actions by businesses and governments in response to the pandemic, and the speed and effectiveness of responses to combat the virus. COVID-19, and the volatile regional and global economic conditions stemming from the pandemic, could also aggravate the other risk factors that we identify herein. While the effects of the COVID-19 pandemic have lessened recently in the United States, we cannot predict the duration or future effects of the pandemic, or more contagious and harmful variants of the COVID-19 virus, and such effects may materially adversely affect our results of operations and financial condition in a manner that is not currently known to us or that we do not currently consider to present significant risks to our operations.
| -20- |
The loss of any member of our management team, upon whose knowledge, relationships with industry participants, leadership and technical expertise we rely could diminish our ability to conduct our operations and harm our ability to execute our business plan.
Our success depends heavily upon the continued contributions of those members of our management team whose knowledge, relationships with industry participants, leadership and technical expertise would be difficult to replace. In particular, our ability to successfully acquire additional properties, to increase our reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements depends on developing and maintaining close working relationships with industry participants. In addition, our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment is dependent on our management team’s knowledge and expertise in the industry. To continue to develop our business, we rely on our management team’s knowledge and expertise in the industry. The members of our management team may terminate their employment with our Company at any time. If we were to lose members of our management team, we may not be able to replace the knowledge or relationships that they possess and our ability to execute our business plan could be materially harmed.
We are substantially dependent on a limited number of customers
For the years ended September 30, 2021 and 2020, we had one and one significant purchaser, respectively, that accounted for approximately 49% and 45%, respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. Additionally, there are no assurances that we will be able to expand our customer base. If we are unable to attract and maintain an adequate customer base to generate revenues, we will have to suspend or cease operations.
Our business could be negatively affected by security threats, including cybersecurity threats and other disruptions.
As an oil and gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability.
The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for operators related to developing and operating our properties.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly water and sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, our operators rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells. If our operators are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. Shortages of drilling rigs, equipment, raw materials, supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our operators’ exploration and development operations, which in turn could have a material adverse effect on our financial condition, results of operations and free cash flow.
If we are unable to acquire adequate supplies of water for our future drilling and operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired.
We will be using a substantial amount of water in future drilling programs and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as (i) hydraulic fracturing, including, but not limited to, the use of fresh water in such operations, or (ii) disposal of waste, including, but not limited to, the disposal of produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas. Opponents of hydraulic fracturing contend that either the drilling process or the sub-surface injection of fluids, such as water and drilling fluids, as part of accessing hydrocarbons, or disposing of used injection fluids, creates or magnifies seismic disturbances, and should such contentions be given credence with regard to our Company, our operations could experience more regulation, higher costs or greater delays in accessing hydrocarbon resources, or claims of parties asserting damage arising from seismic activity. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, and all of which could have an adverse effect on our business, financial condition, results of operations and cash flows. While we intend to conduct our operations with the level of care necessary to avoid such claims, if the structural integrity of non-producing subsurface strata are impaired by hydraulic fracturing, we could face claims for damages (e.g., claims that we are producing from other geologic strata to which we do not have production rights).
| -21- |
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.
| -22- |
Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.
From time to time, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for natural gas and oil properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although these provisions were largely unchanged in the most recent federal tax legislation, certain of these changes were considered for inclusion in the proposed “Build Back Better Act” and Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. Moreover, other more general features of any additional tax reform legislation, including changes to cost recovery rules, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted in future legislation and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.
Our business involves the selling and shipping by rail of crude oil, which involves risks of derailment, accidents and liabilities associated with cleanup and damages, as well as potential regulatory changes that may adversely impact our business, financial condition or results of operations.
A portion of our crude oil production is transported to market centers by rail. Derailments in North America of trains transporting crude oil have caused various regulatory agencies and industry organizations, as well as federal, state and municipal governments, to focus attention on transportation by rail of flammable liquids. Any changes to existing laws and regulations, or promulgation of new laws and regulations, including any voluntary measures by the rail industry, that result in new requirements for the design, construction or operation of tank cars used to transport crude oil could increase our costs of doing business and limit our ability to transport and sell our crude oil at favorable prices at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, any derailment of crude oil involving crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities.
Federal and state legislative and regulatory initiatives could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Any federal or state legislative or regulatory changes with respect to hydraulic fracturing could cause us to incur substantial compliance costs or result in operational delays, and the consequences of any failure to comply could have a material adverse effect on our financial condition and results of operations.
In addition, in response to concerns relating to recent seismic events near underground disposal wells used for the disposal by injection of flowback and produced water or certain other oilfield fluids resulting from oil and natural gas activities (so-called “induced seismicity”), regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. States may, from time to time, develop and implement plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. These developments could result in additional regulation and restrictions on the use of injection wells by our operators to dispose of flowback and produced water and certain other oilfield fluids. Increased regulation and attention given to induced seismicity also could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing injection wells for waste disposal. Until such pending or threatened legislation or regulations are finalized and implemented, it is not possible to estimate their impact on our business.
Any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.
The adoption of climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas we produce.
Shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change and requiring agencies to review environmental actions taken by the Trump administration, as well as a memorandum to departments and agencies to refrain from proposing or issuing rules until a departmental or agency head appointed or designated by the Biden administration has reviewed and approved the rule. In November 2021, the Biden Administration released ‘The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-carbon dioxide greenhouse gas (“GHG”) emissions, such as methane and nitrous oxide. These executive orders and policy priorities may result in the development of additional regulations or changes to existing regulations, certain of which could negatively impact our financial position, results of operations and cash flows. In addition, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will take to achieve its GHG emissions targets. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. In addition, several states and geographic regions in the United States have also adopted legislation and regulations regarding climate change-related matters, and additional legislation or regulation by these states and regions, U.S. federal agencies, including the Environmental Protection Agency (“EPA”), and/or international agreements to which the United States may become a party could result in increased compliance costs for us and our customers. Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, administrative, civil or criminal fines or penalties or injunctions limiting our operations in affected areas. Moreover, multiple environmental laws provide for citizen suits which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. We consider the responsibility and costs of environmental protection and safety and health compliance fundamental, manageable parts of our business. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.
Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure and/or well construction requirements on hydraulic fracturing operations. We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and potential bans. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.
Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and potentially reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. See “Business—Governmental Regulation and Environmental Matters” and “—Climate Change” for a further discussion of the laws and regulations related to GHGs and of climate change.
We may be involved in legal proceedings that could result in substantial liabilities.
Similar to many oil and natural gas companies, we may be involved in various legal and other proceedings from time to time, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have a material adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, resolution of one or more such proceedings could result in liability, loss of contractual or other rights, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.
| -23- |
Legislation or regulatory initiatives intended to address seismic activity could restrict our operators’ drilling and production activities, which could have a material adverse effect on our business.
State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. For example, in 2015, the United States Geological Study identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction.
In addition, a number of lawsuits have been filed alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, in October 2014, the Texas Railroad Commission published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Texas Railroad Commission has used this authority to deny permits for waste disposal wells. In some instances, regulators may also order that disposal wells be shut in.
The adoption and implementation of any new laws or regulations that restrict our operators’ ability to use hydraulic fracturing or dispose of produced water gathered from drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring them to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.
Continuing political and social discussion of the issue of climate change has resulted in legislative, regulatory and other initiatives to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers at both the U.S. federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases through inventories, limitations and/or taxes on GHG emissions. The EPA has issued regulations for the control of methane emissions, which also include leak detection and repair requirements, for the oil and gas industry and are likely to create additional regulations regarding such matters. In November 15, 2021, the EPA proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. EPA hopes to finalize the proposed regulations by the end of 2022. Once finalized, the regulations are likely to be subject to legal challenge, and will also need to be incorporated into the states’ implementation plans, which will need to be approved by the EPA in individual rulemakings that could also be subject to legal challenge. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to our operations. Future additional federal GHG regulations of the oil and gas industry remain a significant possibility. Some states have imposed limitations designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state initiatives to date have generally focused on the development of renewable energy standards and/or cap-and-trade and/or carbon tax programs. Renewable energy standards (also referred to as renewable portfolio standards) require electric utilities to provide a specified minimum percentage of electricity from eligible renewable resources, with potential increases to the required percentage over time. The development of a federal renewable energy standard, or the development of additional or more stringent renewable energy standards at the state level, or continuing implementation of increasingly disadvantageous (from our industry’s perspective) renewable energy requirements embedded in existing legislation could reduce the demand for oil and gas, thereby adversely impacting our earnings, cash flows and financial position. A cap-and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. A federal cap and trade program or expanded use of cap and trade programs at the state level could impose direct costs on us through the purchase of allowances and could impose indirect costs by incentivizing consumers to shift away from fossil fuels. In addition, federal or state carbon taxes could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels.
In addition, opponents of fossil fuels claiming concern about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in an increasing number of financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this would make it more difficult and expensive to secure funding for exploration and production activities. Members of the investment community have also begun to screen companies such as ours for sustainability performance, including practices related to GHGs and climate change, before investing in our common shares. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable in order to improve our sustainability performance and to meet the specific requirements to perform services for certain customers.
These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations, which could require us to incur costs to reduce emissions of GHGs associated with our operations. Limitations on GHG emissions could also adversely affect demand for oil and gas, which could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity.
Some of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions we or other operators may take when drilling, completing, or operating wells that we or they own.
Some of our properties are in reservoirs that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations by us or other operators could cause depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells by us or other operators could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.
Risks Related to this Offering and our Common Shares
The market price of our common shares is volatile and may not accurately reflect the long term value of our Company.
Securities markets have a high level of price and volume volatility, and the market price of securities of many companies has experienced substantial volatility in the past. This volatility may affect the ability of holders of our common shares to sell their securities at an advantageous price. Market price fluctuations in our common shares may be due to our operating results, failing to meet expectations of securities analysts or investors in any period, downward revision in securities analysts’ estimates, adverse changes in general market conditions or economic trends, acquisitions, dispositions, or other material public announcements by us or our competitors, along with a variety of additional factors. These broad market fluctuations may adversely affect the market price of our common shares. Financial markets have historically, at times, experienced significant price and volume fluctuations that have particularly affected the market prices of equity securities of companies and that have often been unrelated to the operating performance, underlying asset values, or prospects of such companies.
Accordingly, the market price of our common shares may decline even if our operating results, underlying asset values, or prospects have not changed. Additionally, these factors as well as other related factors may cause decreases in asset values that are deemed to be other than temporary, which may result in impairment losses. There can be no assurance that continuing fluctuations in the price and volume of our common shares will not occur. If such increased levels of volatility and market turmoil continue, our operations could be adversely impacted and the trading price of our common shares may be materially adversely affected.
There is no assurance that an investment in our common shares will earn any positive return.
There is no assurance that an investment in our common shares will earn any positive return. An investment in our common shares involves a high degree of risk and should be undertaken only by investors whose financial resources are sufficient to enable them to assume such risks and who have no need for immediate liquidity in their investment. An investment in our common shares is appropriate only for investors who have the capacity to absorb a loss of some or all of their investment.
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We have never paid cash dividends and have no plans to pay cash dividends in the future.
Holders of our common shares are entitled to receive such dividends as may be declared by our board of directors. To date, we have paid no cash dividends on our capital stock and we do not expect to pay cash dividends in the foreseeable future. We intend to retain future earnings, if any, to provide funds for operations of our business. Therefore, any return investors in our capital stock may have will be in the form of appreciation, if any, in the market value of their common shares.
There is a limited market for our common shares.
Our common shares are listed for trading on the Canadian Securities Exchange and the Frankfurt Stock Exchange and are quoted over-the-counter in the United States on the OTCQB of the OTC Markets Group, Inc. The over-the-counter markets provide less liquidity than U.S. national securities exchanges, such as the New York Stock Exchange or Nasdaq. Accordingly, a market for our common shares may become highly illiquid and holders of our common shares may be unable to sell or otherwise dispose of their common shares at desirable prices or at all.
Outstanding and future issuances of debt securities, which would rank senior to our common shares upon bankruptcy or liquidation, may adversely affect the level of return holders of common shares may be able to receive. In the future, we may increase our capital resources by offering additional debt securities. Upon bankruptcy or liquidation, holders of our debt securities and lenders would receive distributions of our available assets prior to any distributions being made to holders our common shares. As our decision to issue debt securities or borrow money from lenders will depend in part on market conditions, we cannot predict or estimate the amount, timing, or nature of any such future offerings or borrowings. Holders of our common shares must bear the risk that current and future securities including the issuance of debt securities may adversely affect the level of return, if any, that the holders of our common shares may receive.
We may need to raise additional funds to support our business operations or to finance future acquisitions, including through the issuance of equity or debt securities, which could have a material adverse effect on our ability to grow our business, and may dilute your ownership in us.
If we do not generate sufficient cash from operations or do not otherwise have sufficient cash and cash equivalents to support our business operations or to finance future acquisitions, we may need raise addition capital through the issuance of debt or equity securities. We do not have any arrangements for any credit facility, or any other sources of capital. We may not be able to raise cash in future financing on terms acceptable to us, or at all.
Financings, if available, may be on terms that are dilutive to our shareholders, and the prices at which new investors would be willing to purchase our securities may be lower than the current price of our common shares. The holders of new securities may also receive rights, preferences or privileges that are senior to those of existing holders of our common shares. If new sources of financing are required but are insufficient or unavailable, we would be required to modify our plans to the extent of available funding, which could harm our ability to grow our business.
We have issued options, warrants and a convertible debenture and may continue to issue additional securities in the future. The exercise and/or conversion of these securities and the sale of the common shares issuable thereunder may dilute your percentage ownership interest and may also result in downward pressure on the price of our common shares.
As of August 2, 2022, we have issued and outstanding options to purchase 5,575,000 common shares with a weighted average exercise price of $0.24 per share, warrants to purchase 65,825,806 common shares with a weighted average exercise price of $0.21 per share, and a debenture in the original principal amount of $79,000 (C$100,000) (excluding interest thereon) convertible into 666,667 common shares and warrants to purchase an additional 666,667 common shares. In addition, we have 6,020,603 common shares available for future issuance under our 2017 and 2022 Stock Option Plans. Because the market for our common shares may be thinly traded, the sales and/or the perception that those sales may occur, could adversely affect the market price of our common shares. Furthermore, the mere existence of a significant number of common shares issuable upon exercise and/or conversion of our outstanding securities may be perceived by the market as having a potential dilutive effect, which could lead to a decrease in the price of our common shares.
We are a British Columbia company and it may be difficult for you to enforce judgments against us or certain of our directors or officers.
As a corporation organized under the provincial laws of British Columbia, Canada, it may be difficult to bring actions under U.S. federal securities law against us. Some of our directors and officers reside principally in Canada or outside of the United States. Because a portion of our assets and the assets of these persons are located outside of the United States, it may not be possible for investors to effect service of process within the United States upon us or those persons. Furthermore, it may not be possible for investors to enforce against us, or those persons not in the United States, judgments obtained in U.S. courts based upon the civil liability provisions of the U.S. federal securities laws or other laws of the United States. There is doubt as to the enforceability, in original actions in Canadian courts, of liabilities based upon U.S. federal securities laws and as to the enforceability in Canadian courts of judgments of U.S. courts obtained in actions based upon the civil liability provisions of the U.S. federal securities laws. Therefore, it may not be possible to enforce those actions against us or certain of our directors and officers.
General Risk Factors
We are an “emerging growth company” and 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 common shares less attractive to investors.
We are an “emerging growth company,” as defined in the JOBS Act and we intend to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “emerging growth companies” including not being required to comply with the auditor attestation requirements of Section 404(b) of the Sarbanes-Oxley Act of 2002, as amended, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. In addition, Section 107 of the JOBS Act also provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act, for complying with new or revised accounting standards. In other words, an “emerging growth company” can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We 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 common shares attractive because we may rely on these exemptions. If some investors find our common shares less attractive as a result, there may be a less active trading market for our common shares and our stock price may be more volatile.
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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
The information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenue and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Risk Factors.” These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.
Forward-looking statements may include statements about:
| ● | our business strategy; | |
| ● | our reserves; | |
| ● | our financial strategy, liquidity and capital requirements; | |
| ● | our realized or expected natural gas prices; | |
| ● | our timing and amount of future production of natural gas; | |
| ● | our future drilling plans and cost estimates; | |
| ● | our competition and government regulations; | |
| ● | our ability to make acquisitions; | |
| ● | the impact of the COVID-19 pandemic and its effect on our business and financial condition; | |
| ● | general economic conditions; | |
| ● | our future operating results; and | |
| ● | our future plans, objectives, expectations and intentions. |
We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production and sale of natural gas. These risks include, but are not limited to, commodity price volatility, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under “Risk Factors.”
Reserve engineering is a method of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of previous estimates. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas and oil that are ultimately recovered.
Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.
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MARKET FOR OUR COMMON STOCK AND RELATED STOCKHOLDER MATTERS
Market Information
Our common shares currently trades on the OTCQB Marketplace in the United States under the symbol “OILCF” on the Canadian Securities Exchange in Canada under the symbol “OIL” and under the Frankfort Stock Exchange under the symbol “75P”,
Shareholders
As of August 2, 2022, there were 115,956,026 common shares issued and outstanding, held by approximately 66 holders of record, although there are a much larger number of beneficial owners.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table summarizes information about our equity compensation plans as of September 30, 2021.
| Plan Category | Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) | Weighted average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | |||||||||
| Equity compensation plans approved by securityholders | 2,175,000 | (1) | C$0.3239 | 4,343,036 | ||||||||
| Equity compensation plans not approved by securityholders | - | - | - | |||||||||
| Total | 2,175,000 | C$0.3239 | 4,343,036 | |||||||||
| (1) | Represents the number of Common Shares available for issuance upon exercise of outstanding Options as at September 30, 2021. | |
| (2) | C$0.41 converted into USD |
Our Board of Directors has discretion as to whether we will pay dividends in the future, subject to restrictions under the Business Corporations Act (British Columbia) (the “BCBCA”) and our charter documents. Under the BCBCA, we may not declare or pay dividends if our Company is insolvent or where the payment of the dividend would render our Company insolvent. See “Description of Share Capital.” We do not currently pay dividends. Accordingly, we may, but do not anticipate, declaring or paying any dividends for the foreseeable future.
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The following table sets forth our cash and cash equivalents and our capitalization as of March 31, 2022:
You should read this table in conjunction with the sections titled and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes included elsewhere in this prospectus.
As of March 31, 2022 (Unaudited) $ | ||||
| Cash and cash equivalents | 6,727,758 | |||
| Total Debt | 114,290 | |||
| Shareholders’ equity (deficit): | 12,709,919 | |||
| Share capital | 14,399,373 | |||
| Deficit | (6,286,478 | ) | ||
| Reserves | 4,585,413 | |||
| Share subscription proceeds | 30,456 | |||
| Accumulated other comprehensive loss | (18,845 | ) | ||
| Total shareholders’ equity | 12,709,919 | |||
| Total capitalization | 12,824,209 | |||
The number of common shares is based on 115,956,026 common shares issued and outstanding as of March 31, 2022, and excludes the following as of such date:
| ● | 5,575,000 common shares issuable upon the exercise of outstanding options, with a weighted average exercise price of $0.24 per share; | |
| ● | 65,825,806 common shares issuable upon the exercise of outstanding warrants, with a weighted average exercise price of $0.21 per share; and | |
| ● | 666,667 common shares issuable upon conversion of an outstanding secured convertible debenture in the amount of $79,000 (C$100,000) including interest accrued thereon; and | |
| ● | 6,020,603 common shares available for future issuance under our 2017 and 2022 Stock Option Plans. |
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MANAGEMENT’S
DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion and analysis of our financial condition and results of operations together with the Company’s consolidated financial statements and the related notes thereto and other financial information included elsewhere in this prospectus. Some of the information contained in this discussion and analysis or set forth elsewhere in this prospectus, including information with respect to our plans and strategy for our business, includes forward-looking statements that involve risks and uncertainties. You should review the “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” sections of this prospectus for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.
Overview
The Company was incorporated on April 24, 2017 under the laws of British Columbia, Canada. The Company is an independent energy company engaged in the acquisition, exploration, development and production of oil and gas properties on private, state and federal land in the United States, primarily in the Permian Basin which includes the Midland Basin and Delaware Basin. The Company focuses on acquiring producing assets at a discount to market, increasing production and cash-flow through recompletion and re-entries, secondary recovery and lower risk infill drilling and development. Currently, the Company owns and operates various oil and gas properties located in Texas and New Mexico. In addition, the Company holds various royalty interests in 73 wells and 5 permitted wells across 3,800 acres within the Permian Basin of West Texas and southeast New Mexico. Moreover, the Company owns and operates more than 78 oil and gas wells, has more than 11,700 net acres of production oil and gas assets, 67 shut-in opportunities, 17 salt water disposal wells eliminating water disposal fees and decreasing OPEX and 2 water supply wells allowing for waterflood secondary recovery.
Key Activities:
| ● | In December 2020, the Company entered into an agreement to sell its interests in ODC San Andres Unit and W.J. “A” Taylor leases for $1,215,769. |
| ● | On February 4, 2021, the Company announced the purchase of various royalty interests in 10 producing horizontal oil and natural gas wells and one permitted well located in Upton County, Texas. |
| ● | On February 24, 2021, the Company announced the purchase of royalty interests in 15 producing horizontal oil and natural gas wells located in Atascosa and La Salle Counties, Texas. |
| ● | On March 16, 2021, the Company announced the expansion of its royalty acquisitions program by purchasing royalty interests in 5 producing horizontal oil and natural gas wells plus four permitted wells located in Lea County, New Mexico. |
| ● | On April 20, 2021, the Company announced an acquisition of additional royalty interests in 11 producing horizontal oil and gas wells located in Midland, Texas. |
| ● | On June 23, 2021, the Company announced an acquisition of additional royalty interests in 29 producing oil and gas wells located in Permian Basin of west Texas. |
| ● | On September 30, 2021, the Company, through its wholly-owned subsidiary, Permex Petroleum US Corporation, acquired a 100% Working Interest and an 81.75% Net Revenue Interest in the Breedlove “B” Clearfork leases located in Martin County, Texas. The Company issued 25,000,000 common shares of the Company and 12,500,000 share purchase warrants as consideration for this acquisition. The share purchase warrants have an exercise price $0.16 per share and are exercisable until October 1, 2031. |
| ● | On October 12, 2021, the Company announced the appointment of John Perry (“J.P.”) Bryan, Jr. and John James (“Jay”) Lendrum, III to its Board of Directors. |
| ● | On November 4, 2021, the Company completed a non-brokered private placement of 2,647,037 units at a price of $0.21 (C$0.27) per unit for gross proceeds of $564,613 (C$714,700). Each unit is comprised of one common share and one half of share purchase warrant; each whole warrant entitles the holder to acquire one additional common share for a period of 24 months at an exercise price of $0.19 (C$0.54). |
| ● | On March 28 and 29, 2022, the Company closed a brokered private placement of an aggregate of 47,128,625 units at a price of $0.16 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 for a period of five years at an exercise price of $0.21 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 4,712,863 common shares of at an exercise price of $0.21 per share. |
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Impact of Covid-19
In March 2020 the World Health Organization declared coronavirus COVID-19 a global pandemic. This contagious disease outbreak, which has continued to spread, and any related adverse public health developments, has adversely affected workforces, economies, and financial markets globally, potentially leading to an economic downturn. Specifically, the effects of the COVID-19 pandemic, including travel bans, prohibitions on group events and gatherings, shutdowns of certain businesses, curfews, shelter-in-place orders and recommendations to practice social distancing in addition to other actions taken by both businesses and governments, resulted in a significant and swift reduction in international and U.S. economic activity. The collapse in the demand for oil caused by this unprecedented global health and economic crisis contributed to the significant decrease in crude oil prices in 2020 in general and resulted in shut down of the Company’s wellbores which had and could in the future continue to have a material adverse impact on the Company’s financial condition and results of operations. As a result of the ongoing COVID-19 pandemic, the Company’s operations, and those of its operating partners, have and may continue to experience delays or disruptions and temporary suspensions of operations and increased volatility. In addition, the Company’s results of operations and financial condition have been and may continue to be adversely affected by the ongoing COVID-19 pandemic; however, it is not possible for the Company to predict the duration or magnitude of the adverse results of the outbreak and its effects on the Company’s business or ability to raise funds at this time. The Company is closely monitoring developments and adapting its business plans accordingly.
Oil and Gas Properties
The Company hired MKM Engineering, who prepared for the Company the Appraisal Reports. Each of the Appraisal Reports used standard engineering practices generally accepted by the petroleum industry and conform to SEC Pricing. The Appraisal Reports are each filed as an exhibit to the registration statement for which this prospectus is a part of. MKM Engineering is independent with respect to Permex Petroleum Corporation as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. MKM Engineering’s estimates of the Company’s proved and probable reserves in each of the Appraisal Reports were prepared according to generally accepted petroleum engineering and evaluation principles, and each of the Appraisal Reports conform to SEC Pricing. The Appraisal Reports are each filed as an exhibit to the registration statement for which this prospectus is a part of.
The Appraisal Reports were each specifically prepared by Michele Mudrone, an employee of MKM Engineering, a registered Professional Engineer in the State of Texas, and a member of the Society of Petroleum Engineers. Ms. Mudrone graduated from the Colorado School of Mines with a Bachelor of Science degree in Petroleum Engineering in 1976 and has been employed in the petroleum industry and directly involved in reservoir engineering, petrophysical analysis, reservoir simulation and property evaluation since that time Ms. Mudrone certified in each Appraisal Report that she did not receive, nor expects to receive, any direct or indirect interest in the holdings discussed in the report or in the securities of the Company. Because the Company’s current size, the Company does not have any technical person at the Company response for overseeing the preparation of the reserve estimates presented herein (or have any internal control policies pertaining to estimates of oil and gas reserves) and consequently the Company relies exclusively on the Appraisal Reports in the preparation of the reserve estimates present in this prospectus.
Since all of the Company’s reserves are from conventional reservoirs, MKM Engineering assumed for the purposes of its appraisal reports that the technology to be used to develop the Company’s reserves would include horizontally drilled wells, fracturing, and acidizing.
The following tables show a summary of our reserves as of September 30, 2021 and September 30, 2020 which have been derived from the Appraisal Reports and conform to SEC Pricing.
Composite Proved Reserve Estimates and Economic Forecasts for the year ended September 30, 2021
| Proved | Proved Developed Producing |
Proved Non-Producing |
Proved Undeveloped |
|||||||||||||||||
| Net Reserves | ||||||||||||||||||||
| Oil/Condensate | MBbl | 6,199.4 | 399.3 | 188.1 | 5,612.0 | |||||||||||||||
| Natural Gas | Mcf | 3,018.3 | 314.4 | 97.5 | 2,606.4 | |||||||||||||||
| Revenue | ||||||||||||||||||||
| Oil/Condensate | M$ | 347,051.0 | 21,920.1 | 10,468.6 | 314,662.3 | |||||||||||||||
| Natural Gas | M$ | 8,906.8 | 949.0 | 286.9 | 7,670.9 | |||||||||||||||
| Severance and Ad Valorem Taxes | M$ | 26,171.1 | 1,927.3 | 774.5 | 23,469.3 | |||||||||||||||
| Operating Expenses | M$ | 43,511.4 | 8,048.8 | 3,057.0 | 32,405.6 | |||||||||||||||
| Investments | M$ | 71,700.0 | 791.9 | 689.6 | 70,218.5 | |||||||||||||||
| Operating Income (BFIT) | M$ | 214,575.4 | 12,101.2 | 6,234.4 | 196,239.8 | |||||||||||||||
| Discounted @ 10% | M$ | 100,772.6 | 6,356.0 | 3,644.6 | 90,772.0 | |||||||||||||||
Composite Proved Reserve Estimates and Economic Forecasts for the year ended September 30, 2020
| Proved | Proved Developed Producing |
Proved Non-Producing |
Proved Undeveloped |
|||||||||||||||||
| Net Reserves | ||||||||||||||||||||
| Oil/Condensate | MBbl | 3,706.4 | 254.9 | 294.5 | 3,157.0 | |||||||||||||||
| Natural Gas | Mcf | 740.3 | 64.9 | 17.6 | 657.8 | |||||||||||||||
| Revenue | ||||||||||||||||||||
| Oil/Condensate | M$ | 149,380.6 | 10,201.3 | 12,077.9 | 127,101.4 | |||||||||||||||
| Natural Gas | M$ | 1,313.0 | 58.7 | 32.6 | 1,221.7 | |||||||||||||||
| Severance and Ad Valorem Taxes | M$ | 11,404.2 | 903.6 | 863.4 | 9,637.2 | |||||||||||||||
| Operating Expenses | M$ | 38,863.8 | 5,590.5 | 2,818.4 | 30,454.9 | |||||||||||||||
| Investments | M$ | 26,262.9 | 630.1 | 807.0 | 24,825.8 | |||||||||||||||
| Operating Income (BFIT) | M$ | 74,162.6 | 3,135.8 | 7,621.7 | 63,405.1 | |||||||||||||||
| Discounted @ 10% | M$ | 29,113.0 | 1,806.4 | 4,057.6 | 23,249.0 | |||||||||||||||
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Composite Probable Reserve Estimates and Economic Forecasts for the year ended September 30, 2021
| Probable | Probable Non- Producing |
Probable Undeveloped |
||||||||||||||
| Net Reserves | ||||||||||||||||
| Oil/Condensate | MBbl | 7,466.5 | 119.8 | 7,346.7 | ||||||||||||
| Natural Gas | Mcf | 10,252.1 | 6.3 | 10,245.8 | ||||||||||||
| Revenue | ||||||||||||||||
| Oil/Condensate | M$ | 411,745.8 | 6,686.4 | 405,059.4 | ||||||||||||
| Natural Gas | M$ | 30,171.8 | 18.4 | 30,153.4 | ||||||||||||
| Severance and Ad Valorem Taxes | M$ | 23,511.2 | 478.1 | 23,033.1 | ||||||||||||
| Operating Expenses | M$ | 50,336.3 | 1,061.2 | 49,275.1 | ||||||||||||
| Investments | M$ | 102,884.9 | - | 102,884.9 | ||||||||||||
| Operating Income (BFIT) | M$ | 265,185.3 | 5,165.5 | 260,019.8 | ||||||||||||
| Discounted @ 10% | M$ | 123,329.8 | 1,957.5 | 121,372.3 | ||||||||||||
Composite Probable Reserve Estimates and Economic Forecasts for the year ended September 30, 2020
| Probable | Probable Non- Producing |
Probable Undeveloped |
||||||||||||||
| Net Reserves | ||||||||||||||||
| Oil/Condensate | MBbl | 439.4 | 121.9 | 317.5 | ||||||||||||
| Natural Gas | Mcf | 126.3 | 6.3 | 120.0 | ||||||||||||
| Revenue | ||||||||||||||||
| Oil/Condensate | M$ | 17,637.2 | 5,024.7 | 12,612.5 | ||||||||||||
| Natural Gas | M$ | 232.3 | 12.3 | 220.0 | ||||||||||||
| Severance and Ad Valorem Taxes | M$ | 1,279.6 | 359.4 | 920.2 | ||||||||||||
| Operating Expenses | M$ | 2,404.2 | 952.6 | 1,451.6 | ||||||||||||
| Investments | M$ | - | - | - | ||||||||||||
| Operating Income (BFIT) | M$ | 14,185.7 | 3,725.0 | 10,460.7 | ||||||||||||
| Discounted @ 10% | M$ | 5,844.7 | 1,489.9 | 4,354.8 | ||||||||||||
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, 2021, the Company did not commence drilling on any undeveloped acreage and no undeveloped reserves were converted into proved developed reserves. The Company has also did not make any investments in, or make any progress towards, converting proved undeveloped reserves to proved developed reserves during the year ended September 30, 2021. The Company also has not begun drilling on any undeveloped acreage or make any investments in undeveloped reserves during 2022 as of the date hereof.
An aggregate of 5,612 MBO and 2,606 MMCF, of the Company’s proved undeveloped reserves as of September 30, 2021, 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, 2021.
Proved Undeveloped Reserves Additions
From September 30, 2020 to September 30, 2021, the Company had proved undeveloped reserve additions of 2,779.78 MBoe, mostly as a result of the acquisition of an aggregate of 6,046 net acres of new properties located in Martin County, Texas during the fiscal year ended 2021, being partially offset by the sales of certain acreage at the Company’s Peavy property in Young County, Texas and the Company’s property in Gaines County, Texas to a third party and a reclassification of 120.85 MBoe from proved undeveloped reserves to probable undeveloped reserves at the Company’s West Henshaw property in Eddy County, New Mexico. This reclassification was the result of a determination in 2021 that certain proved undeveloped reserves on the West Henshaw property were not a direct offset to a producing well and consequently should be categorized as undeveloped probable reserves. The specific changes to the Company’s proved undeveloped reserves from September 30, 2020 to September 30, 2021 were as follows:
| Breedlove | Peavy | Gaines County | Henshaw | Royalty Wells | Total | |||||||||||||||||||
| Beginning balance at September 30, 2020 (MBoe)(1) | — | — | — | — | — | 3,266.59 | ||||||||||||||||||
| Production (MBoe)(1) | — | — | — | — | — | — | ||||||||||||||||||
| Revisions or reclassifications of previous estimates (MBoe)(1) | — | — | — | (120.85 | ) | — | (120.85 | ) | ||||||||||||||||
| Improved Recovery (MBoe)(1) | — | — | — | — | — | — | ||||||||||||||||||
| Extensions and Discoveries (MBoe)(1) | — | — | — | — | — | — | ||||||||||||||||||
| Acquisitions/Purchases (MBoe)(1) | 5,584.14 | — | — | — | 0.23 | 5,584.37 | ||||||||||||||||||
| Sales (MBoe)(1) | — | (70.40 | ) | (2,614.00 | ) | — | — | (2,684.40 | ) | |||||||||||||||
| Price Change (MBoe) | — | — | — | — | — | 0.66 | ||||||||||||||||||
| Ending balance as of September 30, 2021 (MBoe)(1) | — | — | — | — | — | 6,046.37 | ||||||||||||||||||
| (1) | Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended September 30, 2021, the average prices of WTI (Cushing) oil and NYMEX Henry Hub natural gas were $57.69 per Bbl and $2.94 per Mcf, respectively, resulting in an oil-to-gas ratio of over 19 to 1. |
| -31- |
Financing of Proved and Probable Undeveloped Reserves
The Company currently estimates that the total cost to develop the Company’s proved undeveloped reserves of 5,612.0 MBbl of oil and 2,606.4 Mcf of natural gas as of September 30, 2021 is $67,940,950.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 7,346.7 MBbl of oil and 10,245.8 Mcf of natural gas as of September 30, 2021 is $102,884,900. 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 did not drill any wells during the last three fiscal years. As at September 30, 2021, the Company had 95 gross wells and 17.29 net productive wells, with 89 wells producing oil and six wells producing natural gas, and the Company’s gross developed acreage totaled 5,177 and net developed acreage totaled 3,942 with the following geographic breakdown:
| Property | Gross Developed Acreage | Net Developed Acreage | Gross Productive Wells | Net Productive Wells | ||||||||||||
Pittcock | 818 | 664.63 | 1 | 0.81 | ||||||||||||
| Henshaw | 1,880 | 1,353.60 | 2 | 1.44 | ||||||||||||
| Oxy Yates | 680 | 489.60 | 2 | 1.44 | ||||||||||||
| Bullard | 241 | 187.98 | 1 | 0.78 | ||||||||||||
| Breedlove | 1,558 | 1,246.4 | 16 | 12.80 | ||||||||||||
| Royalty Interest Properties | - | - | 73 | 0.01 | ||||||||||||
The Company has 6,000 gross undeveloped acres and 4,800 net undeveloped acres. All of the Company’s undeveloped acreage is on the Company’s Breedlove property.
The Company’s leases are held by production in perpetuity. If a field/lease is undeveloped it typically has a 2, 3 or 5 year term of expiry. The Company has over 340 leases covering undeveloped acreage and less than 3% of these leases have a term that expires within two years of the date of this prospectus.
Sales and Production
The average sales prices of the Company’s oil and gas products sold in the fiscal years ended September 30, 2021, 2020 and 2019 was $46.86, $38.51, and $51.79, respectively.
The Company’s net production quantities by final product sold in the fiscal years ended September 30, 2021, 2020, and 2019 was 30,623.69 Boe, 20,112.44 Boe, and 1,112.87 Boe, respectively.
The Company’s average production costs per unit for the fiscal years ended September 30, 2021, 2020, and 2019, was $23.56, $27.93, and $32.59, respectively.
The breakdown of production and prices between oil/condensate and natural gas was as follows:
| Net Production Volumes | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate (Bbl) | 947 | 16,240 | 25,513 | |||||||||
| Natural Gas (Mcf) | 1,410 | 9,196 | 13,121 | |||||||||
| Average Sales Price | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate ($/Bbl) | 58.36 | 41.09 | 49.67 | |||||||||
| Natural Gas ($/Mcf) | 3.40 | 1.44 | 2.04 | |||||||||
The breakdown of the Company’s production quantities by individual product type for each of the Company’s fields that contain 15% or more of the Company’s total proved reserves expressed on an oil-equivalent-barrels basis was as follows:
Breedlove
| Net Production Volumes | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate (Bbl) | - | - | - | |||||||||
| Natural Gas (Mcf) | 419 | - | - | |||||||||
Henshaw
| Net Production Volumes | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate (Bbl) | - | - | 1,519 | |||||||||
| Natural Gas (Mcf) | - | - | - | |||||||||
McMurtry-Loving
| Net Production Volumes | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate (Bbl) | - | - | 2,634 | |||||||||
| Natural Gas (Mcf) | - | - | - | |||||||||
ODC San Andres
| Net Production Volumes | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate (Bbl) | 14,464 | 11,570 | - | |||||||||
| Natural Gas (Mcf) | 4,982 | 2,605 | - | |||||||||
| -32- |
Breedlove “B” Clearfork Leases – Texas
The Breedlove “B” Clearfork properties situated in Martin County, Texas are over 12 contiguous sections for a total of 7,870.23 Gross and 7,741.67 Net acres, of which 98% is held by production in the core of the Permian Basin. There is a total of 25 vertical wells of which 12 are producers, 4 are saltwater disposal wells and 9 that are shut-in opportunities.
Permex holds a 100% working interest and an 81.75% net revenue interest in the Breedlove “B” Clearfork Property.
Pittcock Leases – Texas
The Pittcock Leases are situated in Stonewall County. Stonewall County is in Northwest Texas, in the central part of the North Central Plains and consist of the Pittcock North property, the Pittcock South property and the Windy Jones Property.
The Pittcock North property covers 320 acres held by production. There is currently one producing well, ten shut-in wells, two saltwater disposal wells, and a water supply well. Permex holds a 100% working interest in the Pittcock North Property, and an 81.25% net revenue interest.
The Pittcock South property covers 498 acres in four tracts. There are currently 19 shut-in wells and two saltwater disposal wells. Permex holds a 100% working interest in the lease, and a 71.90% net revenue interest.
The Windy Jones Property consists of forty acres and includes two injection wells and two suspended oil wells. The sole purpose of the Windy Jones property is to provide waterflood to the offset wells being the Pittcock wells located east boundary of the Windy Jones property. Permex holds a 100% working interest in the Windy Jones Property, and a 78.9% net revenue interest.
Mary Bullard Property - Texas
The Mary Bullard Property is located in Stonewall County, about 5 ½ miles south west of Aspermont, Texas. The asset is situated on the Eastern Shelf of the Midland Basin in the central part of the North Central Plains. The Mary Bullard Property covers 241 acres held by production and is productive in the Clearfork formation at a depth of approximately 3,200 feet. There is currently one producing well, four shut-in wells, and two water injection wells. Permex holds a 100% working interest in the Mary Bullard Property, and a 78.625% net revenue interest.
| -33- |
West Henshaw Property and Oxy Yates Property – New Mexico
The West Henshaw Property is located in Eddy County, New Mexico, 12 miles northeast of Loco Hills in the Delaware Basin. Eddy County is in Southeast New Mexico. It is bounded by Chaves County to the north, Otero County to the east, Loving County, Texas to the south, and Lea County to the west. The West Henshaw Property covers 1,880 acres held by production. There are two producing wells, seven shut-in wells and four saltwater disposal wells. Permex holds a 100% working interest in the West Henshaw Property, and a 72% net revenue interest.
The Oxy Yates Property is located in Eddy County, approximately eight miles north of Carlsbad, New Mexico in the Delaware Basin. The Oxy Yates Property covers 680 acres held by production. There is one producing well and nine shut-in wells. The Yates formation is located at an average depth of 1,200 feet and overlies the Seven River formation and underlies the Tansill formation. Permex holds a 100% working interest in the Oxy Yates Property, and a 77% net revenue interest.
Selected Annual Information
The following table sets out selected financial information for the Company which has been derived from the Company’s audited financial statements for the fiscal years ended September 30, 2021 and 2020.
| Fiscal 2021 ($) | Fiscal 2020 ($) | |||||||
| Revenues | 84,625 | 682,786 | ||||||
| Net income (loss) | (1,245,057 | ) | (1,249,202 | ) | ||||
| Net income (loss) per share - basic and diluted | (0.03 | ) | (0.03 | ) | ||||
| Total assets | 8,148,472 | 7,000,821 | ||||||
| Total non-current liabilities | 1,685,851 | 929,740 | ||||||
| Dividends | - | - | ||||||
Factors That Affect the Comparability of the Annual Financial Data Disclosed Above
Net losses for the years ended September 30, 2021 and 2020 were mainly attributable to general administrative expenses (2021 - $590,239, 2020 - $498,752) and loss on disposal of properties (2021 - $613,457, 2020 - $879,070). The decrease in revenue in fiscal 2021 and 2020 is due to the significant decline in oil prices in the middle of the fiscal 2020. Oil production on all the Company’s properties were shut down for four months in fiscal 2020 due to a steep decline in the price of oil during 2020. The Company sold its interest in ODC San Andres Unit and W.J. “A” Taylor leases in October 2020. All other oil and gas wells remained shut down until May 2021. The increase in total assets in fiscal 2021 is due to the acquisition of Breedlove “B” Clearfork properties. The decrease in non-current liabilities in fiscal 2020 is due to the reclassification of decommissioning obligations related to ODC San Andres Unit and W.J. “A” Taylor leases to current liabilities held for sale. The increase in non-current liabilities in fiscal 2021 is due to the recognition of decommissioning obligations related to the newly acquired Breedlove “B” Clearfork properties.
Discussion of Operations
Years Ended September 30, 2021 and 2020
During the year ended September 30, 2021, the Company reported a net loss of $1,245,057 as compared to a net loss of $1,249,202 for the year ended September 30, 2020. Revenue from oil and gas production decreased 93% to $46,703 (2020 - $682,786). The decrease is the result of the sale of ODC San Andres Unit and W.J. “A” Taylor leases in October 2020 and the complete shutdown of production from July 2020 in response to the steep decline in oil price. During the last six months of 2021, the Company has been working to bring the Pittcock North, Mary Bullard and Henshaw properties back online. The Pittcock North and Mary Bullard wells generated the first oil sales in June 2021. The royalty income of $37,922 (2020 - $Nil) is generated from royalty interests acquired in early 2021. The Company has acquired royalty interests in 73 wells located in Texas and New Mexico for a total investment of $179,095.
The general administrative expenses excluding depletion and depreciation and share-based payment expenses for the ended September 30, 2021 were $526,890 (2020 - $457,286) and were generally consistent with fiscal 2020. Some of the significant expense items are summarized as follows:
| ● | Accounting and audit of $78,090 (2020 - $66,710) include audit, accounting, and tax compliance related costs. |
| ● | Filing and transfer agent of $54,822 (2020 - $27,922) have increased from the prior period mainly due to the DTC application fee of $17,284. |
| ● | Investor relations and news dissemination of $72,196 (2020 - $45,490) relate to investor communications, including maintaining and updating the website and disseminating news releases. |
| ● | Management fees of $149,806 (2020 - $144,288) relate to fees to the Company’s Chief Executive Officer (“CEO”). The Company has entered into an employment contract with the CEO for a monthly base salary of $12,500. Effective October 1, 2021, the monthly base salary has been increased to $16,667 ($200,000 annually). |
| -34- |
Share-based compensation expenses of $2,870 (2020 - $4,175), a non-cash charge, are the estimated fair value of the stock options granted and vested during the period. The Company used the Black-Scholes option pricing model for the fair value calculation.
During the year ended September 30, 2021, the Company assessed a loss of $613,457 on the sale of the Peavy leases and office equipment (2020 - $879,070 on the ODC and Taylor leases). The Company also realized a loss of $50,165 (2020 - $Nil) on forfeiture of reclamation deposit.
Three Months Ended March 31, 2022 and 2021
During the three months ended March 31, 2022, the Company reported a net loss of $144,944 as compared to a net loss of $196,023 for the three months ended March 31, 2021. Revenue for the second quarter consisted of oil and gas sales of $228,497 (2021 - $40) and royalty income of $13,389 (2021 - $nil). Revenue from the Company’s newly acquired Breedlove “B” Clearfork leases accounted for 64% of the total oil and gas sales. The Company also brought Pittcock North, Mary Bullard, and West Henshaw wells back online during the second quarter. The direct producing and operating expenses were $115,000, approximately 51% of the gross sales. The general administrative expenses excluding depletion and depreciation, and share-based payment expenses for the three months ended March 31, 2022 were $213,783 (2021 - $132,526). The variance was mainly attributable to accounting and audit fees of $51,280 (2021 - $18,397), investor relations of $18,266 (2021 - $1,351), legal fees of $18,435 (2021 - $nil), and management fees of $59,393 (2021 - $37,513). The increase is mainly due to the increased field and general corporate activities as a result of the increased oil and gas productions and the brokered financing completed in the second quarter.
Six Months Ended March 31, 2022 and 2021
During the six months ended March 31, 2022, the Company reported a net loss of $967,709 as compared to a net loss of $307,356 for the six months ended March 31, 2021. Revenue for the first six months consisted of oil and gas sales of $318,487 (2021 - $3,094) and royalty income of $29,848 (2021 - $nil). Revenue from the Company’s newly 5 acquired Breedlove “B” Clearfork leases accounted for 67.5% of the total oil and gas sales. The Company also brought Pittcock North, Mary Bullard, and West Henshaw wells back online during the second quarter. For the three and six months, the company has produced 35 bopd and 43 bopd, respectively. The direct producing and operating expenses were $196,879, approximately 62% of the gross sales.
The general administrative expenses excluding depletion and depreciation and share-based payment expenses for the six months ended March 31, 2022 were $418,575 (2021 - $218,489). The variance was mainly attributable to:
| ● | Accounting and audit fees of $65,480 (2021 - $29,947) have increased from the prior period due to the increased production activities and the increased regulatory compliance requirements in the US as a result of the brokered financing completed in the second quarter. | |
| ● | Investor relations of $41,733 (2021 - $2,406) include investor communications, corporate website maintenance and news releases dissemination. The increase was mainly due to the Company retaining an investor relations firm in June 2021 to handle its investor relations activities. | |
| ● | Legal fees of $23,826 (2021 - $670) have increased from the prior period due to the increased regulatory compliance requirements in the US as a result of the brokered financing completed in the second quarter. | |
| ● | Management fees of $109,773 (2021 - $75,116) relate to fees to the Company’s Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”). The Company had entered into an employment contract with the CEO Company for an annual base salary of $150,000. Effective October 1, 2021, the annual base salary was increased to $200,000. | |
| ● | Marketing and promotion of $48,818 (2021 - $20,654) include mainly costs of marketing firms for investor awareness programs and campaigns. | |
| ● | Office and general of $30,223 (2021 - $10,658) have increased from the prior period due to the increase in corporate activities in general. | |
| ● | Share-based compensation expenses of $604,676 (2021 - $1,915), a non-cash charge, are the estimated fair value of the stock options granted and vested during the period. The Company used the Black-Scholes option pricing model for the fair value calculation. |
Liquidity and Capital Resources
As at March 31, 2022, the Company had a cash balance of $6,727,758, an increase of $6,701,952 from the cash balance of $25,806 on September 30, 2021. During the six months ended March 31, 2022, cash used in the operating activities is $245,954. The Company spent $75,834 on capital expenditures on its oil and gas assets and $27,774 on office lease payments. The Company received net proceeds of $7,050,714 from private placement financings and paid outstanding interest of $18,960 on the debenture loan.
The Company had a working capital of $6,243,776 as at March 31, 2022 compared to a working capital deficiency of $465,129 as at September 30, 2021.
As at September 30, 2021, the Company had a cash balance of $25,806, an increase of $20,289 from the cash balance of $5,517 on September 30, 2020. During the year ended September 30, 2021, cash used in operating activities was $720,987. The Company spent $250,581 on capital expenditures on its oil and gas assets and $43,932 on office lease payments. The Company received net proceeds of $1,123,244 from the sale of ODC San Andres Unit and W.J. “A” Taylor leases. The Company repaid debenture loan of $79,000 and a related party loan of $8,455 during fiscal 2021.
The Company had a working capital deficiency of $465,129 as at September 30, 2021 compared to working capital of $227,815 as at September 30, 2020.
Although the Company expects to invest additional capital on the continued development of its oil and gas operations, the Company currently does not have material commitments for capital expenditures. As of both March 31, 2022 and the date of this prospectus, the Company has sufficient working capital to meet its anticipated operating and capital requirements. The Company will continue to monitor the current economic and financial market conditions and evaluate their impact on the Company’s liquidity and future prospects.
| -35- |
Related Party Transactions
Year Ended September 30, 2021 and 2020
During the year ended September 30, 2020, the Company issued a total of $150,000 (C$200,000) in convertible debentures to the CEO and a director of the Company on October 17, 2019 and February 21, 2020, respectively, for cash. The debentures are secured by an interest in all of the Company’s right, title, and interest in all of its oil and gas assets, have a maturity date of September 30, 2021 and February 20, 2022, and bear interest at a rate of 12% per annum, payable on maturity. The debentures are convertible at the holder’s option into units of the Company at $0.12 (C$0.15) per unit. Each unit will be comprised of one common share of the Company and one share purchase warrant; each warrant entitles the holder to acquire one additional common share for a period of three years at an exercise price of $0.16. During the year ended September 30, 2021, the Company repaid $79,000 (C$100,000) of the convertible debenture together with accrued interest of $13,090. During the year ended September 30, 2021 and 2020, the Company accrued interest of $9,480 and $13,991, respectively, and is included within amounts due to related party on the consolidated balance sheets. As at September 30, 2021, $78,500 (C$100,000) of debenture loan remained outstanding and the interest accrued on the loan was $15,176 (2020 - $14,104).
The Company entered into the following transactions relating to key management personnel and entities over which they have control or significant influence during the year ended September 30, 2021:
| a) | Incurred management fees of $149,806 (2020 - $144,288) to a company controlled by the CEO of the Company. |
The Company has entered into an employment agreement with the CEO of the Company for an annual base salary of $150,000, with no specified term. The employment agreement may be terminated with a termination payment equal to twelve months of accrued base salary and a bonus equal to 20% of the annual salary. Effective October 1, 2021, the annual base salary has been increased to $200,000.
Six Months Ended March 31, 2022 and 2021
As at March 31, 2022, the Company had a convertible debenture of $80,000 (C$100,000) due to the CEO. The debentures are secured by an interest in all of the Company’s right, title, and interest in all of its oil and gas assets, have a maturity date of August 20, 2022, and bear interest at a rate of 12% per annum, payable on maturity. The debentures are convertible at the holder’s option into units of the Company at $0.12 (C$0.15) per unit. Each unit will be comprised of one common share of the Company and one share purchase warrant; each warrant entitles the holder to acquire one additional common share for a period of three years at an exercise price of $0.16. During the six months ended March 31, 2022 and 2021, the Company recorded interest of $3,688 and $9,768, respectively, and is included within amounts due to related party on the consolidated balance sheets.
During the six month period ended March 31, 2022, the Company incurred management fees of $109,773 (2021 - $75,116) to a company controlled by the CEO of the Company.
The Company had entered into an employment agreement with the CEO of the Company for an annual base salary of $200,000, with no specified term. The employment agreement may be terminated with a termination payment equal to twelve months of base salary and a bonus equal to 20% of the annual salary.
Subsequent to March 31, 2022, the Company amended the employment with the CEO of the Company for an annual base salary of $250,000, with no specified term. The CEO is also eligible on an annual basis for a cash bonus of up to 100% of annual salary. The employment agreement may be terminated with a termination payment equal to three years of base salary and a bonus equal to 20% of the annual base salary.
Subsequent to March 31, 2022, the Company entered into an employment with the CFO of the Company for an annual base salary of $50,000, with no specified term. The CFO is also eligible on an annual basis for a cash bonus of up to 100% of annual salary. The employment agreement may be terminated with a termination payment equal to two months of base salary.
Critical Accounting Estimates
The preparation of the Company’s consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of expenses during the period. Actual results could differ from these estimates. The Company’s management reviews these estimates and underlying assumptions on an ongoing basis, based on experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Revisions to estimates are adjusted for prospectively in the period in which the estimates are revised. Significant areas requiring the use of management estimates include:
Decommissioning obligations
Decommissioning obligations require the use of management’s best estimates of future decommissioning expenditures, expected timing of expenditures and future inflation rates. A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risk specific to the liability. Provisions are not recognized for future operating losses.
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Provisions for decommissioning associated with the Company’s oil and gas operations are based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows may differ from estimates due to changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean up technology. Estimates are made using internal and external information.
Depreciation
Equipment is amortized over the estimated useful life of the assets. Changes in the estimated useful lives or depreciation rate used could significantly increase or decrease the amount of depreciation recorded during the period and the carrying value of equipment.
Petroleum and natural gas interests
Reserves resources are used in the unit-of-production calculation for depreciation and depletion and the impairment analysis, which affects net loss. There are numerous uncertainties inherent in estimating petroleum and natural gas (“P&NG”) reserves. Estimating reserves is complex, requiring many judgments based on geological, geophysical, engineering and economic data. Changes in these judgments could have a material impact on the estimated reserves. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available and as the economic environment changes.
Share-based payments
The determination of the fair value of stock options and agent’s warrants using stock pricing models, require the input of highly subjective assumptions, including the expected price volatility. Changes in the subjective input assumptions could materially affect the fair value estimate.
Financial Instruments
The Company classified its financial instruments as follows: cash, trade and other receivables, and reclamation deposits as subsequently measured at amortized cost; and trade and other payables, amounts due to related parties, loan payable, and convertible debentures – loan component as subsequently measured at amortized cost financial liabilities.
The carrying amount of cash, trade and other receivables, reclamation deposits, trade and other payables, amounts due to related parties, loan payable, and convertible debentures carried at amortized cost is a reasonable approximation of fair value due to the relatively short period to maturity of these financial instruments and/or the rate of interest being charged.
Financial risk management
The Company’s financial risks arising from its financial instruments are credit risk, liquidity risk, foreign currency exchange risk, interest rate risk and commodity price risk. The Company’s exposures to these risks and the policies on how to mitigate these risks are set out below. Management monitors and manages these exposures to ensure appropriate measures are implemented on a timely basis and in an effective manner.
Credit risk
Credit risk is the risk of potential loss to the Company if the counter party to a financial instrument fails to meet its contractual obligations. The credit risk of the Company is associated with cash, trade and other receivables, and reclamation deposits. The credit risk with respect to its cash and reclamation deposits is minimal as they are held with high-credit quality financial institutions. The Company’s Goods and Services Tax recoverable is due from the Canadian Government. Management does not expect these counterparties to fail to meet their obligations. The Company does not anticipate any default of its trade receivables, as it transacts with creditworthy customers and management does not expect any losses from non-performance by these customers.
Liquidity risk
Liquidity risk is the risk that the Company will not meet its obligations associated with its financial liabilities as they fall due. The Company performs cash flow forecasting to ensure sufficient cash is available to fund its projects and operations. As at September 30, 2021, the Company has current assets of $84,941 and current liabilities of $550,070. The Company’s financial liabilities include accrued expenses and trade and other payables which have contractual maturities of 30 days or are due on demand and debenture loan due within the next 12 months.
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At present, the Company’s operations do not generate positive cash flows. The Company’s primary source of funding has been the issuance of equity securities through private placements and revenue from oil and gas production. Despite previous success in acquiring these financings, there is no guarantee of obtaining future financings.
Foreign exchange rate risk
Foreign currency exchange risk is the risk that fair value or future cash flows of a financial instrument will fluctuate because of changes in foreign exchange rates. The Company’s administrative expenditures are transacted in Canadian dollars. The Company funds its oil and gas operations in the United States by using United States dollars (“US dollars”) converted from its Canadian bank accounts. At September 30, 2021, the Company had financial assets of $5,846 and financial liabilities of $106,456 denominated in Canadian dollars. A 10% strengthening of the US dollar would affect net loss by approximately $10,000. The Company does not hedge its foreign exchange risk.
Interest rate risk
The Company is exposed to interest rate risk arising from cash held in Canadian financial institutions. The interest rate risk on cash is not considered significant due to its short-term nature and maturity. The exposure to interest rates for the Company is considered minimal. The Company has not used any financial instrument to hedge potential fluctuations in interest rates.
Commodity price risk
Commodity price risk is the risk that future cash flows will fluctuate as a result of changes in the price of oil and natural gas. Commodity prices are impacted by world economic events that affect supply and demand, which are generally beyond the Company’s control. Changes in crude oil prices may significantly affect the Company’s results of operations, cash generated from operating activities, capital spending and the Company’s ability to meet its obligations. The Company manages this risk by constantly monitoring commodity prices and factoring them into operational decisions, such as contracting or expanding its capital expenditures program.
Outstanding Share Data
The Company had the following common shares, stock options and warrants outstanding as of August 2, 2022.
| Issued and Outstanding Common shares | 115,956,026 | |||
| Stock options | 5,575,000 | |||
| Warrants | 65,825,806 | |||
| 187,356,832 |
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Overview
We are an independent energy company engaged in the acquisition, exploration, development and production of oil and gas properties on private, state and federal land in the United States, primarily in the Permian Basin which includes the Midland Basin and Delaware Basin. We focus on acquiring producing assets at a discount to market, increasing production and cash-flow through recompletion and re-entries, secondary recovery and lower risk infill drilling and development. Currently, we own and operate various oil and gas properties located in Texas and New Mexico. In addition, we hold various royalty interests in 73 wells and 5 permitted wells across 3,800 acres within the Permian Basin of West Texas and southeast New Mexico. Moreover, we own and operate more than 78 oil and gas wells, have more than 11,700 net acres of production oil and gas assets, 67 shut-in opportunities, 17 salt water disposal wells eliminating water disposal fees and decreasing OPEX and 2 water supply wells allowing for waterflood secondary recovery.
Oil and Gas Properties
The Company hired MKM Engineering, who prepared for the Company the Appraisal Reports. MKM Engineering is independent with respect to Permex Petroleum Corporation as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. MKM Engineering’s estimates of the Company’s proved and probable reserves in each of the Appraisal Reports were prepared according to generally accepted petroleum engineering and evaluation principles, and each of the Appraisal Reports conform to SEC Pricing. The Appraisal Reports are each filed as an exhibit to the registration statement for which this prospectus is a part of.
The Appraisal Reports were each specifically prepared by Michele Mudrone, an employee of MKM Engineering, a registered Professional Engineer in the State of Texas, and a member of the Society of Petroleum Engineers. Ms. Mudrone graduated from the Colorado School of Mines with a Bachelor of Science degree in Petroleum Engineering in 1976 and has been employed in the petroleum industry and directly involved in reservoir engineering, petrophysical analysis, reservoir simulation and property evaluation since that time Ms. Mudrone certified in each Appraisal Report that she did not receive, nor expects to receive, any direct or indirect interest in the holdings discussed in the report or in the securities of the Company. Because the Company’s current size, the Company does not have any technical person at the Company response for overseeing the preparation of the reserve estimates presented herein (or have any internal control policies pertaining to estimates of oil and gas reserves) and consequently the Company relies exclusively on the Appraisal Reports in the preparation of the reserve estimates present in this prospectus.
Since all of the Company’s reserves are from conventional reservoirs, MKM Engineering assumed for the purposes of its appraisal reports that the technology to be used to develop the Company’s reserves would include horizontally drilled wells, fracturing, and acidizing.
The following tables show a summary of our reserves as of September 30, 2021 and September 30, 2020 which have been derived from the Appraisal Reports and conform to SEC Pricing.
Composite Proved Reserve Estimates and Economic Forecasts for the year ended September 30, 2021
| Proved | Proved Developed Producing |
Proved Non-Producing |
Proved Undeveloped |
|||||||||||||||||
| Net Reserves | ||||||||||||||||||||
| Oil/Condensate | MBbl | 6,199.4 | 399.3 | 188.1 | 5,612.0 | |||||||||||||||
| Natural Gas | Mcf | 3,018.3 | 314.4 | 97.5 | 2,606.4 | |||||||||||||||
| Revenue | ||||||||||||||||||||
| Oil/Condensate | M$ | 347,051.0 | 21,920.1 | 10,468.6 | 314,662.3 | |||||||||||||||
| Natural Gas | M$ | 8,906.8 | 949.0 | 286.9 | 7,670.9 | |||||||||||||||
| Severance and Ad Valorem Taxes | M$ | 26,171.1 | 1,927.3 | 774.5 | 23,469.3 | |||||||||||||||
| Operating Expenses | M$ | 43,511.4 | 8,048.8 | 3,057.0 | 32,405.6 | |||||||||||||||
| Investments | M$ | 71,700.0 | 791.9 | 689.6 | 70,218.5 | |||||||||||||||
| Operating Income (BFIT) | M$ | 214,575.4 | 12,101.2 | 6,234.4 | 196,239.8 | |||||||||||||||
| Discounted @ 10% | M$ | 100,772.6 | 6,356.0 | 3,644.6 | 90,772.0 | |||||||||||||||
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Composite Proved Reserve Estimates and Economic Forecasts for the year ended September 30, 2020
| Proved | Proved Developed Producing |
Proved Non-Producing |
Proved Undeveloped |
|||||||||||||
| Net Reserves | ||||||||||||||||
| Oil/Condensate | MBbl | 3,706.4 | 254.9 | 294.5 | 3,157.0 | |||||||||||
| Gas | Mcf | 740.3 | 64.9 | 17.6 | 657.8 | |||||||||||
| Revenue | ||||||||||||||||
| Oil/Condensate | M$ | 149,380.6 | 10,201.3 | 12,077.9 | 127,101.4 | |||||||||||
| Gas | M$ | 1,313.0 | 58.7 | 32.6 | 1,221.7 | |||||||||||
| Severance and Ad Valorem Taxes | M$ | 11,404.2 | 903.6 | 863.4 | 9,637.2 | |||||||||||
| Operating Expenses | M$ | 38,863.8 | 5,590.5 | 2,818.4 | 30,454.9 | |||||||||||
| Investments | M$ | 26,262.9 | 630.1 | 807.0 | 24,825.8 | |||||||||||
| Operating Income (BFIT) | M$ | 74,162.6 | 3,135.8 | 7,621.7 | 63,405.1 | |||||||||||
| Discounted @ 10% | M$ | 29,113.0 | 1,806.4 | 4,057.6 | 23,249.0 | |||||||||||
Composite Probable Reserve Estimates and Economic Forecasts for the year ended September 30, 2021
| Probable | Probable Non- Producing |
Probable Undeveloped |
||||||||||||||
| Net Reserves | ||||||||||||||||
| Oil/Condensate | MBbl | 7,466.5 | 119.8 | 7,346.7 | ||||||||||||
| Natural Gas | Mcf | 10,252.1 | 6.3 | 10,245.8 | ||||||||||||
| Revenue | ||||||||||||||||
| Oil/Condensate | M$ | 411,745.8 | 6,686.4 | 405,059.4 | ||||||||||||
| Natural Gas | M$ | 30,171.8 | 18.4 | 30,153.4 | ||||||||||||
| Severance and Ad Valorem Taxes | M$ | 23,511.2 | 478.1 | 23,033.1 | ||||||||||||
| Operating Expenses | M$ | 50,336.3 | 1,061.2 | 49,275.1 | ||||||||||||
| Investments | M$ | 102,884.9 | - | 102,884.9 | ||||||||||||
| Operating Income (BFIT) | M$ | 265,185.3 | 5,165.5 | 260,019.8 | ||||||||||||
| Discounted @ 10% | M$ | 123,329.8 | 1,957.5 | 121,372.3 | ||||||||||||
Composite Probable Reserve Estimates and Economic Forecasts for the year ended September 30, 2020
| Probable | Probable Non- Producing |
Probable Undeveloped |
||||||||||||||
| Net Reserves | ||||||||||||||||
| Oil/Condensate | MBbl | 439.4 | 121.9 | 317.5 | ||||||||||||
| Natural Gas | Mcf | 126.3 | 6.3 | 120.0 | ||||||||||||
| Revenue | ||||||||||||||||
| Oil/Condensate | M$ | 17,637.2 | 5,024.7 | 12,612.5 | ||||||||||||
| Natural Gas | M$ | 232.3 | 12.3 | 220.0 | ||||||||||||
| Severance and Ad Valorem Taxes | M$ | 1,279.6 | 359.4 | 920.2 | ||||||||||||
| Operating Expenses | M$ | 2,404.2 | 952.6 | 1,451.6 | ||||||||||||
| Investments | M$ | - | - | - | ||||||||||||
| Operating Income (BFIT) | M$ | 14,185.7 | 3,725.0 | 10,460.7 | ||||||||||||
| Discounted @ 10% | M$ | 5,844.7 | 1,489.9 | 4,354.8 | ||||||||||||
Probable reserves are unproven reserves that geologic and engineering analyses suggest are more likely than not to be recoverable, They are not comparable to proved reserves and estimates of oil, condensate, and gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Such reserve and revenue estimates are based on the information currently available, the interpretation of which is subject to uncertainties inherent in applying judgmental factors.
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Conversion of Undeveloped Acreage
The Company’s process for converting undeveloped acreage to developed acreage is tied to whether there is any drilling being conducted on the acreage in question. During the fiscal year ended September 30, 2021, the Company did not commence drilling on any undeveloped acreage and no undeveloped reserves were converted into proved developed reserves. The Company has also did not make any investments in, or make any progress towards, converting proved undeveloped reserves to proved developed reserves during the year ended September 30, 2021. The Company also has not begun drilling on any undeveloped acreage or make any investments in undeveloped reserves during 2022 as of the date hereof.
An aggregate of 5,612 MBO and 2,606 MMCF, of the Company’s proved undeveloped reserves as of September 30, 2021, 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, 2021.
Proved Undeveloped Reserves Additions
From September 30, 2020 to September 30, 2021, the Company had proved undeveloped reserve additions of 2,779.78 MBoe, mostly as a result of the acquisition of an aggregate of 6,046 net acres of new properties located in Martin County, Texas during the fiscal year ended 2021, being partially offset by the sales of certain acreage at the Company’s Peavy property in Young County, Texas and the Company’s property in Gaines County, Texas to a third party and a reclassification of 120.85 MBoe from proved undeveloped reserves to probable undeveloped reserves at the Company’s West Henshaw property in Eddy County, New Mexico. This reclassification was the result of a determination in 2021 that certain proved undeveloped reserves on the West Henshaw property were not a direct offset to a producing well and consequently should be categorized as undeveloped probable reserves. The specific changes to the Company’s proved undeveloped reserves from September 30, 2020 to September 30, 2021 were as follows:
| Breedlove | Peavy | Gaines County | Henshaw | Royalty Wells | Total | |||||||||||||||||||
| Beginning balance at September 30, 2020 (MBoe)(1) | — | — | — | — | — | 3,266.59 | ||||||||||||||||||
| Production (MBoe)(1) | — | — | — | — | — | — | ||||||||||||||||||
| Revisions or reclassifications of previous estimates (MBoe)(1) | — | — | — | (120.85 | ) | — | (120.85 | ) | ||||||||||||||||
| Improved Recovery (MBoe)(1) | — | — | — | — | — | — | ||||||||||||||||||
| Extensions and Discoveries (MBoe)(1) | — | — | — | — | — | — | ||||||||||||||||||
| Acquisitions/Purchases (MBoe)(1) | 5,584.14 | — | — | — | 0.23 | 5,584.37 | ||||||||||||||||||
| Sales (MBoe)(1) | — | (70.40 | ) | (2,614.00 | ) | — | — | (2,684.40 | ) | |||||||||||||||
| Price Change (MBoe) | — | — | — | — | — | 0.66 | ||||||||||||||||||
| Ending balance as of September 30, 2021 (MBoe)(1) | — | — | — | — | — | 6,046.37 | ||||||||||||||||||
| (1) | Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended September 30, 2021, the average prices of WTI (Cushing) oil and NYMEX Henry Hub natural gas were $57.69 per Bbl and $2.94 per Mcf, respectively, resulting in an oil-to-gas ratio of over 19 to 1. |
Financing of Proved and Probable Undeveloped Reserves
The Company currently estimates that the total cost to develop the Company’s proved undeveloped reserves of 5,612.0 MBbl of oil and 2,606.4 Mcf of natural gas as of September 30, 2021 is $67,940,950.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 7,346.7 MBbl of oil and 10,245.8 Mcf of natural gas as of September 30, 2021 is $102,884,900. 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 did not drill any wells during the last three fiscal years. As at September 30, 2021, the Company had 95 gross wells and 17.29 net productive wells, with 89 wells producing oil and six wells producing natural gas, and the Company’s gross developed acreage totaled 5,177 and net developed acreage totaled 3,942 with the following geographic breakdown:
| Property | Gross Developed Acreage | Net Developed Acreage | Gross Productive Wells | Net Productive Wells | ||||||||||||
| Pittcock | 818 | 664.63 | 1 | 0.81 | ||||||||||||
| Henshaw | 1,880 | 1,353.60 | 2 | 1.44 | ||||||||||||
| Oxy Yates | 680 | 489.60 | 2 | 1.44 | ||||||||||||
| Bullard | 241 | 187.98 | 1 | 0.78 | ||||||||||||
| Breedlove | 1,558 | 1,246.4 | 16 | 12.80 | ||||||||||||
| Royalty Interest Properties | - | - | 73 | 0.01 | ||||||||||||
The Company has 6,000 gross undeveloped acres and 4,800 net undeveloped acres. All of the Company’s undeveloped acreage is on the Company’s Breedlove property.
The Company’s leases are held by production in perpetuity. If a field/lease is undeveloped it typically has a 2, 3 or 5 year term of expiry. The Company has over 340 leases covering undeveloped acreage and less than 3% of these leases have an expiry date that is less than two years from the date of this prospectus.
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Sales and Production
The average sales prices of the Company’s oil and gas products sold in the fiscal years ended September 30, 2021, 2020 and 2019 was $46.86, $38.51, and $51.79, respectively.
The Company’s net production quantities by final product sold in the fiscal years ended September 30, 2021, 2020, and 2019 was 30,623.69 Boe, 20,112.44 Boe, and 1,112.87 Boe, respectively.
The Company’s average production costs per unit for the fiscal years ended September 30, 2021, 2020, and 2019, was $23.56, $27.93, and $32.59, respectively.
The breakdown of production and prices between oil/condensate and natural gas was as follows:
| Net Production Volumes | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate (Bbl) | 947 | 16,240 | 25,513 | |||||||||
| Natural Gas (Mcf) | 1,410 | 9,196 | 13,121 | |||||||||
| Average Sales Price | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate ($/Bbl) | 58.36 | 41.09 | 49.67 | |||||||||
| Natural Gas ($/Mcf) | 3.40 | 1.44 | 2.04 | |||||||||
The breakdown of the Company’s production quantities by individual product type for each of the Company’s fields that contain 15% or more of the Company’s total proved reserves expressed on an oil-equivalent-barrels basis was as follows:
Breedlove
| Net Production Volumes | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate (Bbl) | - | - | - | |||||||||
| Natural Gas (Mcf) | 419 | - | - | |||||||||
Henshaw
| Net Production Volumes | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate (Bbl) | - | - | 1,519 | |||||||||
| Natural Gas (Mcf) | - | - | - | |||||||||
McMurtry-Loving
| Net Production Volumes | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate (Bbl) | - | - | 2,634 | |||||||||
| Natural Gas (Mcf) | - | - | - | |||||||||
ODC San Andres
| Net Production Volumes | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | Fiscal Year Ended September 30, 2019 | |||||||||
| Oil/Condensate (Bbl) | 14,464 | 11,570 | - | |||||||||
| Natural Gas (Mcf) | 4,982 | 2,605 | - | |||||||||
Texas Properties
Breedlove “B” Clearfork Leases
In September 2021, we, through our wholly-owned subsidiary, Permex Petroleum US Corporation, acquired a 100% Working Interest and an 81.75% Net Revenue Interest in the Breedlove “B” Clearfork leases located in Martin County, Texas. We issued 25,000,000 of our common shares and 12,500,000 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.
We have begun the permitting process for two locations on the Breedlove property for drilling and development. Upon approval of the permits by the regulatory body, we expect to compete in the Spraberry and Wolfcamp formations with possible fracking.
Pittcock Leases
The Pittcock Leases are situated in Stonewall County. 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.
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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 Petroleum US Corporation, 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 ours 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.
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Business Strategy
The principal elements of our business strategy include the following:
| ● | Grow production and reserves in a capital efficient manner using internally generated levered free cash flow. We intend to allocate capital in a disciplined manner to projects that we anticipate will produce predictable and attractive rates of return. We plan to direct capital to our oil-rich and low-risk development opportunities while focusing on driving cost efficiencies across our asset base with the primary objective of internally funding our capital budget and growth plan. We may also use our capital flexibility to pursue value-enhancing, bolt-on acquisitions to opportunistically improve our positions in existing basins. | |
| ● | Maximize ultimate hydrocarbon recovery from our assets by optimizing drilling, completion and production techniques and investigating deeper reservoirs and areas beyond our known productive areas. While we intend to utilize proven techniques and technologies, we will also continuously seek efficiencies in our drilling, completion and production techniques in order to optimize ultimate resource recoveries, rates of return and cash flows. We will explore innovative EOR techniques to unlock additional value and have allocated capital towards next generation technologies. For example, we have already completed extensive waterflood EOR studies in Pittcock North and Pittcock South. Through these studies, we will seek to expand our development beyond our known productive areas in order to add probable and possible reserves to our inventory at attractive all-in costs. | |
| ● | Pursue operational excellence with a sense of urgency. We plan to deliver low cost, consistent, timely and efficient execution of our drilling campaigns, work programs and operations. We intend to execute our operations in a safe and environmentally responsible manner, focus on reducing our emissions, apply advanced technologies, and continuously seek ways to reduce our operating cash costs on a per barrel basis. | |
| ● | Pursue strategic acquisitions that maintain or reduce our break-even costs. We intend to actively pursue accretive acquisitions, mergers and dispositions that are intended to improve our margins, returns, and break-even costs of our investment portfolio. Financial strategies associated with these efforts will focus on delivering competitive adjusted per share returns. |
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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 Targa Midstream Partners LP under Henry Hub gas spot prices.
For the years ended September 30, 2021 and 2020, we had one and one significant purchaser that accounted for approximately 49% and 45%, 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.
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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”), PHMSA and the courts. We cannot predict when or whether any such proposals may become effective.
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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:
| ● | require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; | |
| ● | limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and | |
| ● | impose substantial liabilities for pollution resulting from operations. |
The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are in compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry in general.
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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 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. 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.
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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 Pipeline and Hazardous Materials Safety Administration (“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.
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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 Clear Air Act 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.
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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 August 2, 2022, 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.
Facilities
Our executive offices are located at 100 Crescent Court, Suite 700, Dallas, Texas, 75201 and consists of 200 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.
Corporate History
We were incorporated on April 24, 2017 under the laws of British Columbia, Canada. At June 30, 2022, we have one wholly-owned subsidiary, Permex Petroleum US Corporation, a corporation incorporated under the laws of New Mexico (Permex U.S.). We own and operate oil and gas properties in Texas (Breedlove “B” Property, Pittcock North Property, Pittcock South Property and Mary Bullard Property), and Permex U.S. owns and operates oil and gas properties in New Mexico (Henshaw Property and the Oxy Yates Property).
Corporate Information
Our principal executive offices are located at 100 Crescent Court, Suite 700, Dallas, Texas, 75201 and our website is www.permexpetroleum.com. We do not incorporate the information on our website into this prospectus and you should not consider any such information that can be accessed through our website as part of this prospectus.
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Directors and Executive Officers
Set forth below is the name and position and a brief account of the business experience of each of our directors and executive officers as of August 2, 2022. Each of the directors listed below was elected to our Board of Directors to serve until our next annual meeting of shareholders or until his or her successor is elected and qualified.
| Name | Age | Position | ||
| Mehran Ehsan | 40 | Chief Executive Officer, President and Director | ||
| Gregory Montgomery | 53 | Chief Financial Officer and Director | ||
| Barry Whelan | 81 |
Chief Operating Officer and Director | ||
| Scott Kelly | 47 | Director | ||
| Douglas Charles Urch | 63 | Director | ||
| James Perry Bryan | 82 | Director | ||
| John James Lendrum | 71 | Director |
Biographical Information
Mehran Ehsan
Mehran Ehsan has served as the Chief Executive Officer and President and a member of the board of directors of the Company since April 2017. In addition, from July 2010 to June 2019, Mr. Ehsan served as President and Chief Executive Officer of N.A. Energy Resources Corporation, a privately held oil and gas operator. Mr. Ehsan also previously served as the Director of Business Development for West Texas Investment Corp. and a Financial Specialist (Oil and Gas) for Sterling Wealth. Mr. Ehsan received his Masters degree in finance from Heriot-Watt University and his associate’s degree in marketing/finance from the British Columbia Institute of Technology. In addition, Mr. Ehsan took professional courses in banking, corporate finance and securities law at Simon Fraser University.
We believe Mr. Ehsan is qualified to serve on our Board of Directors because he brings first-hand knowledge of the Company’s day-to-day operations as well as an understanding of the operational, financial and strategic issues facing our Company.
Gregory Montgomery
Gregory Montgomery has served as Chief Financial Officer of the Company since May 2022 and a member of the Company’s board of directors since March 2020. Since June 2021, Mr. Montgomery has served as Vice President, Project Management Office – Private Equity Energy Management of Priority Power Management, LLC. In addition from October 2018 until June 2021, he served as Partner of Vine Advisors, from October 2017 until October 2018, he served as Chief Financial Officer of Oiltanking North America and from March 2013 until October 2017, he served as Chief Financial Officer of Semarus Energy, LLC. Mr. Montgomery also served as Chief Financial Officer for Lion Copolymer, Coast Energy and Laser Midstream, and was a Director of Strategic Planning for Enbridge Energy Partners (EEP: NYSE) and Compliance Officer for Pennzoil Company (PZL: NYSE). Mr. Montgomery is a CPA and member of the Texas Society of CPA’s and American Institute of Certified Public Accountants. Mr. Montgomery holds a Bachelor of Business Administration from the University of Houston – Bauer College of Business.
We believe Mr. Montgomery is qualified to serve on our Board of Directors because he brings extensive financial and accounting experience in the oil and gas industry.
Barry Whelan
Barry Whelan has served as the Chief Operating Officer and a member of the board of directors of the Company since April 2017. Since May 2017, Mr. Whelan has served as the Chief Operating Officer and a member of the board of directors of N.A. Energy Resources Corporation, a privately held oil and gas operator. Mr. Whelan received his degrees in geology from Western University (London) and McMaster University (Hamilton). He is a past member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta, the Association of Professional Engineers and Geoscientists of British Columbia, the Institute of Geology (London, U.K.) and a Fellow of the Geological Institute of Canada.
We believe Mr. Whelan is qualified to serve on our Board of Directors because he brings first-hand knowledge of the Company’s day-to-day operations.
Scott Kelly
Scott Kelly served as the Chief Financial Officer and Corporate Secretary from December 2017 until May 2022 and has served as a member of the board of directors of the Company since December 2017. Since 2017, Mr. Kelly has been a self-employed business consultant who has held the office of Chief Financial Officer for Ely Gold Royalties Inc. (May 2007 – June 2019), Mako Mining Corp. (TSXV: MKO; OTCQX: MAKOF) (November 2018 – February 2021), Sonoro Gold Corp. (October 2010 – November 2019) (OTCQB: SMOFF; TSX: SGO) and Ethos Gold Corp. (August 2014 – April 2021) (TSX: PPP). Mr. Kelly obtained his Bachelor of Commerce degree from Royal Roads University.
We believe Mr. Kelly is qualified to serve on our Board of Directors because he brings extensive financial and accounting experience.
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Douglas Charles Urch
Douglas Urch has served as a member of the Company’s board of directors since November 2018. Since November 2019, Mr. Urch has served as the Executive Vice President and Chief Financial Officer of PetroTal Corp. (OTCQX: PTALF; TSX: TAL), and from December 2017 until October 2019, he served as chair of the board of directors. In addition, from February 2008 until September 2018, Mr. Urch served as Executive Vice President, Finance and Chief Financial Officer of Bankers Petroleum Ltd. Moreover, since April 2017, Mr. Urch has served as a member of the board of directors of Blue Moon Metals Corp. (TSXV: MOON). Mr. Urch is a Chartered Professional Accountant (CPA) and a member of the Institute of Corporate Directors (ICD). He also received a Bachelor of Commerce degree (with a major in accounting) from the University of Calgary in 1980.
We believe Mr. Urch is qualified to serve on our Board of Directors because he brings extensive financial and accounting experience in the oil and gas industry.
James Perry Bryan
James Bryan has served as a member of the Company’s board of directors since September 2021. Mr. Bryan has been involved in the energy and investment industries for more than five decades, serving as Chief Executive Officer and President of Gulf Canada Resources Limited (1995 - 1998), Chairman (1990 - 1997) and Chief Executive Officer of Nuevo Energy Company (1990 - 1995), Chief Executive Officer of Bellwether Exploration (1987 - 1997), First Vice President of E.F. Hutton & Company and Director of Investment Banking-Southwest Region (1978 - 1981), Chairman and Chief Executive Officer of Torch Energy Advisors, Inc. (1981 - 2012), President and Chief Executive Officer of The Mortgage Banque (1974 - 1978), Executive Vice President and Director of Dominick & Dominick, Inc. (1969 - 1974), and Vice President of Morgan Guaranty Trust Company (1966 - 1969). He received his B.A. from The University of Texas at Austin, his L.L.B. from The University of Texas Law School at Austin and his B.F.T. from the American Institute of Foreign Trade at Phoenix, Arizona. Among his numerous business awards are Texas Entrepreneur of the Year (1994) and Canadian Oil Producer of the Year (1995).
We believe Mr. Bryan is qualified to serve on our Board of Directors because he brings extensive experience in the oil and gas industry.
John James Lendrum
John Lendrum has served as a member of the Company’s board of directors since September 2021. Since 2015, Mr. Lendrum has served as the Non-Executive Chairman of Nuevo Midstream Dos, LLC. From 2012 to 2014, he served as the President, Chief Executive Officer and member of the board of directors of Nuevo Midstream Company (“Nuevo”). Nuevo owned and operated gas gathering, processing and treating assets in the Delaware and Permian Basins of West Texas and New Mexico and was sold to an affiliate of Anadarko Petroleum Company in 2014. Since February 2019, Mr. Lendrum serves on the board of Blue Rock Energy Partners. In 2018, he participated along with several other family offices, in the acquisition of Blue Rock from the private equity unit of TudorPickeringHolt. Mr. Lendrum has a B.B.A. in Finance and completed his graduate studies in Accounting Theory at The University of Texas at Austin.
We believe Mr. Lendrum is qualified to serve on our Board of Directors because he brings extensive experience in the oil and gas industry.
Family Relationships
There are no family relationships among any of our executive officers or directors.
Involvement in Certain Legal Proceedings
We are not aware of any of our directors or officers being involved in any legal proceedings in the past ten years relating to any matters in bankruptcy, insolvency, criminal proceedings (other than traffic and other minor offenses), or being subject to any of the items set forth under Item 401(f) of Regulation S-K under the Securities Act.
Arrangements between Officers and Directors
Except as set forth herein, to our knowledge, there is no arrangement or understanding between any of our officers or directors and any other person pursuant to which the officer or director was selected to serve as an officer or director.
Independence
We have determined Douglas Charles Urch, John James Lendrum and James Perry Bryan to be “independent” directors within the meaning of the listing standards of the New York Stock Exchange. Mehran Ehsan is not independent since he is the current President and CEO of the Company; Gregory Montgomery is not independent since he is the current CFO of the Company; Scott Kelly is not considered independent as he previously served as our CFO; and Barry Whelan is not independent since he is the current COO of the Company. In making our independence determinations, we have considered all relationships between any of the directors and the Company.
Committees of our Board of Directors
Our Board of Directors has a separately designated standing audit committee. Our Board serves in place of a compensation committee, determining the compensation of our officers and directors, and nominating and corporate governance committee, nominating members to our board of directors.
Audit Committee
Our audit committee consists of Douglas Charles Urch (Chair), Scott Kelly and Gregory Montgomery. Our Board of Directors has determined that Douglas Charles Urch meets the definition as an “independent” director within the meaning of the listing standards of the New York Stock Exchange. Each member of the audit committee is financially literate, and in addition, our Board of Directors has determined that Douglas Charles Urch qualifies as an “audit committee financial expert,” as defined in applicable SEC regulations.
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Our audit committee is responsible for overseeing our financial reporting process on behalf of the Board, including overseeing the work of the independent auditors who report directly to the audit committee. The specific responsibilities of our audit committee, among others, include:
| ● | evaluating the performance and assessing the qualifications of the independent directors and recommending to the Board and the shareholders the appointment of our external auditor; | |
| ● | determining and approving the engagement of and compensation for audit and non-audit services of our external auditor; | |
| ● | reviewing our financial statements and management’s discussion and analysis of financial condition and results of operations and recommending to the Board whether or not such financial statements and management’s discussion and analysis of financial condition and results of operations should be approved by the Board; | |
| ● | conferring with our external auditor and with management regarding the scope, adequacy and effectiveness of internal financial reporting controls; | |
| ● | establishing procedures for the receipt, retention and treatment of complaints received by us regarding our accounting controls, internal accounting controls or auditing matters and the confidential and anonymous submission by employees of concerns regarding questionable accounting and auditing matters; and | |
| ● | reviewing and discussing with management and the independent auditor, as appropriate, our guidelines and policies with respect to risk assessment and risk management, including major financial risk exposure and investment and hedging policies and the steps taken by management to monitor and control our exposure to such risks. |
Committee Charters and Other Corporate Governance Matters
Audit Committee Charter
Our Board of Directors has adopted a written charter for our audit committee.
Code of Business Conduct and Ethics
We have adopted a written Code of Business Conduct and Ethics which addresses issues including, but not limited to: (i) conflicts of interest; (ii) compliance with laws, rules, and regulations; (iii) protection and proper use of corporate opportunities; (iv) protection and proper use of corporate assets; (v)confidentiality of corporate information; (vi) fair dealing with securityholders, customers, competitors, and employees; and (vii) accuracy of business records. The Code of Business Conduct and Ethics applies to all of our directors, officers and employees. Any change or waivers from the provisions of the Code of Business Conduct and Ethics for our executive officers or directors will be made only after approval by the board of directors and will be promptly disclosed.
Director Compensation
To date, the we have not paid any cash compensation to our independent directors. Six of our directors have been granted a total of 4,825,000 options.
Executive Officer Compensation, Excluding Compensation Securities
For the purposes hereof, a named executive officer (“NEO”) of the Company means each of the following individuals:
(a) the Chief Executive Officer of the Company;
(b) the Chief Financial Officer of the Company;
(c) each of the three most highly compensated Executive Officers, or the three most highly compensated individuals acting in a similar capacity, other than the CEO and CFO, at the end of the most recently completed financial year whose total compensation was, individually, more than $150,000. “Executive Officer” means the chairman, and any vice-chairman, president, secretary or any vice-president and any officer of the Company or a subsidiary who performs a policymaking function in respect of the Company; and
(d) each individual who would be an NEO under paragraph (c) but for the fact that the individual was neither an executive officer of the Company, nor acting in a similar capacity, at the end of that financial year.
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Each of Mehran Ehsan, President and CEO of the Company, and Scott Kelly, CFO and Corporate Secretary of the Company, is a NEO of the Company for purposes of this disclosure.
The following table sets forth, for the years ended September 30, 2021 and 2020, all compensation (other than stock options and other compensation securities) paid, payable, awarded, granted, given or otherwise provided, directly or indirectly, by the Company, or a subsidiary of the Company, to each NEO and director, in any capacity.
Table of Compensation, Excluding Compensation Securities
| Table of Compensation, Excluding Compensation Securities | |||||||||||||||||||||||||||
| Name and Principal Position | Year | Salary, Consulting Fee, Retainer or Commission ($) | Bonus ($) | Committee or meeting fees ($) | Value of perquisites ($) (1)(2) | Value of All Other Compensation ($) | Total Compensation ($) | ||||||||||||||||||||
| Mehran Ehsan (3) | 2021 | $ | 149,806 | - | - | - | - | $ | 149,806 | ||||||||||||||||||
| President, CEO and Director | 2020 | $ | 141,188 | - | - | - | - | $ | 141,188 | ||||||||||||||||||
| Scott Kelly (4) | 2021 | - | - | - | - | - | - | ||||||||||||||||||||
| Former CFO and Corporate Secretary and Current Director | 2020 | - | - | - | - | - | - | ||||||||||||||||||||
| Barry Whelan (5) | 2021 | - | - | - | - | - | - | ||||||||||||||||||||
| Chief Operating Officer and Director | 2020 | $ | 3,100 | -l | - | - | - | $ | 3,100 | ||||||||||||||||||
| Gregory Montgomery (6) | 2021 | - | - | - | - | - | - | ||||||||||||||||||||
| Director | 2020 | - | - | - | - | - | - | ||||||||||||||||||||
| Edward A. Odishaw (7) | 2021 | - | - | - | - | - | - | ||||||||||||||||||||
| Director | 2020 | - | - | - | - | - | - | ||||||||||||||||||||
| Douglas Charles Urch (8) | 2021 | - | - | - | - | - | - | ||||||||||||||||||||
| Director | 2020 | - | - | - | - | - | - | ||||||||||||||||||||
(1) Includes perquisites provided to an NEO or director that are not generally available to all employees. An item is generally a perquisite if it is not integrally and directly related to the performance of the director’s or NEO’s duties. If something is necessary for a person to do his or her job, it is integrally and directly related to the job and is not a perquisite, even if it also provides some amount of personal benefit. For the purposes of the table, perquisites are valued on the basis of the aggregate incremental cost to the Company and its subsidiaries.
(2) NEOs and directors whose total salary for the applicable financial year was $150,000 or less did not receive perquisites that, in aggregate, were greater than $15,000. NEOs and directors whose total salary for the applicable financial year was greater than $150,000 but less than $500,000 did not receive perquisites that, in aggregate, were greater than 10% of the NEO’s or director’s salary for the applicable financial year.
(3) Mr. Ehsan is a director of the Company but does not receive any compensation in such capacity. Mr. Ehsan was appointed as a director of the Company on April 24, 2017.
(4) Mr. Kelly is a director of the Company but does not receive any compensation in such capacity. Mr. Kelly was appointed as a director of the Company on December 4, 2017. Mr. Kelly resigned as Chief Financial Officer of the Company on May 1, 2022.
(5) Mr. Whelan is a director of the Company but does not receive any compensation in such capacity. Mr. Whelan was appointed as a director of the Company on April 24, 2017.
(6) Mr. Montgomery was appointed as a director of the Company on March 15, 2020, and as Chief Financial Officer of the Company on May 1, 2022.
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(7) Mr. Odishaw was appointed as a director of the Company on December 4, 2017 and resigned on May 2, 2022.
(8) Mr. Urch was appointed as a director of the Company on November 1, 2018.
External Management Companies
None of the NEOs or directors of the Company have been retained or employed by an external management company which has entered into an understanding, arrangement or agreement with the Company to provide executive management services to the Company, director or indirectly, other than those set out below under “Employment Contracts, Termination Benefits and Change of Control Benefits”.
Stock Options and Other Compensation Securities
The following table discloses all compensation securities granted or issued to each director and NEO by the Company or one of its subsidiaries in the year ended September 30, 2021 for services provided or to be provided, directly or indirectly, to the Company or any of its subsidiaries.
| Compensation Securities | ||||||||||||||||||||||||||||
| Name and position | Type of compensation security(1) | Number of compensation securities, number of underlying securities, and percentage of class(2) | Date of issue or grant | Issue, conversion or exercise price ($) | Closing price of security or underlying security on date of grant ($) | Closing price of security or underlying security at year end ($) | Expiry Date (3) | |||||||||||||||||||||
| Mehran Ehsan President, CEO and Director | - | - | - | - | - | - | - | |||||||||||||||||||||
| Scott Kelly Former CFO and Corporate Secretary and Current Director (3) | - | - | - | - | - | - | - | |||||||||||||||||||||
| Barry Whelan Chief Operating Officer and Director | - | - | - | - | - | - | - | |||||||||||||||||||||
| Edward A. Odishaw Director (5) | - | - | - | - | - | - | - | |||||||||||||||||||||
| Douglas Charles Urch Director | - | - | - | - | - | - | - | |||||||||||||||||||||
| Gregory Montgomery Director (4) | - | - | - | - | - | - | - | |||||||||||||||||||||
(1) “Compensation Securities” includes stock options, convertible securities, exchangeable securities and similar instruments including stock appreciation rights, deferred share units and restricted stock units granted or issued by the Company or one of its subsidiaries for services provided or to be provided, directly or indirectly, to the Company or any of its subsidiaries.
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(2) As of September 30, 2021, the NEOs and directors held the following number of options (each one option being exercisable to acquire one common share of the Company): Mehran Ehsan – 675,000 options; Scott Kelly – 300,000 options; Barry Whelan – 300,000 options; Edward A. Odishaw – 300,000 options; Douglas Charles Urch – 300,000 options; Gregory Montgomery – 300,000 options.
(3) Mr. Kelly resigned as Chief Financial Officer of the Company on May 1, 2022.
(4) Mr. Montgomery was appointed as Chief Financial Officer of the Company on May 1, 2022.
(5) Mr. Odishaw resigned as director on May 2, 2022.
The following table discloses details regarding each exercise of Compensation Securities by a director or NEO during the year ended September 30, 2021.
| Exercise of Compensation Securities by Directors and NEOs | ||||||||||||||||||||||||||||
| Name and position | Type of compensation security | Number of underlying securities exercised | Exercise price per security ($) | Date of exercise | Closing price per security on date of exercise ($) | Difference between exercise price and closing price on date of exercise ($) | Total value on exercise date ($) | |||||||||||||||||||||
| Mehran Ehsan President, CEO and Director | - | - | - | - | - | - | - | |||||||||||||||||||||
| Scott Kelly Former CFO and Corporate Secretary and Current Director (1) | - | - | - | - | - | - | - | |||||||||||||||||||||
| Barry Whelan Chief Operating Officer and Director | - | - | - | - | - | - | - | |||||||||||||||||||||
| Edward A. Odishaw Director (3) | - | - | - | - | - | - | - | |||||||||||||||||||||
| Douglas Charles Urch Director | - | - | - | - | - | - | - | |||||||||||||||||||||
| Gregory Montgomery Director (2) | - | - | - | - | - | - | - | |||||||||||||||||||||
(1) Mr. Kelly resigned as Chief Financial Officer of the Company on May 1, 2022.
(2) Mr. Montgomery was appointed as Chief Financial Officer of the Company on May 1, 2022.
(3) Mr. Odishaw resigned as director on May 2, 2022.
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Stock Option Plans and Other Incentive Plan
Other than the Option Plan set forth below, the Company currently does not have any other stock option plan, stock option agreement made outside of a stock option plan, plan providing for the grant of stock appreciation rights, deferred share units or restricted stock units or any other incentive plan or portion of a plan under which awards are granted.
The Company’s current stock option plan (the “Option Plan”) was approved by the Board on November 27, 2017 and by the Company’s shareholders on April 8, 2022. The purpose of the Option Plan is to ensure that the Company is to able to provide an incentive program for directors, officers, employees and persons providing services to the Company (each, an “Optionee”) that provides enough flexibility in the structuring of incentive benefits to allow the Company to remain competitive in the recruitment and maintenance of key personnel.
The Option Plan is administered by the Board, which shall, without limitation, have full and final authority in its discretion, but subject to the express provisions of the Option Plan, to interpret the Option Plan, to prescribe, amend and rescind rules and regulations relating to it and to make all other determinations deemed necessary or advisable for the administration of the Option Plan, subject to any necessary shareholder or regulatory approval. The Board may delegate any or all of its authority with respect to the administration of the Option Plan. The Board shall determine to whom options shall be granted, the terms and provisions of the respective option agreements, the time or times at which such options shall be granted and vested, and the number of common shares to be subject to each option.
Under the Option Plan, options will be exercisable over periods of up to 10 years as determined by the Board. The exercise price of any option may not be less than the greater of the closing market price of the common shares on: (i) the trading day prior to the date of grant of the option; and (ii) the grant date of the option, less any applicable discount allowed by the Canadian Securities Exchange (the “CSE”) or any other stock exchange on which the common shares are listed for trading.
The maximum number of common shares which may be issued pursuant to options granted under the Option Plan is 10% of the issued and outstanding common shares at the time of the grant, provided that the common shares are listed on the CSE or any other stock exchange at the time of grant. In addition, the number of common shares which may be issuable under the Option Plan and all of the Company’s other previously established or proposed share compensation arrangements, within a one-year period:
| ● | to any one Optionee may not exceed (without the requisite disinterested shareholder approval) 5% of the issued common shares on a non-diluted basis; | |
| ● | to insiders as a group shall not exceed 10% of the total number of issued and outstanding common shares, on a non-diluted basis, at the time of the grant; and | |
| ● | to all Optionees who undertake investor relation activities shall not exceed 1% in the aggregate of the total number of issued and outstanding common shares at the time of the grant, on a non-diluted basis. |
The Option Plan permits the Board to specify a vesting schedule in its discretion, subject to minimum vesting requirements imposed by the applicable stock exchange. Unless otherwise specified by the Board at the time of granting an option, and subject to the other limits on option grants set out in the Option Plan, all options granted under the Option Plan shall vest and become exercisable in full upon grant, except Options granted to consultants performing investor relations activities, which options must vest in stages over twelve months with no more than one-quarter of the options vesting in any three month period.
The Option Plan provides that if a change of control (as defined in the Option Plan) occurs, or if the Company is subject to a take-over bid, all common shares subject to options shall immediately become vested and may thereupon be exercised in whole or in part by the option holder. The Board may also accelerate the expiry date of outstanding options in connection with a take-over bid.
The Option Plan contains adjustment provisions with respect to outstanding options in cases of share reorganizations, special distributions and other corporation reorganizations including an arrangement or other transaction under which the business or assets of the Company become, collectively, the business and assets of two or more companies with the same shareholder group upon the distribution to the Company’s shareholders, or the exchange with the Company’s shareholders, of securities of the Company or securities of another company.
The Option Plan provides that on the death or disability of an option holder, all vested options will expire at the earlier of 365 days after the date of death or disability and the expiry date of such options. Where an Optionee is terminated for cause, any outstanding options (whether vested or unvested) are cancelled as of the date of termination. If an Optionee retires or voluntarily resigns or is otherwise terminated by the Company other than for cause, then all vested options held by such Optionee will expire at the earlier of (i) the expiry date of such options and (ii) the date which is 90 days (30 days if the Optionee was engaged in investor relations activities) after the Optionee ceases its office, employment or engagement with the Company.
The Option Plan contains a provision that if pursuant to the operation of an adjustment provision of the Option Plan, an Optionee receives options (the “New Options”) to purchase securities of another company (the “New Company”) in respect of the Optionee’s options under the Option Plan (the “Subject Options”), the New Options shall expire on the earlier of: (i) the expiry date of the Subject Options; (ii) if the Optionee does not become an eligible person in respect of the New Company, the date that the Subject Options expire pursuant to the applicable provisions of the Option Plan relating to expiration of options in cases of death, disability or termination of employment discussed in the preceding paragraph above (the “Termination Provisions”); (iii) if the Optionee becomes an eligible person in respect of the New Company, the date that the New Options expire pursuant to the terms of the New Company’s stock option plan that correspond to the Termination Provisions; and (iv) the date that is one year after the Optionee ceases to be an eligible person in respect of the New Company or such shorter period as determined by the Board.
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In accordance with good corporate governance practices and as recommended by National Policy 51-201 – Disclosure Standards, the Company imposes black-out periods restricting the trading of its securities by directors, officers, employees and consultants during periods surrounding the release of annual and interim financial statements and at other times when deemed necessary by management and the Board. In order to ensure that holders of outstanding options are not prejudiced by the imposition of such black-out periods, the Option Plan contains a provision to the effect that any outstanding options with an expiry date occurring during a management imposed black-out period or within five trading days thereafter will be automatically extended to a date that is 10 trading days following the end of the black-out period.
The options granted under the Option Plan are non-assignable and non-transferable. Subject to required shareholder approval and the approval of the CSE, or any other stock exchange on which the common shares are listed, if applicable, the Board may from time to time amend or revise the terms of the Option Plan or may terminate the Option Plan at any time.
The Company does not provide any financial assistance to participants in order to facilitate the purchase of common shares under the Option Plan. As at August 2, 2022, there were options outstanding under the Option Plan to acquire 5,575,000 common shares, representing approximately 8% of the Company’s current issued and outstanding shares.
A copy of the Option Plan may be inspected at the head office of the Company, 100 Crescent Court, Suite 700, Dallas, Texas, 75201, during normal business hours and at the Meeting. In addition, a copy of the Option Plan will be mailed, free of charge, to any shareholder who requests a copy, in writing, from the Chief Financial Officer of the Company. Any such requests should be mailed to the Company, at its head office, to the attention of the Chief Financial Officer.
Employment, Consulting and Management Agreements
Other than the executive employment agreement between the Company and Mehran Ehsan, the material terms of which are set forth below, the Company does not have any compensation agreements or arrangements that the Company or any of its subsidiaries have entered into with respect to services provided by a NEO, a director or any other party in the event such services provided are typically provided by a director or NEO (collectively, “Compensation Arrangements”).
The Compensation Arrangements for Mehran Ehsan were initially set forth in the amended employment agreement dated September 1, 2021, as subsequently amended on May 1, 2022, between the Company and Mr. Ehsan (the “CEO Employment Agreement”). Pursuant to the CEO Employment Agreement, the Company employs Mr. Ehsan to serve as CEO of the Company and to perform such duties and have such authority as may from time to time be assigned by the Board. As compensation for the performance of such duties, the Company paid Mr. Ehsan a base salary of $200,000 per year (which increased to $250,000 as of May 1, 2022), which shall be reviewed by the Company annually. Mr. Ehsan is also eligible for cash bonuses and grants of Options under the Option Plan, in the sole discretion of the Board, as well as group health, medical and disability insurance benefits and any other fringe benefit programs that the Company maintains from time to time for the benefit of its employees.
The Company may immediately terminate Mr. Ehsan’s employment at any time for cause, by written notice. The Company may terminate the Mr. Ehsan’s employment at any time without cause by providing him with notice in writing and compensation in lieu of notice as follows:
| ● | payment of all outstanding and accrued base salary and vacation pay, earned and owing up to the last day of the active employment, and reimbursement for all proper expenses incurred by him in connection with the Company’s business prior to the last day of active employment; | |
| ● | payment of an amount equal to 36 months base salary; | |
| ● | payment of an amount in lieu of his performance bonus equal to 20% of base salary; and | |
| ● | continuation of his benefit coverage for a period of six months, or alternatively, if it is unable to continue Mr. Ehsan’s participation in one or more of the Company’s benefit plans, the Company shall pay him an amount equal to the premium cost or contributions the Company would otherwise have made in respect of his participation in the relevant plan(s) for six months. |
Mr. Ehsan is required to give the Company not less than two weeks’ notice in the event of his resignation. Upon receipt of his notice of resignation, or at any time thereafter, the Company has the right to elect to pay, in lieu of such notice period, Mr. Ehsan’s salary for the remainder of the notice period and a reasonable amount in lieu of the his benefits for that period. If the Company elects for payment in lieu of notice, the Mr. Ehsan’s employment shall terminate immediately upon such payment.
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If the Company determines that Mr. Ehsan has suffered a Disability (as defined below) that cannot be accommodated, the Company may terminate his employment by notice. In such case, Mr. Ehsan is entitled to receive, in lieu of all amounts otherwise payable under the CEO Employment Agreement (except for amounts earned but not yet paid to Mr. Ehsan through the date of such Disability), compensation at Mr. Ehsan’s base salary rate for a period of six months following the date of Disability or such greater amount as is required by applicable law. In the CEO Employment Agreement, “Disability” means a physical or mental incapacity of Mr. Ehsan that has prevented him from performing the duties customarily assigned to him for 180 days, whether or not consecutive, out of any 12 consecutive months and that in the opinion of the Company, acting on the basis of advice from a duly qualified medical practitioner, is likely to continue to a similar degree.
In the event of death, Mr. Ehsan’s employment shall be deemed to have terminated on the date thereof and the Company shall pay his estate the amounts specified above in respect of termination without cause.
Other than pursuant to the CEO Employment Agreement, the Company has not granted any termination or change of control benefits with respect to any Compensation Arrangement and there are no compensatory plans or arrangements with respect to any NEO or director resulting from the resignation, retirement or any other termination of any NEO or director or from a change of any NEO’s or director’s responsibilities following a change of control. In case of termination of NEOs, other than the CEO, common law and statutory law applies.
The table below sets forth information with respect to each NEO currently employed by the Company in order to assist the reader in determining the potential payment to each such NEO in the event of the termination of such NEO’s employment by the Company other than for cause or in the event of a change of control. The estimated payments have been calculated on the basis of employment agreements as they exist at the date of this prospectus and assuming that they were in effect on September 30, 2021.
| Name | Estimated Payment Assuming Termination Without Cause on September 30, 2021 ($) | Estimated Payment Assuming a Change of Control on September 30, 2021 ($) | ||||||
| Mehran Ehsan | $ | 802,000 | - | |||||
| Scott Kelly (1) | - | - | ||||||
(1) Mr. Kelly resigned as Chief Financial Officer of the Company on May 1, 2022.
The estimated payments assuming a change of control on September 30, 2021 are based on the assumption that the NEOs are terminated without cause or elect to terminate the agreements.
Oversight and Description of Director and Name Executive Officer Compensation
Elements of Compensation
Compensation to be awarded or paid to the Company’s directors and/or executive officers, including NEOs consist primarily of management fees, stock options and bonuses. Payments may be made from time to time to executive officers, including NEOs, or companies they control for the provision of consulting or management services. Such services are paid for by the Company at competitive industry rates for work of a similar nature done by reputable arm’s length services providers.
The Board will from time to time determine the stock option grants to be made pursuant to the Option Plan. It is also anticipated that the Board may award bonuses, in its sole discretion, to executive officers (including NEOs) from time to time.
The most significant components of the Company’s executive compensation plan are base salary and an annual incentive bonus. These components are based upon:
| ● | achievement of specific corporate or segment performance targets; | |
| ● | a performance evaluation process, taking into consideration comparative levels of compensation with comparable entities in the Company’s industry; | |
| ● | alignment of the compensation level of each individual to that individual’s level of responsibility; | |
| ● | the individual’s performance, competencies, skills and achievements; | |
| ● | alignment with corporate strategy; and | |
| ● | contributions to corporate or segment performance. |
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Base Salary
The base salary review of any NEO will take into consideration the current competitive market conditions, experience, proven or expected performance, and the particular skills of the NEO. Base salary is not expected to be evaluated against a formal “peer group”. The base salaries for NEOs during the fiscal year ended September 30, 2021 were set at the following:
| ● | Mehran Ehsan (CEO) –$150,000/year commencing in 2017, subject to adjustment. During the year ended September 30, 2021, Mr. Ehsan received $149,806, which has since then increased to $250,000 annually effective as of May 1, 2022. | |
| ● | Scott Kelly (CFO) – C$50,000/year. |
Performance-Based Cash Bonuses
Cash bonuses are not a normal part of the Company’s executive compensation. However, the Company may elect to utilize such incentives where the role-related context and competitive environment suggest that such a compensation modality is appropriate. When and if utilized, the amount of cash bonus compensation will normally be paid on the basis of timely achievement of specific pre-agreed milestones. Each milestone will be selected based upon consideration of its impact on shareholder value creation and the ability of the Company to achieve the milestone during a specific interval. The amount of bonus compensation will be determined based upon achievement of the milestone, its importance to the Company’s near and long term goals at the time such bonus is being considered, the bonus compensation awarded to similarly situated executives in similarly situated companies or any other factors the Company may consider appropriate at the time such performance-based bonuses are decided upon.
Stock Options
The Company currently has the Option Plan in place for the purposes of attracting and motivating directors, officers, employees, and consultants of the Company and advancing the interests of the Company by affording such persons with the opportunity to acquire an equity interest in the Company through rights granted under the Option Plan. Any grant of options under the Option Plan is within the discretion of the Board, subject to the condition that the maximum number of common shares which may be reserved for issuance under the Option Plan may not exceed 10% of the Company’s issued and outstanding common shares.
Options are also an important component of aligning the objectives of the Company’s employees with those of shareholders. The Company expects to provide significant option positions to senior employees and lesser amounts to lower-level employees.
Notwithstanding the above, the Company is still in the development stage and has an informal compensation program and strategy. The management team is committed to developing the operations of the Company and will establish a formal compensation program for directors and executive officers once it begins generating revenues sufficient to sustain operations. The Board is responsible for determining, by way of discussions at Board meetings, the ultimate compensation to be paid to the executive officers of the Company. The Company does not have a formal compensation program with set benchmarks; however, the performance of each executive will be considered along with the Company’s ability to pay compensation and its results of operation for the period.
The Company relies solely on its Board to determine the executive compensation that is to be paid to NEOs and directors without any formal objectives, criteria, or analysis.
Pension Disclosure
The Company does not currently provide any pension plan benefits for executive officers, directors, or employees.
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information regarding the beneficial ownership of our capital stock outstanding as of August 2, 2022 by:
| ● | each person, or group of affiliated persons, known by us to beneficially own more than 5% of our common shares; | |
| ● | each of our directors; | |
| ● | each of our named executive officers; and | |
| ● | all of our directors and named executive officers as a group. |
The percentage ownership information is based on 115,956,026 common shares outstanding as of August 2, 2022. The number of shares owned are those beneficially owned, as determined under the rules of the SEC. Under these rules, beneficial ownership includes any common shares as to which a person has sole or shared voting power or investment power and any common shares that the person has the right to acquire within 60 days of August 2, 2022 through the exercise of any option, warrant or right, through conversion of any security or pursuant to the automatic termination of a power of attorney or revocation of a trust, discretionary account or similar arrangement. These shares are deemed to be outstanding and beneficially owned by the person holding such option, warrants or other derivative securities for the purpose of computing the percentage ownership of that person, but they are not treated as outstanding for the purpose of computing the percentage ownership of any other person. Unless otherwise indicated, the persons or entities identified in this table have sole voting and investment power with respect to all common shares shown as beneficially owned by them, subject to applicable community property laws.
Except as otherwise noted below, the address for each person or entity listed in the table is c/o Permex Petroleum Corporation, 100 Crescent Court, Suite 700, Dallas, Texas, 75201.
| Name and Address of Beneficial Owner | Number of shares beneficially owned | Percentage of shares beneficially owned | ||||||
| Directors and Named Executive Officers: | ||||||||
| Mehran Ehsan | 7,340,308 | (1) | 6.18 | % | ||||
| Barry Whelan | 1,603,000 | (2) | 1.37 | % | ||||
| Scott Kelly | 1,700,000 | (3) | 1.46 | % | ||||
| Douglas Charles Urch | 1,090,000 | (4) | * | |||||
| Gregory Montgomery | 375,000 | (5) | * | |||||
| James Perry Bryan | 17,625,000 | (6) | 9.64 | % | ||||
| John James Lendrum | 19,875,000 | (7) | 16.21 | % | ||||
| All Officers and Directors as a Group (7 persons) | 50,108,308 | 37.24 | % | |||||
| 5% or Greater Shareholders: | ||||||||
| Empery Asset Master, LTD (8) | 12,500,000 | (9) | 19.46 | % | ||||
| Ramnarain Jaigobind (10) | 6,250,000 | (11) | 10.23 | % | ||||
* less than 1%.
(1) Represents (i) 2,056,974 common shares owned by Mehran Ehsan, (ii) 2,500,000 common shares owned by N.A. Energy Resources Corporation, (iii) 25,000 common shares owned by Mehran Ehsan’s spouse, (iv) 1,425,000 common shares issuable upon exercise of options owned by Mehran Ehsan, (v) 666,667 common shares issuable upon conversion of an outstanding secured convertible debenture in the principal amount of C$100,000, held by Mehran Ehsan and (vi) 666,667 common shares issuable upon exercise of a warrant to be issued to Mehran Ehsan upon conversion of the outstanding secured convertible debenture held by Mehran Ehsan. Mehran Ehsan is the President and Chief Executive Officer of N.A. Energy Resources Corporation and in such capacity has the right to vote and dispose of the securities held by such entity.
(2) Represents (i) 778,000 common shares owned by Barry Whelan, (ii) 25,000 common shares owned by Barry Whelan’s spouse and (iii) 800,000 common shares issuable upon exercise of options owned by Barry Whelan.
(3) Represents (i) 700,000 common shares owned by Tuareg Consulting Inc., (ii) 200,000 common shares owned by Scott Kelly’s spouse and (iii) 800,000 common shares issuable upon exercise of options owned by Scott Kelly. Scott Kelly is the owner of Tuareg Consulting Inc. and in such capacity has the right to vote and dispose of the securities held by such entity.
(4) Represents (i) 240,000 common shares and (ii) 850,000 common shares issuable upon exercise of options.
(5) Represents 375,000 common shares issuable upon exercise of options. Excludes 75,000 common shares issuable upon exercise of options that are not subject to vesting within 60 days of August 2, 2022.
(6) Represents (i) 11,750,000 common shares owned by Pratt Oil and Gas, LLC and (ii) 5,875,000 common shares issuable upon exercise of warrants owned by Pratt Oil and Gas, LLC. James Bryan has the right to vote and dispose of the securities held by Pratt Oil and Gas, LLC.
(7) Represents (i) 7,000,000 common shares owned by Petro Americas Resources, LLC, (ii) 6,250,000 common shares owned by Rockport Permian, LLC, (iii) 3,125,000 common shares issuable upon exercise of warrants owned by Rockport Permian, LLC and (iv) 3,500,000 common shares issuable upon exercise of warrants owned by Petro Americas Resources, LLC. John Lendrum has the right to vote and dispose of the securities held by each of Petro Americas Resources, LLC and Rockport Permian, LLC.
(8) Empery Asset Management LP, the authorized agent of Empery Asset Master Ltd (“EAM”), has discretionary authority to vote and dispose of the shares held by EAM and may be deemed to be the beneficial owner of these shares. Martin Hoe and Ryan Lane, in their capacity as investment managers of Empery Asset Management LP, may also be deemed to have investment discretion and voting power over the shares held by EAM. EAM, Mr. Hoe and Mr. Lane each disclaim any beneficial ownership of these shares. The address of Empery Asset Master Ltd is c/o Empery Asset Management, LP, One Rockefeller Plaza, Suite 1205, New York, NY 10020.
(9) Represents (i) 12,500,000 common shares and (ii) 12,500,000 common shares issuable upon exercise of warrants. At such time that our common shares become registered pursuant to the Exchange Act, under the terms of the warrants, the holder thereof may not exercise the warrants to the extent such exercise would cause such holder, together with its affiliates and attribution parties, to beneficially own a number of common shares which would exceed 4.99% (or, at the election of the holder, 9.99%) of our then outstanding common shares following such exercise.
(10) Represents (i) 6,250,000 common shares and (ii) 6,250,000 common shares issuable upon exercise of warrants. At such time that our common shares become registered pursuant to the Exchange Act, under the terms of the warrants, the holder thereof may not exercise the warrants to the extent such exercise would cause such holder, together with its affiliates and attribution parties, to beneficially own a number of common shares which would exceed 4.99% (or, at the election of the holder, 9.99%) of our then outstanding common shares following such exercise.
(11) Ramnarain Jaigobind is a principal of ThinkEquity LLC. ThinkEquity LLC acted as the Company’s placement agent for its March 2022 private offering. See “Private Placement of Common Shares and Warrants” above.
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PRIVATE PLACEMENT OF COMMON SHARES AND WARRANTS
We entered into subscription agreements certain of the selling shareholders identified herein pursuant to which, on March 28 and 29, 2022, we issued an aggregate of 47,128,625 units at a price of $0.16 per unit for gross proceeds of $7,540,580. Each unit is comprised of one common share and one five year common share purchase warrant. Each warrant is exercisable into one common share at an exercise price of $0.21 per share and could not be exercised until July 29, 2022. Furthermore, at such time that our common shares become registered pursuant to the Exchange Act, under the terms of the warrants, the holder thereof may not exercise the warrants to the extent such exercise would cause such holder, together with its affiliates and attribution parties, to beneficially own a number of common shares which would exceed 4.99% (or, at the election of the holder, 9.99%) of our then outstanding common shares following such exercise, excluding for purposes of such determination common shares issuable upon exercise of the warrants which have not been exercised.
In connection with the foregoing offering, we entered into registration rights agreements with certain of the selling shareholders identified herein pursuant to which we agreed to file, no later than 45 calendar days after the date of date of each respective registration rights agreement, a registration statement with the SEC covering the resale of the common shares issued in the offering as well as the common shares issuable upon exercise of the warrants issued in the offering. Pursuant to the terms of each such registration rights agreement, we must use our best efforts to cause the registration statement to be declared effective within 60 calendar days following the date on which we file our initial registration statement (the “Trigger Date”) (or, in the event of a “full review” by the SEC, 90 calendar days following the Trigger Date). We are subject to penalties and liquidated damages in the event we not meet certain filing requirements and deadlines set forth in each such registration rights agreement.
Pursuant to the placement agent agreement entered into between us and ThinkEquity LLC on March 28, 2022, ThinkEquity LLC acted as our placement agent for the offering. We paid ThinkEquity LLC a cash fee equal to 10% of the gross proceeds received by us in the offering and reimbursed ThinkEquity LLC $125,000 for its legal expenses. Moreover, we issued ThinkEquity LLC and/or its designees warrants to purchase such number of common shares equal to 10% of the units sold in the offering, or warrants to purchase up to 4,712,863 common shares, at an exercise price of $0.21 per share.
The closings of the offering were consummated on March 28 and 29, 2022. The gross proceeds from the offering, prior to deducting offering expenses and placement agent fees and expenses payable by us, were $7,540,580. 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.
The selling shareholders will receive all of the proceeds from the sale of the Resale Shares offered by them pursuant to this prospectus. We will not receive any proceeds from the sale of the Resale Shares by the selling shareholders covered by this prospectus; provided, however, if the warrants are exercised for cash, such proceeds will be used by us as follows: (i) 50% for the drilling and completion of two wells, (ii) 30% of the recompletion, stimulation and enhanced oil recovery and (iii) the balance, or 20%, for working capital.
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The common shares being offered by the selling shareholders are those previously issued to the selling shareholders, and those issuable to the selling shareholders, upon exercise of the warrants. For additional information regarding the issuances of those common shares and warrants, see “Private Placement of Common Shares and Warrants” above. We are registering the common shares in order to permit the selling shareholders to offer the Resale Shares for resale from time to time. Except for the ownership of the common shares and the warrants, or as otherwise described herein, the selling shareholders have not had any material relationship with us within the past three years.
The table below lists the selling shareholders and other information regarding the beneficial ownership of the common shares by each of the selling shareholders. The second column lists the number of common shares beneficially owned by each selling shareholder, based on its ownership of the common shares and warrants, as of August 2, 2022, assuming exercise of the warrants held by the selling shareholders on that date, without regard to any limitations on exercises.
The third column lists the Resale Shares being offered by this prospectus by the selling shareholders.
In accordance with the terms of a registration rights agreement with the selling shareholders, this prospectus generally covers the resale of the sum of (i) the number of common shares issued to the selling shareholders in the 2022 private placement, and (ii) the maximum number of common shares issuable upon exercise of the related warrants, determined as if the outstanding warrants were exercised in full as of the trading day immediately preceding the date this registration statement was initially filed with the SEC, each as of the trading day immediately preceding the applicable date of determination and all subject to adjustment as provided in the registration right agreement, without regard to any limitations on the exercise of the warrants. The third column assumes the sale of all of the Resale Shares offered by the selling shareholders pursuant to this prospectus.
At such time that our common shares become registered pursuant to the Exchange Act, under the terms of the warrants, a selling shareholder may not exercise the warrants to the extent such exercise would cause such selling shareholder, together with its affiliates and attribution parties, to beneficially own a number of common shares which would exceed 4.99% (or, at the election of the holder, 9.99%) of our then outstanding common shares following such exercise, excluding for purposes of such determination common shares issuable upon exercise of the warrants which have not been exercised. The number of shares in the second column does not reflect this limitation. The selling shareholders may sell all, some or none of their shares in this offering. See “Plan of Distribution.”
| Name of Selling Shareholder | Number of Common Shares Owned Prior to Offering | Maximum Number of Common Shares to be Sold Pursuant to this Prospectus |
Number of Common Shares Owned After Offering (1) | ||||||||
| AKS Family Partners, LP (2) † | 1,250,000 | (3) | 1,250,000 | (3) | - | ||||||
| Ardara Capital, LP (4) | 1,250,000 | (5) | 1,250,000 | (5) | - | ||||||
| Brick Lane Holdings LLC (6) | 1,875,000 | (7) | 1,875,000 | (7) | - | ||||||
| Chirag Choudhary (71) † | 1,164,667 | (8) | 1,164,667 | (8) | - | ||||||
| Evergreen Capital Management LLC (9) | 1,250,000 | (10) | 1,250,000 | (10) | - | ||||||
| Kamal Kant | 500,000 | (11) | 500,000 | (11) | - | ||||||
| Lind Global Fund II, LP (12) | 6,250,000 | (13) | 6,250,000 | (13) | - | ||||||
| ProActive Capital Partners LP (14) | 1,250,000 | (15) | 1,250,000 | (15) | - | ||||||
| Ramnarain Jaigobind (71) † | 13,303,590 | (16) | 13,303,590 | (16) | - | ||||||
| Rexford Capital LLC (17) | 1,250,000 | (18) | 1,250,000 | (18) | - | ||||||
| RL Capital Partners, LP (19) † | 625,000 | (20) | 625,000 | (20) | - | ||||||
| Robert M. Niecestro | 312,500 | (21) | 312,500 | (21) | - | ||||||
| Barry Shemaria | 120,000 | (22) | 120,000 | (22) | - | ||||||
| Tiger Trout Capital Puerto Rico LLC (23) | 2,500,000 | (24) | 2,500,000 | (24) | - | ||||||
| Turret Investments LLC (25) | 1,875,000 | (26) | 1,875,000 | (26) | - | ||||||
| Warberg WF IX LP (27) | 1,250,000 | (28) | 1,250,000 | (28) | - | ||||||
| Warberg WF X LP (29) | 1,250,000 | (30) | 1,250,000 | (30) | - | ||||||
| Alpha Capital Anstalt (31) | 6,250,000 | (32) | 6,250,000 | (32) | - | ||||||
| Flying S Ranch Trust (33) | 700,000 | (34) | 700,000 | (34) | - | ||||||
| Markley Capital Partners, L.P. (35) | 937,500 | (36) | 937,500 | (36) | - | ||||||
| Altium Growth Fund, LP (37) | 6,250,000 | (38) | 6,250,000 | (38) | - | ||||||
| Alan Gelband † | 1,000,000 | (39) | 1,000,000 | (39) | - | ||||||
| The Farkas Group Inc. (40) | 3,125,000 | (41) | 3,125,000 | (41) | - | ||||||
| Empery Asset Master Ltd (42) | 25,000,000 | (43) | 25,000,000 | (43) | - | ||||||
| LTS Holdings LLC (44) | 3,125,000 | (45) | 3,125,000 | (45) | - | ||||||
| The Funicular Fund, LP (46) | 2,500,000 | (47) | 2,500,000 | (47) | - | ||||||
| Odin Investments Ltd. (48) | 312,250 | (49) | 312,250 | (49) | - | ||||||
| Walleye Opportunities Master Fund Ltd (50) † | 6,250,000 | (51) | 6,250,000 | (51) | - | ||||||
| Kevin Mangan (71) † | 98,311 | (52) | 98,311 | (52) | - | ||||||
| Nelson Baquet (71) † | 98,310 | (53) | 98,310 | (53) | - | ||||||
| Maria Robles (71) † | 7,069 | (54) | 7,069 | (54) | - | ||||||
| Craig Skop (71) † | 108,396 | (55) | 108,396 | (55) | - | ||||||
| Jeffrey Singer (71) † | 14,139 | (56) | 14,139 | (56) | - | ||||||
| Francis Argenziano (71) † | 1,880,432 | (57) | 1,880,432 | (57) | - | ||||||
| Ryan Konik (71) † | 98,310 | (58) | 98,310 | (58) | - | ||||||
| Philip Quartuccio (71) † | 98,310 | (59) | 98,310 | (59) | - | ||||||
| Premchand Beharry (71) † | 136,681 | (60) | 136,681 | (60) | - | ||||||
| Bruce & Nancy Inglis JTWROS (71) † | 103,683 | (61) | 103,683 | (61) | - | ||||||
| Robert Sagarino (71) † | 75,406 | (62) | 75,406 | (62) | - | ||||||
| William Baquet (71) † | 488,922 | (63) | 488,922 | (63) | - | ||||||
| Charles Giordano (71) † | 62,681 | (64) | 62,681 | (64) | - | ||||||
| Richard Adams (71) † | 31,300 | (65) | 31,300 | (65) | - | ||||||
| Phyllis Henderson (71) † | 31,300 | (66) | 31,300 | (66) | - | ||||||
| Kolinda Tomasic (71) † | 6,300 | (67) | 6,300 | (67) | - | ||||||
| Angela Kang (71) † | 6,300 | (68) | 6,300 | (68) | - | ||||||
| Eric Lord (71) † | 300,445 | (69) | 300,445 | (69) | - | ||||||
| Priyanka Mahajan (71) † | 98,311 | (70) | 98,311 | (70) | - | ||||||
| Armistice Capital Master Fund Ltd. (72) | 2,500,000 | (73) | 2,500,000 | (73) | - | ||||||
| TOTAL | 98,970,113 | ||||||||||
† The selling shareholder is an affiliate of a broker-dealer. The selling shareholder has represented to us that (i) it purchased the Resale Shares in the ordinary course of business, and (ii) at the time of the purchase of the Resale Shares, the selling shareholder had no agreements or understandings, directly or indirectly, with any person to distribute the Resale Shares.
(1) Assumes that all of the Resale Shares held by the selling shareholders covered by this prospectus are sold and that the selling shareholders acquire no additional shares of common shares before the completion of this offering. However, as the selling shareholders can offer all, some, or none of their Resale Shares, no definitive estimate can be given as to the number of Resale Shares that the selling shareholders will ultimately offer or sell under this prospectus.
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(2) Adam Stern is the General Partner of AKS Family Partners, LP and in such capacity has the right to vote and dispose of the securities held by such entity. The address of AKS Family Partners, LP is 9429 Harding Avenue, #225, Surfside, FL 33154.
(3) Represents (i) 625,000 common shares and (ii) 625,000 common shares issuable upon exercise of warrants.
(4) Patrick Mullin is the Managing Partner of Ardara Capital, LP and in such capacity has the right to vote and dispose of the securities held by such entity. The address of Ardara Capital, LP is 246 Brookside Road, Darien, CT 56802.
(5) Represents (i) 625,000 common shares and (ii) 625,000 common shares issuable upon exercise of warrants.
(6) Sandra Monfared is the sole director of Brick Lane Holdings LLC and in such capacity have the right to vote and dispose of the securities held by such entity. The address of Brick Lane Holdings LLC is 315 East 68th Street, 12R, New York, NY 10065.
(7) Represents (i) 937,500 common shares and (ii) 937,500 common shares issuable upon exercise of warrants.
(8) Represents (i) 500,000 common shares and (ii) 664,667 common shares issuable upon exercise of warrants.
(9) Jeffrey Pazdro is the Manager of Evergreen Capital Management LLC and in such capacity has the right to vote and dispose of the securities held by such entity. The address of Evergreen Capital Management LLC is 156 W. Saddle River Road, Saddle River, NJ 07458.
(10) Represents (i) 625,000 common shares and (ii) 625,000 common shares issuable upon exercise of warrants.
(11) Represents (i) 250,000 common shares and (ii) 250,000 common shares issuable upon exercise of warrants.
(12) Jeff Easton is the Managing Member of The Lind Partners, LLC, which is the Investment Manager of Lind Global Fund II LP, and in such capacity has the right to vote and dispose of the securities held by such entities. Mr. Easton disclaims beneficial ownership over the securities listed except to the extent of his pecuniary interest therein. The address of The Lind Partners, LLC is 444 Madison Avenue, 41st Floor, New York, NY 10022.
(13) Represents (i) 3,125,000 common shares and (ii) 3,125,000 common shares issuable upon exercise of warrants.
(14) Jeffrey Ramson is the Manager of ProActive Capital Partners LP and in such capacity has the right to vote and dispose of the securities held by such entity. The address of ProActive Capital Partners LP is 150 East 58th Street, 16th Floor, New York, NY 10155.
(15) Represents (i) 625,000 common shares and (ii) 625,000 common shares issuable upon exercise of warrants.
(16) Represents (i) 6,250,000 common shares and (ii) 7,053,590 common shares issuable upon exercise of warrants.
(17) Kimberly Langston is the Manager of Rexford Capital LLC and in such capacity has the right to vote and dispose of the securities held by such entity. The address of Rexford Capital LLC is 78 SW 7th Street, Miami, FL 33130.
(18) Represents (i) 625,000 common shares and (ii) 625,000 common shares issuable upon exercise of warrants.
(19) Ronald Lazar is the Managing Member of RL Capital Partners, LP and in such capacity has the right to vote and dispose of the securities held by such entity. The address of RL Capital Partners, LP is 810 7th Avenue, 18th Floor, New York, NY 10019.
(20) Represents (i) 312,500 common shares and (ii) 312,500 common shares issuable upon exercise of warrants.
(21) Represents (i) 156,250 common shares and (ii) 156,250 common shares issuable upon exercise of warrants.
(22) Represents (i) 60,000 common shares and (ii) 60,000 common shares issuable upon exercise of warrants.
(23) Alan Masley is the Managing Member of Tiger Trout Capital Puerto Rico LLC and in such capacity has the right to vote and dispose of the securities held by such entity. The address of Tiger Trout Capital Puerto Rico LLC is 1357 Ashford Ave STE 2-267 San Juan, PR 00907.
(24) Represents (i) 1,250,000 common shares and (ii) 1,250,000 common shares issuable upon exercise of warrants.
(25) Michael Babcock is a director of Turret Investments LLC and in such capacity has the right to vote and dispose of the securities held by such entity. The address of Turret Investments LLC is 132 Chief Justice Cushing Hwy, Unit 216, Cohasset, MA 02025.
(26) Represents (i) 937,500 common shares and (ii) 937,500 common shares issuable upon exercise of warrants.
(27) Daniel Warsh is the Manager of Warberg WF IX LP and in such capacity has the right to vote and dispose of the securities held by such entity. The address of Warberg WF IX LP is 716 Oak Street, Winnetka, IL 60093.
(28) Represents (i) 625,000 common shares and (ii) 625,000 common shares issuable upon exercise of warrants.
(29) Daniel Warsh is the Manager of Warberg WF X LP and in such capacity has the right to vote and dispose of the securities held by such entity. The address of Warberg WF X LP is 716 Oak Street, Winnetka, IL 60093.
(30) Represents (i) 625,000 common shares and (ii) 625,000 common shares issuable upon exercise of warrants.
(31) Nicola Feuerstein is a director of Alpha Capital Anstalt and in such capacity has the right to vote and dispose of the securities held by such entity. The address of Alpha Capital Anstalt is Alpha Capital Anstalt c/o LH Financial Services, 510 Madison Avenue, Suite 1400, New York, NY 10022.
(32) Represents (i) 3,125,000 common shares and (ii) 3,125,000 common shares issuable upon exercise of warrants.
(33) Ryan W. Shay and Diane C. Shay are Co-Trustees of the Flying S Ranch Trust and in such capacities have the right to vote and dispose of the securities held by such trust.
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(34) Represents (i) 350,000 common shares and (ii) 350,000 common shares issuable upon exercise of warrants.
(35) Glen Gordon is the General Partner of Markley Capital Partners, L.P. and in such capacity has the right to vote and dispose of the securities held by such entity. The address of Markley Capital Partners, L.P. is 500 West 2nd Street, Suite 1900, Austin, TX 78701
(36) Represents (i) 468,750 common shares and (ii) 468,750 common shares issuable upon exercise of warrants.
(37) Altium Capital Management, LP, the investment manager of Altium Growth Fund, LP, has voting and investment power over these securities. Jacob Gottlieb is the managing member of Altium Capital Growth GP, LLC, which is the general partner of Altium Growth Fund, LP. Each of Altium Growth Fund, LP and Jacob Gottlieb disclaims beneficial ownership over these securities. The principal address of Altium Capital Management, LP is 152 West 57th Street, 20th Floor, New York, NY 10019.
(38) Represents (i) 3,125,000 common shares and (ii) 3,125,000 common shares issuable upon exercise of warrants.
(39) Represents (i) 500,000 common shares and (ii) 500,000 common shares issuable upon exercise of warrants.
(40) Michael D. Farkas is the President of The Farkas Group Inc. and in such capacity has the right to vote and dispose of the securities held by such entity. The address of The Farkas Group Inc. is 1221 Brickell Avenue, Suite 900, Miami, FL 33131.
(41) Represents (i) 1,562,500 common shares and (ii) 1,562,500 common shares issuable upon exercise of warrants.
(42) Empery Asset Management LP, the authorized agent of Empery Asset Master Ltd (“EAM”), has discretionary authority to vote and dispose of the shares held by EAM and may be deemed to be the beneficial owner of these shares. Martin Hoe and Ryan Lane, in their capacity as investment managers of Empery Asset Management LP, may also be deemed to have investment discretion and voting power over the shares held by EAM. EAM, Mr. Hoe and Mr. Lane each disclaim any beneficial ownership of these shares. The address of Empery Asset Master Ltd is c/o Empery Asset Management, LP, One Rockefeller Plaza, Suite 1205, New York, NY 10020.
(43) Represents (i) 12,500,000 common shares and (ii) 12,500,000 common shares issuable upon exercise of warrants.
(44) John Forsythe is the Managing Member of LTS Holdings LLC and in such capacity has the right to vote and dispose of the securities held by such entity. The address of LTS Holdings LLC is 3001 Allaire Road, Wall, NJ 07719.
(45) Represents (i) 1,562,500 common shares and (ii) 1,562,500 common shares issuable upon exercise of warrants.
(46) Jacob Ma-Weaver is the Managing Member of the General Partner of The Funicular Fund, LP and in such capacity has the right to vote and dispose of the securities held by such entity. The address of The Funicular Fund, LP is 2261 Market Street, #4307, San Francisco, CA 94114.
(47) Represents 2,500,000 common shares.
(48) Glenn Jorgensen is the President of Odin Investments Ltd. and in such capacity has the right to vote and dispose of the securities held by such entity. The address of Odin Investments Ltd. is 250 52 Street, Delta, BC V4M 2Y4, Canada.
(49) Represents (i) 156,125 common shares and (ii) 156,125 common shares issuable upon exercise of warrants.
(50) Andrew Carney is the Chief Executive Officer of Walleye Capital LLC, the Investment Manager of Walleye Opportunities Master Fund Ltd, and in such capacity has the right to vote and dispose of the securities held by such entity. The address of Walleye Opportunities Master Fund Ltd is 2800 Niagara Lane North, Plymouth, MN 55447.
(51) Represents (i) 3,125,000 common shares and (ii) 3,125,000 common shares issuable upon exercise of warrants.
(52) Represents 98,311 common shares issuable upon exercise of warrants.
(53) Represents 98,310 common shares issuable upon exercise of warrants.
(54) Represents 7,069 common shares issuable upon exercise of warrants.
(55) Represents 108,396 common shares issuable upon exercise of warrants.
(56) Represents 14,139 common shares issuable upon exercise of warrants.
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(57) Represents 1,880,432 common shares issuable upon exercise of warrants.
(58) Represents 98,310 common shares issuable upon exercise of warrants.
(59) Represents 98,310 common shares issuable upon exercise of warrants.
(60) Represents 136,681 common shares issuable upon exercise of warrants.
(61) Represents 103,683 common shares issuable upon exercise of warrants.
(62) Represents 75,406 common shares issuable upon exercise of warrants.
(63) Represents 488,922 common shares issuable upon exercise of warrants.
(64) Represents 62,681 common shares issuable upon exercise of warrants.
(65) Represents 31,300 common shares issuable upon exercise of warrants.
(66) Represents 31,300 common shares issuable upon exercise of warrants.
(67) Represents 6,300 common shares issuable upon exercise of warrants.
(68) Represents 6,300 common shares issuable upon exercise of warrants.
(69) Represents 300,445 common shares issuable upon exercise of warrants.
(70) Represents 98,311 common shares issuable upon exercise of warrants.
(71) The selling shareholder is a principal of ThinkEquity LLC. ThinkEquity LLC acted as our placement agent for our March 2022 private offering. See “Private Placement of Common Shares and Warrants” above.
(72) The securities are directly held by Armistice Capital Master Fund Ltd., a Cayman Islands exempted company (the “Master Fund”), and may be deemed to be indirectly beneficially owned by: (i) Armistice Capital, LLC (“Armistice Capital”), as the investment manager of the Master Fund; and (ii) Steven Boyd, as the Managing Member of Armistice Capital. Armistice Capital and Steven Boyd disclaim beneficial ownership of the securities except to the extent of their respective pecuniary interests therein. The address of the Master Fund is c/o Armistice Capital, LLC, 510 Madison Avenue, 7th Floor, New York, NY 10022.
(73) Represents 2,500,000 common shares issuable upon exercise of warrants. Armistice Capital Master Fund Ltd. acquired the warrants from another selling shareholder in a private offering.
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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
The following includes a summary of transactions since October 1, 2018 to which we have been a party, including transactions in which the amount involved in the transaction exceeds the lesser of $120,000 or 1% of the average of our total assets at year-end for the last two completed fiscal years and in which any of our directors, executive officers or, to our knowledge, beneficial owners of more than 5% of our capital stock or any member of the immediate family of any of the foregoing persons had or will have a direct or indirect material interest, other than equity and other compensation, termination, change in control and other arrangements which are described elsewhere in this prospectus. We are not otherwise a party to a current related party transaction and no transaction is currently proposed, in which the amount of the transaction exceeds the lesser of $120,000 or 1% of the average of our total assets at year-end for the last two completed fiscal years and in which a related person had or will have a direct or indirect material interest.
Transactions with Related Parties
During the year ended September 30, 2020, the Company issued a total of $150,000 (C$200,000) in convertible debentures to the CEO and a director of the Company for cash. The debentures are secured by an interest in all of the Company’s right, title, and interest in all of its oil and gas assets, have a maturity date of September 30, 2021 and February 20, 2022, and bear interest at a rate of 12% per annum, payable on maturity. The debentures are convertible at the holder’s option into units of the Company at $0.12 (C$0.15) per unit. Each unit will be comprised of one common share of the Company and one share purchase warrant; each warrant entitles the holder to acquire one additional common share for a period of three years at an exercise price of $0.16 (C$0.20). During the year ended September 30, 2021, the Company repaid $79,000 (C$100,000) of the convertible debenture due to a director of the Company together with accrued interest of $9,480 (C$16,570). As at September 30, 2021, $78,500 (C$100,000) of debenture loan remained outstanding and the interest accrued on the loan was $15,176 (C$19,332) (2020 – $15,176 (C$18,805)).
During the years ended September 30, 2021, 2020, and 2019 the Company incurred management fees of $149,806 $144,288, and $112,500, respectively, to a company controlled by the CEO of the Company. These payments were made in connection with the terms of the employment agreement between the Company and the CEO described below.
Since September 30, 2021, the Company has incurred an aggregate of $212,000 in management fees to a company controlled by the CEO of the Company in connection with the terms of the employment agreement between the Company and the CEO described below.
The Company’s Board of Directors is required to comply with the conflict of interest provisions of the BCBCA and relevant securities regulation in order to ensure that directors exercise independent judgment in considering transactions and agreements in respect of which a director or officer has a material interest. Any interested director is required to declare the nature and extent of his interest and is not entitled to vote on any matter that is the subject of the conflict of interest.
Agreements with Directors and Officers
The Company entered into an employment agreement with Mehran Ehsan, the Company’s CEO, on September 1, 2021 (which amended the Company’s previous employment agreement with Mr. Ehsan dated August 1, 2017), which was subsequently amended on May 1, 2022. Pursuant to this employment agreement, the Company employs Mr. Ehsan to serve as CEO of the Company and to perform such duties and have such authority as may from time to time be assigned by the Company’s Board of Directors. As compensation for the performance of such duties, the Company paid Mr. Ehsan a base salary of $200,000 per year (which increased to $250,000 as of May 1, 2022), which shall be reviewed by the Company annually. The terms of this employment agreement as amended also provide that Mr. Ehsan is eligible for an annual cash bonus of up to 100% of his annual salary. Further, the terms of this employment agreement provide that if Mr. Ehsan’s employment with the Company is terminated without “cause” (as defined in the agreement) than Mr. Ehsan is entitled to a severance payment equal to three years of base salary and a bonus equal to 20% of his annual base salary. For information regarding this employment agreement see “Management—Employment, Consulting and Management Agreements”
On May 1, 2022, the Company entered into an employment agreement with Gregory Montgomery in connection with Mr. Montgomery’s appointment as the Company’s Chief Financial Officer. This employment agreement provides that Mr. Montgomery will receive an annual base salary of $50,000 and be eligible to receive an annual cash bonus of up to 100% of this annual salary. Under the terms of this employment agreement, if Mr. Montgomery’s employment with the Company is terminated without “cause” (as defined in the agreement) he would be entitled to a severance payment equal to two months of his base salary.
For information regarding agreements between us and certain of our executive officers and directors, see “Management—Director Compensation,” “Management— Executive Officer Compensation, Excluding Compensation Securities” and “Management—Employment, Consulting and Management Agreements”.
The following description of our share capital summarizes certain provisions of our Articles. The summary does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all of the provisions of our Articles, a copy of which has been filed as an exhibit to the registration statement of which this prospectus forms a part. Prospective investors are urged to read the exhibits to the registration statement of which this prospectus forms a part for a complete understanding of our Articles.
Authorized/Issued Capital
Our authorized share capital consists of an unlimited number of common shares without par value. As of August 2, 2022, 115,956,026 common shares were issued and outstanding.
Common Shares
Each common share carries the right to attend and vote at all general meetings of shareholders. Holders of the Company’s common shares are entitled to dividends, if any, as and when declared by the Board and to one vote per common share at meetings of shareholders. In addition, upon liquidation, dissolution or winding-up of the Company, holders of common shares may share, on a pro rata basis, the remaining assets of the Company as are distributable to holders of common shares of the Company. The Company may, subject to certain exceptions, purchase, redeem or otherwise acquire any of its shares at the price and upon the terms determined by the Board of Directors. The Company’s common shares are not subject to call or assessment rights, rights regarding purchase for cancellation or surrender, or any pre-emptive or conversion rights.
Options
Our Option Plan provides for us to issue common shares or to grant incentive stock options to employees, officers, members of the Board and consultants. As of August 2, 2022, there were options to purchase up to 5,575,000 common shares outstanding at a weighted average exercise price of $0.24 per share.
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Warrants
As of August 2, 2022, there were warrants to purchase up to 65,825,806 common shares of our stock outstanding at a weighted average exercise price of $0.21 per share.
Transfer Agent and Registrar
Our transfer agent and registrar is TSX Trust Company whose address is 650 West Georgia Street, Suite 2700, Vancouver, British Columbia, Canada, V6B 4N9. TSX Trust Company maintains our registered list of shareholders.
Listing
Our common shares, no par value, are listed on the Canadian Securities Exchange and the Frankfurt Stock Exchange under the symbols “OIL” and “75P”, respectively, and quoted on the OTCQB tier of the OTC Markets Group, Inc. under the symbol “OILCF.”
Shareholder Meetings
We must hold a general meeting of our shareholders at least once in each calendar year and not more than 15 months after the preceding annual general meeting at such time and place as may be determined by the directors. If all shareholders who are entitled to vote at an annual general meeting consent by a unanimous resolution to all of the business that is required to be transacted at that annual general meeting, the annual general meeting is deemed to have been held on that date of the unanimous resolution. The location for a meeting of shareholders shall be determined by the directors and may be within or outside of the Province of British Columbia, Canada.
The Company must send notice of the date, time and location of any meeting of shareholders (including, without limitation, any notice specifying the intention to propose a resolution as an exceptional resolution, a special resolution or a special separate resolution, and any notice to consider approving an amalgamation into a foreign jurisdiction, an arrangement or the adoption of an amalgamation agreement, and any notice of a general meeting, class meeting or series meeting), in the manner provided in the Company’s Articles, or in such other manner, if any, as may be prescribed by ordinary resolution (whether previous notice of the resolution has been given or not), to each shareholder entitled to attend the meeting, to each director and to the auditor of the Company, unless the Articles of the Company otherwise provide, at least 21 days before the meeting if and for so long as the Company is a public company.
Limitations on Liability and Indemnification of Directors and Officers
Subject to the Business Corporations Act (British Columbia), the Company must indemnify a director, former director or alternate director of the Company against all judgment, penalty or find award or imposed in, or an amount paid in settlement of, an eligible proceeding. An eligible proceeding means: a legal proceeding or investigative action, whether current, threatened, pending or contemplated, in which a director, former director or alternate director of the Company or any of the heirs and legal personal representatives of the eligible party, by reason of the eligible party being or having been a director or alternate director of the Company.
The failure of a director, alternate director or officer of the Company to comply with the Business Corporations Act (British Columbia) or the Articles of Incorporation of the Company, or if applicable, any former Companies Act or former Articles, does not invalidate any indemnity to which he or she is entitled pursuant to the Articles of Incorporation of the Company.
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U.S. FEDERAL INCOME TAX CONSIDERATIONS
The following is a summary of the anticipated U.S. federal income tax consequences generally applicable to U.S. Holders (as defined below) of the ownership and disposition of our common shares. This summary addresses only holders who acquire pursuant to this offering and hold common shares as “capital assets” (generally, assets held for investment purposes).
The following summary does not purport to address all U.S. federal income tax consequences that may be relevant to a U.S. Holder (as defined below) as a result of the ownership and disposition of our common shares, nor does it take into account the specific circumstances of any particular holder, some of which may be subject to special tax rules (including, but not limited to, brokers, dealers in securities or currencies, traders in securities that elect to use a mark-to-market method of accounting for securities holdings, tax-exempt organizations, insurance companies, banks, thrifts and other financial institutions, persons liable for the alternative minimum tax, persons that hold our common shares through an entity, persons that will own, or will have owned, directly, indirectly or constructively 10% or more (by vote or value) of our common shares, persons that hold our common shares as part of a hedging, integration, conversion or constructive sale transaction or a straddle, former citizens or permanent residents of the U.S., or persons whose functional currency is not the U.S. dollar).
This summary is based on the U.S. Internal Revenue Code of 1986, as amended, U.S. Treasury regulations, administrative pronouncements and rulings of the U.S. Internal Revenue Service (“IRS”) and judicial decisions and the Canada-United States Income Tax Convention (1980), as amended, all as in effect on the date hereof, and all of which are subject to change (possibly with retroactive effect) and to differing interpretations. Except as specifically set forth below, this summary does not discuss applicable income tax reporting requirements. This summary does not describe any state, local or foreign tax law considerations, or any aspect of U.S. federal tax law other than income taxation (e.g., estate or gift tax or the Medicare contribution tax). U.S. Holders (as defined below) should consult their own tax advisers regarding such matters.
No legal opinion from U.S. legal counsel or ruling from the IRS has been requested, or will be obtained, regarding the U.S. federal income tax consequences of the ownership or disposition of our common shares. This summary is not binding on the IRS, and the IRS is not precluded from taking a position that is different from, and contrary to, the positions taken in this summary. In addition, because the authorities on which this summary is based are subject to different interpretations, the IRS and U.S. courts could disagree with one or more of the positions taken in this summary.
As used in this summary of U.S. federal income tax consequences, a “U.S. Holder” is a beneficial owner of our common shares who, for U.S. federal income tax purposes, is (i) an individual who is a citizen or resident of the U.S., (ii) a corporation (or other entity that is classified as a corporation for U.S. federal income tax purposes) that is created or organized in or under the laws of the U.S., any state thereof or the District of Columbia, (iii) an estate whose income is subject to U.S. federal income tax regardless of its source, or (iv) a trust if (A) a U.S. court can exercise primary supervision over the trust’s administration and one or more U.S. persons are authorized to control all substantial decisions of the trust, or (B) the trust has a valid election in effect to be treated as a U.S. person for U.S. federal income tax purposes.
The tax treatment of a partner in a partnership (or other entity or arrangement classified as a partnership for U.S. federal income tax purposes) that holds our common shares may depend on both the partnership’s and the partner’s status and the activities of the partnership. Partnerships (or other entities or arrangements classified as a partnership for U.S. federal income tax purposes) that are beneficial owners of our common shares, and their partners and other owners, should consult their own tax advisers regarding the tax consequences of the ownership and disposition of our common shares.
The following discussion is for general information purposes only, does not discuss all aspects of U.S. federal income taxation that may be relevant to a particular U.S. Holder in light of such holder’s circumstances and income tax situation, and is not intended to be, nor should it be construed to be, legal or tax advice to any U.S. Holder. No opinion or representation with respect to the U.S. federal income tax consequences to any U.S. Holder is made. Each U.S. Holder is urged to consult its own tax advisor regarding the particular tax consequences to it pursuant to this offering, including the application of U.S. federal, state and local tax Laws, as well as any applicable non-U.S. tax Laws, to a U.S. Holder’s particular situation, and of any change in applicable tax Laws.
General Rules Applicable to our Common Shares
Distributions on Common Shares
In general, subject to the “passive foreign investment company” (or “PFIC”) rules discussed below, the gross amount of any distribution received by a U.S. Holder with respect to our common shares (including amounts withheld to pay Canadian withholding taxes) will be included in the gross income of the U.S. Holder as a dividend to the extent attributable to our current and accumulated earnings and profits, as determined under U.S. federal income tax principles. We may not calculate our earnings and profits each year under U.S. federal income tax rules. Accordingly, U.S. Holders should expect that a distribution generally will be treated as a dividend for U.S. federal income tax purposes. Subject to the PFIC rules discussed below, distributions on our common shares to certain non-corporate U.S. Holders that are treated as dividends may be taxed at preferential rates provided we are not treated as a PFIC for the taxable year of the distribution or the preceding taxable year, and certain other (including holding period) requirements are satisfied. Such dividends will not be eligible for the “dividends received” deduction ordinarily allowed to corporate shareholders with respect to dividends received from U.S. corporations.
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The amount of any dividend paid in Canadian dollars (including amounts withheld to pay Canadian withholding taxes) will equal the U.S. dollar value of the Canadian dollars calculated by reference to the exchange rate in effect on the date the dividend is actually or constructively received by the U.S. Holder, regardless of whether the Canadian dollars are converted into U.S. dollars. A U.S. Holder will have a tax basis in the Canadian dollars equal to their U.S. dollar value on the date of receipt. If the Canadian dollars received are converted into U.S. dollars on the date of receipt, the U.S. Holder should generally not be required to recognize foreign currency gain or loss in respect of the distribution. If the Canadian dollars received are not converted into U.S. dollars on the date of receipt, a U.S. Holder may recognize foreign currency gain or loss on a subsequent conversion or other disposition of the Canadian dollars. Such gain or loss will be treated as ordinary income or loss and, in the case of a foreign currency loss of a non-corporate U.S. Holder, may be a non-deductible investment expense.
Distributions on our common shares that are treated as dividends generally will constitute income from sources outside the United States. A U.S. Holder may be eligible to elect to claim a U.S. foreign tax credit against its U.S. federal income tax liability, subject to applicable limitations and holding period requirements, for Canadian tax withheld, if any, from distributions received in respect of its common shares. A U.S. Holder that does not elect to claim a U.S. foreign tax credit may instead claim a deduction for Canadian tax withheld, but only for a taxable year in which the U.S. Holder elects to do so with respect to all foreign income taxes paid or accrued in such taxable year. The rules relating to U.S. foreign tax credits are complex, and each U.S. Holder should consult its own tax adviser regarding the application of such rules.
Sale, Exchange or Other Taxable Disposition of Common Shares
A U.S. Holder generally will recognize gain or loss on the sale, exchange or other taxable disposition of our common shares in an amount equal to the difference, if any, between the amount realized on the sale, exchange or other taxable disposition and the U.S. Holder’s adjusted tax basis in our common shares exchanged therefor. Subject to the PFIC rules discussed below, such gain or loss will be capital gain or loss and will be long-term capital gain (currently taxable at a reduced rate for non-corporate U.S. Holders) or loss if, on the date of the sale, exchange or other taxable disposition, our common shares have been held by such U.S. Holder for more than one year. The deductibility of capital losses is subject to limitations. Such gain or loss generally will be sourced within the U.S. for U.S. foreign tax credit purposes.
Passive Foreign Investment Company Rules
In general, a non-U.S. corporation is a PFIC for any taxable year in which (i) 75% or more of its gross income consists of passive income or (ii) 50% or more of the average quarterly value of its assets consists of assets that produce, or are held for the production of, passive income. For the purposes of the above calculations, a non-U.S. corporation that owns directly or indirectly, at least 25% by value of the shares of another corporation is treated as if it held its proportionate share of the assets of the other corporation and received directly its proportionate share of the income of the other corporation. Passive income generally includes dividends, interest, rents, royalties and certain gains. Cash generally is a passive asset for these purposes, other than certain limited working capital exception. Although we currently do not expect to be a PFIC for our current taxable year, because our PFIC status for any taxable year can be determined only after the end of the year and will depend on the composition of our income and assets and the value of our assets from time to time, there can be no assurance that we will not be a PFIC for our current taxable year or any future taxable year.
If we were a PFIC for any taxable year and any of our subsidiaries, consolidated affiliated entities or other companies, in which we own or are treated as owning equity interests were also a PFIC (any such entity, a “Lower-tier PFIC”), U.S. Holders would be deemed to own a proportionate amount (by value) of the shares of each Lower-tier PFIC and would be subject to U.S. federal income tax according to the rules described in the subsequent paragraph on (i) certain distributions by a Lower-tier PFIC and (ii) dispositions of shares of Lower-tier PFICs, in each case as if the U.S. Holders held such shares directly, even though the U.S. Holders had not received the proceeds of those distributions or dispositions.
In general, if we were a PFIC for any taxable year during which a U.S. Holder holds our common shares, gain recognized by such U.S. Holder on a sale or other disposition (including certain pledges) of our common shares would be allocated ratably over the U.S. Holder’s holding period. The amounts allocated to each other taxable year would be subject to tax at the highest rate in effect for individuals or corporations, as appropriate, for that taxable year, and an interest charge would be imposed on the resulting tax liability for each such year. Furthermore, to the extent that distributions received by a U.S. Holder in any year on its common shares exceed 125% of the average of the annual distributions on the common shares received during the preceding three taxable years or the U.S. Holder’s holding period for the common shares, whichever is shorter, such distributions would be subject to taxation in the same manner.
Alternatively, if we were a PFIC and if our common shares were “regularly traded” on a “qualified exchange,” as defined by applicable Treasury regulations, a U.S. Holder could make a mark-to-market election that would result in tax treatment different from the general tax treatment for PFICs described in the preceding paragraph. Our common shares would be treated as “regularly traded” for any calendar year in which more than a de minimis quantity of our common shares were traded on a qualified exchange on at least 15 days during each calendar quarter. There is uncertainty on whether our common shares are considered to be so traded. U.S. Holders will not be able to make a mark-to-market election with respect to Lower-tier PFICs, if any. Accordingly, if we were a PFIC for any taxable year even if, a U.S. Holder is able to make a mark-to-market election with respect to our shares, such holder may continue to be subject to the general PFIC rules with respect to its indirect interest in any Lower-tier PFICs.
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If a U.S. Holder makes a valid mark-to-market election, the U.S. Holder generally will recognize as ordinary income any excess of the fair market value of our common shares at the end of each taxable year over their adjusted tax basis, and will recognize an ordinary loss in respect of any excess of the adjusted tax basis of our common shares over their fair market value at the end of the taxable year (but only to the extent of the net amount of income previously included as a result of the mark-to-market election). If a U.S. Holder makes the election, the U.S. Holder’s tax basis in our common shares will be adjusted to reflect the income or loss amounts recognized. Any gain recognized on the sale or other disposition of our common shares will be treated as ordinary income and any loss will be treated as an ordinary loss (but only to the extent of the net amount of income previously included as a result of the mark-to-market election, with any excess treated as a capital loss). If a U.S. Holder makes the mark-to-market election, distributions paid on our common shares will be treated as discussed under “Distributions on Common Shares” above.
If we are a PFIC for any taxable year during which a U.S. Holder owns our common shares, we will continue to be treated as a PFIC with respect to the U.S. Holder for all succeeding years during which the U.S. Holder owns our common shares, even if we cease to meet the threshold requirements for PFIC status.
We do not intend to provide the information that would otherwise enable U.S. Holders to make a “qualified electing fund” election, which would have resulted in alternate treatment if we were a PFIC for any taxable year.
If we were a PFIC for any taxable year during which a U.S. Holder owned any of our common shares, the U.S. Holder would generally be required to file annual reports with the IRS.
The U.S. federal income tax rules relating to PFICs are very complex. U.S. Holders should consult their tax advisers regarding the determination of whether we are a PFIC for any taxable year and the potential application of the PFIC rules in their ownership and disposition of our common shares.
Information Reporting and Backup Withholding
Payments of dividends and sales proceeds from the sale or exchange of our common shares that are made within the U.S. or through certain U.S.-related financial intermediaries generally are subject to information reporting and may be subject to backup withholding, unless (i) the U.S. Holder is a corporation or other exempt recipient or (ii) in the case of backup withholding, the U.S. Holder provides a correct taxpayer identification number and certifies that it is not subject to backup withholding, generally on IRS Form W-9. Backup withholding is not an additional tax. The amount of any backup withholding from a payment to a U.S. Holder will be allowed as a credit against the holder’s U.S. federal income tax liability and may entitle it to a refund, provided that the required information is timely furnished to the IRS.
Certain U.S. Holders who are individuals (or entities formed or availed of to hold certain “specified foreign financial assets”) may be required to report information relating to their ownership of our common shares unless our common shares are held in accounts at financial institutions (in which case the accounts may be reportable if maintained by non-U.S. financial institutions). U.S. Holders should consult their tax advisers regarding their reporting obligations with respect to our common shares.
CANADIAN FEDERAL INCOME TAX CONSIDERATIONS
The following summarizes the principal Canadian federal income tax consequences applicable to the holding and disposition of our common shares in the capital of the Company by a holder who is not, and is not deemed to be, a resident of Canada for the purposes of the Income Tax Act (Canada) (the “Tax Act”), and who holds such common shares solely as capital property and does not use or hold, and is not deemed to use or hold, our common shares in connection with carrying on a business in Canada, referred to in this summary of Canadian federal income tax consequences as a “U.S. Holder.” This summary is not applicable to a U.S. Holder that is an insurer carrying on an insurance business in Canada and elsewhere.
This summary is based on the current provisions of the Tax Act, the regulations thereunder, all amendments thereto publicly proposed by the government of Canada, the published administrative practices of the Canada Revenue Agency, and the current provisions of the Convention Between Canada and the United States of America with Respect to Taxes on Income and on Capital, signed September 26, 1980, as amended (the “Canada-U.S. Tax Convention”). Except as otherwise expressly provided, this summary does not take into account any provincial, territorial or foreign (including without limitation, any U.S.) tax law or treaty. It has been assumed that all currently proposed amendments will be enacted substantially as proposed and that there is no other relevant change in any governing law or practice, although no assurance can be given in these respects.
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Each U.S. Holder is advised to obtain tax and legal advice applicable to such U.S. Holder’s particular circumstances.
Receipt of Dividends
Dividends paid or credited or deemed to be paid or credited to a U.S. Holder by the Company are subject to Canadian withholding tax at the rate of 25% of the gross amount of the dividend unless reduced by the terms of the Canada-U.S. Tax Convention. The rate of withholding tax on dividends paid or credited to a U.S. Holder who is resident in the U.S. for purposes of the Canada-U.S. Tax Convention and entitled to full benefits thereunder is generally reduced to 15% of the gross amount of the dividend (or 5% in the case of a U.S. Holder that is a company beneficially owning at least 10% of the Company’s voting shares). The Company is required to withhold the applicable tax from the dividend payable to the U.S. Holder, and to remit the tax to the Receiver General of Canada for the account of the U.S. Holder.
Disposition of Common Shares
A U.S. Holder generally will not be subject to tax under the Tax Act in respect of a capital gain realized on the disposition or deemed disposition of a common share unless such common share constitutes “taxable Canadian property” (as defined in the Tax Act) of the U.S. Holder at the time of disposition and the gain is not exempt from tax pursuant to the terms of the Canada-U.S. Tax Convention.
Provided our common shares are listed on a “designated stock exchange”, as defined in the Tax Act at the time of disposition, our common shares will generally not constitute taxable Canadian property of a U.S. Holder at that time, unless at any time during the 60-month period immediately preceding the disposition the following two conditions are satisfied concurrently: (i) (a) the U.S. Holder; (b) persons with whom the U.S. Holder did not deal at arm’s length; (c) partnerships in which the U.S. Holder or a person described in (b) holds a membership interest directly or indirectly through one or more partnerships; or (d) any combination of the persons and partnerships described in (a) through (c), owned 25% or more of the issued shares of any class or series of shares of the Company; and (ii) more than 50% of the fair market value of the common shares was derived directly or indirectly from one or any combination of: real or immovable property situated in Canada, “Canadian resource properties”, “timber resource properties” (each as defined in the Tax Act), and options in respect of, or interests in or for civil law rights in, such properties. Notwithstanding the foregoing, in certain circumstances set out in the Tax Act, our common shares may be deemed to be taxable Canadian property. Even if our common shares are taxable Canadian property of a U.S. Holder, such U.S. Holder may be exempt from tax under the Tax Act on the disposition of such common shares by virtue of the Canada-U.S. Tax Convention. In cases where a U.S. Holder disposes, or is deemed to dispose, of a common share that is taxable Canadian property of that U.S. Holder, and the U.S. Holder is not entitled to an exemption from tax under the Tax Act or pursuant to the terms of the Canada-U.S. Tax Convention, the U.S. Holder generally will realize a capital gain (or capital loss) equal to the amount, if any, by which the proceeds of disposition, net of any reasonable costs of disposition, exceed (or are exceeded by) the adjusted cost base to the U.S. Holder of such common shares, as the case may be, immediately before the disposition or deemed disposition.
A U.S. Holder who disposes of a common share that is taxable Canadian property and is not exempt from tax under the Tax Act by virtue of the Canada-U.S. Tax Convention will be obligated to comply with the withholding and reporting obligations imposed under section 116 of the Tax Act and to obtain a certificate pursuant to section 116 of the Tax Act.
Capital Gains and Capital Losses
Generally, a U.S. Holder is required to include in computing income earned in Canada for a taxation year one-half of the amount of any capital gain (a “taxable capital gain”) realized by the U.S. Holder in such taxation year from the disposition or deemed disposition of taxable Canadian property, which is not exempt from tax under the Canada-U.S. Tax Convention. Subject to and in accordance with the rules contained in the Tax Act, a U.S. Holder is required to deduct one-half of the amount of any capital loss (an “allowable capital loss”) realized in a particular taxation year from the disposition or deemed disposition of taxable Canadian property against taxable capital gains realized by the U.S. Holder in the year from the disposition or deemed disposition of taxable Canadian property. Allowable capital losses from the disposition or deemed disposition of taxable Canadian property in excess of taxable capital gains realized in a particular taxation year from the disposition or deemed disposition of taxable Canadian property may be carried back and deducted in any of the three preceding taxation years or carried forward and deducted in any subsequent taxation year against net taxable capital gains realized in such years from the disposition or deemed disposition of taxable Canadian property, to the extent and under the circumstances described in the Tax Act.
U.S. Holders who hold our common shares should consult their own tax advisers as to whether their common shares are taxable Canadian property.
| -73- |
CAUTIONARY STATEMENT ON SERVICE OF PROCESS AND THE ENFORCEMENT OF CIVIL LIABILITIES
We are a British Columbia, Canada company. As a result, the rights of holders of our common shares will be governed by the laws of British Columbia, Canada and our Articles. The rights of shareholders under the laws of British Columbia, Canada may differ from the rights of shareholders of companies incorporated in other jurisdictions. Some of our directors and some of the named experts referred to in this prospectus are not residents of the U.S. As a result, it may be difficult for investors to effect service of process on those persons in the U.S. or to enforce in the U.S. judgments obtained in U.S. courts against us or those persons based on the civil liability provisions of the U.S. securities laws. Uncertainty exists as to whether courts in British Columbia, Canada will enforce judgments obtained in other jurisdictions, including the U.S., against us or our directors or officers under the securities laws of those jurisdictions or entertain actions in British Columbia, Canada against us or our directors or officers under the securities laws of other jurisdictions.
| -74- |
Each selling shareholder of the securities and any of their pledgees, assignees and successors-in-interest may, from time to time, sell any or all of their securities covered hereby on the principal Trading Market in the United States or any other stock exchange, market or trading facility on which the securities are traded or in private transactions. These sales may be at fixed or negotiated prices. “Trading Market” means any of the following markets or exchanges on which the common shares is listed or quoted for trading on the date in question: the Canadian Securities Exchange, the NYSE American, the Nasdaq Capital Market, the Nasdaq Global Market, the Nasdaq Global Select Market, or the New York Stock Exchange, OTCQB or OTCQX (or any successors to any of the foregoing).
A selling shareholder may use any one or more of the following methods when selling securities:
| ● | ordinary brokerage transactions and transactions in which the broker-dealer solicits purchasers; | |
| ● | block trades in which the broker-dealer will attempt to sell the securities as agent but may position and resell a portion of the block as principal to facilitate the transaction; | |
| ● | purchases by a broker-dealer as principal and resale by the broker-dealer for its account; | |
| ● | an exchange distribution in accordance with the rules of the applicable exchange; | |
| ● | privately negotiated transactions; | |
| ● | settlement of short sales; | |
| ● | in transactions through broker-dealers that agree with the selling shareholders to sell a specified number of such securities at a stipulated price per security; | |
| ● | through the writing or settlement of options or other hedging transactions, whether through an options exchange or otherwise; | |
| ● | a combination of any such methods of sale; or | |
| ● | any other method permitted pursuant to applicable law. |
The selling shareholder may also sell securities under Rule 144 or any other exemption from registration under the Securities Act, if available, rather than under this prospectus.
Broker-dealers engaged by the selling shareholders may arrange for other brokers-dealers to participate in sales. Broker-dealers may receive commissions or discounts from the selling shareholders (or, if any broker-dealer acts as agent for the purchaser of securities, from the purchaser) in amounts to be negotiated, but, except as set forth in a supplement to this prospectus, in the case of an agency transaction not in excess of a customary brokerage commission in compliance with FINRA Rule 2440; and in the case of a principal transaction a markup or markdown in compliance with FINRA IM2440.
In connection with the sale of the securities or interests therein, the selling shareholders may enter into hedging transactions with broker-dealers or other financial institutions, which may in turn engage in short sales of the securities in the course of hedging the positions they assume. The selling shareholders may also sell securities short and deliver these securities to close out their short positions, or loan or pledge the securities to broker-dealers that in turn may sell these securities. The selling shareholders may also enter into option or other transactions with broker-dealers or other financial institutions or create one or more derivative securities which require the delivery to such broker-dealer or other financial institution of securities offered by this prospectus, which securities such broker-dealer or other financial institution may resell pursuant to this prospectus (as supplemented or amended to reflect such transaction).
The selling shareholders and any broker-dealers or agents that are involved in selling the securities may be deemed to be “underwriters” within the meaning of the Securities Act in connection with such sales. In such event, any commissions received by such broker-dealers or agents and any profit on the resale of the securities purchased by them may be deemed to be underwriting commissions or discounts under the Securities Act. Each selling shareholders has informed the Company that it does not have any written or oral agreement or understanding, directly or indirectly, with any person to distribute the securities.
The Company is required to pay certain fees and expenses incurred by the Company incident to the registration of the securities. The Company has agreed to indemnify the selling shareholders against certain losses, claims, damages and liabilities, including liabilities under the Securities Act.
| -75- |
We agreed to keep this prospectus effective until the earlier of (i) the date on which the securities may be resold by the selling shareholders without registration and without regard to any volume or manner-of-sale limitations by reason of Rule 144, without the requirement for the Company to be in compliance with the current public information under Rule 144 under the Securities Act or any other rule of similar effect or (ii) all of the securities have been sold pursuant to this prospectus or Rule 144 under the Securities Act or any other rule of similar effect or (iii) March 29, 2027. The resale securities will be sold only through registered or licensed brokers or dealers if required under applicable state securities laws. In addition, in certain states, the resale securities covered hereby may not be sold unless they have been registered or qualified for sale in the applicable state or an exemption from the registration or qualification requirement is available and is complied with.
Under applicable rules and regulations under the Exchange Act, any person engaged in the distribution of the resale securities may not simultaneously engage in market making activities with respect to the common shares for the applicable restricted period, as defined in Regulation M, prior to the commencement of the distribution. In addition, the selling shareholders will be subject to applicable provisions of the Exchange Act and the rules and regulations thereunder, including Regulation M, which may limit the timing of purchases and sales of the common shares by the selling shareholders or any other person. We will make copies of this prospectus available to the selling shareholders and have informed them of the need to deliver a copy of this prospectus to each purchaser at or prior to the time of the sale (including by compliance with Rule 172 under the Securities Act).
The validity of the issuance of the common shares offered hereby and other matters under the laws of British Columbia, Canada will be passed upon for us by DuMoulin Black LLP, Vancouver, British Columbia, Canada.
The consolidated financial statements of Permex Petroleum Corporation as of September 30, 2021 and 2020 and for each of the two years in the period ended September 30, 2021, included in this prospectus and in the registration statement, have been so included in reliance on the report of Davidson & Company LLP, an independent registered public accounting firm, appearing elsewhere herein and in the registration statement, given on the authority of said firm as experts in auditing and accounting.
Davidson & Company LLP, British Columbia, Canada is registered with both the Canadian Public Accountability Board and the U.S. Public Company Accounting Oversight Board.
Certain estimates of our oil and gas reserves and related information included in this prospectus have been derived from reports prepared by the independent engineering firm, MKM Engineering. All such information has been so included on the authority of such firm as an expert regarding the matters contained in its reports.
| -76- |
WHERE YOU CAN FIND ADDITIONAL INFORMATION
We have filed with the SEC a registration statement on Form S-1, including amendments and relevant exhibits and schedules, under the Securities Act covering the common shares to be sold in this offering. This prospectus does not contain all of the information contained in the registration statement that we filed. You should read the registration statement and its exhibits and schedules for further information with respect to us and our common shares. Each statement made in this prospectus concerning a document filed as an exhibit to the registration statement is qualified by reference to that exhibit for a complete statement of its provisions.
We will become subject to the periodic reporting and other informational requirements of the Exchange Act, which will require us to file reports, including annual reports, and other information with the SEC.
All information filed with the SEC, including the registration statement, will be available at the SEC’s web site at www.sec.gov. We will also make our filings available on our website at www.permexpetroleum.com. The information on our website, however, is not a part of this prospectus.
Exclusive Information
In evaluating an investment in our common shares, you should rely only on the information contained in this prospectus. We have not authorized any person to provide you with information that is different from that contained in this prospectus.
Industry and Market Data
This prospectus includes information concerning our industry and the markets in which we operate that is based on information from independent industry and research organizations and other third-party sources (including industry publications, surveys and forecasts, and management estimates. Although we believe the data from these third-party sources is reliable, we have not independently verified any third-party information and such third-party sources do not guarantee the accuracy or completeness of such information.
Management Estimates
Management estimates are derived in part from information released by independent industry analysts and other third-party sources, as well as data from our internal research, and are based on assumptions made by us upon reviewing such data and our knowledge of such industry and markets, which we believe to be reasonable. Our estimates involve risks and uncertainties, and are subject to change based on various factors, including those discussed in this prospectus under the heading “Risk Factors.”
These and other factors could cause results to differ materially from those expressed in the estimates made by the independent parties and by our management. See “Cautionary Note Regarding Forward-Looking Statements.”
References
All references to “U.S. Dollars,” “USD” or “$” are to the legal currency of the United States; all references to “CAD$” and “C$” are to the legal currency of Canada. All references to “M$” are in thousands of dollars.
Trademarks, Service Marks, and Trade Names
This prospectus may contain trademarks, service marks, trade names and copyrights of other companies, which are the property of their respective owners. Solely for convenience, the trademarks, service marks, trade names and copyrights referred to in this prospectus are listed without the TM, SM, © and ® symbols, but parties may assert, to the fullest extent under applicable law, their rights to these trademarks, service marks, trade names and copyrights.
Date of Information
The information contained in this prospectus is accurate only as of the date of this prospectus. Neither the delivery of this prospectus nor any distribution of securities pursuant to this prospectus shall, under any circumstances, create any implication that there has been no change in the information set forth or incorporated by reference into this prospectus or in our affairs since the date of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.
| -77- |
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| F-1 |
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 sheets of Permex Petroleum Corporation (the “Company”) as of September 30, 2021 and 2020, and the related consolidated statements of loss and comprehensive loss, equity, and cash flows for the years ended September 30, 2021 and 2020, 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 2020, and the results of its operations and its cash flows for the years ended September 30, 2021 and 2020, 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 audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the 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 audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
We have served as the Company’s auditor since 2017.
/s/ DAVIDSON & COMPANY LLP
Vancouver, Canada Chartered Professional Accountants
July 14, 2022
| F-2 |
PERMEX PETROLEUM CORPORATION
AS AT SEPTEMBER 30
| 2021 | 2020 | |||||||
| ASSETS | ||||||||
| Current assets | ||||||||
| Cash | $ | 25,806 | $ | 5,517 | ||||
| Trade and other receivables | 12,984 | 44,702 | ||||||
| Prepaid expenses and deposits | 46,151 | 15,603 | ||||||
| Assets held for sale | - | 2,924,465 | ||||||
| 84,941 | 2,990,287 | |||||||
| Non-current assets | ||||||||
| Reclamation deposits | 144,847 | 194,750 | ||||||
| Property and equipment | 7,846,145 | 3,765,914 | ||||||
| Right of use asset | 72,539 | 49,870 | ||||||
| Total assets | $ | 8,148,472 | $ | 7,000,821 | ||||
| LIABILITIES AND EQUITY | ||||||||
| Current liabilities | ||||||||
| Trade and other payables | $ | 402,979 | $ | 713,696 | ||||
| Amounts due to related party | 16,628 | 151,353 | ||||||
| Convertible debentures – current portion | 78,500 | 75,000 | ||||||
| Lease liability – current portion | 51,963 | 21,202 | ||||||
| Liabilities held for sale | - | 1,801,221 | ||||||
| 550,070 | 2,762,472 | |||||||
| Non-current liabilities | ||||||||
| Decommissioning obligations | 1,627,465 | 792,814 | ||||||
| Convertible debentures | - | 75,000 | ||||||
| Lease liability | 26,986 | 31,926 | ||||||
| Loan payable | 31,400 | 30,000 | ||||||
| Total liabilities | 2,235,921 | 3,692,212 | ||||||
| Equity | ||||||||
| Common stock, no par value per share; unlimited shares authorized, 66,180,364 and 40,024,114 shares issued and outstanding as of September 30, 2021 and September 30, 2020, respectively. | 8,976,747 | 6,453,039 | ||||||
| Share subscription proceeds | 30,456 | 30,456 | ||||||
| Reserves | 2,352,649 | 1,192,123 | ||||||
| Accumulated other comprehensive loss | (128,532 | ) | (270,235 | ) | ||||
| Deficit | (5,318,769 | ) | (4,096,774 | ) | ||||
| Total equity | 5,912,551 | 3,308,609 | ||||||
| Total liabilities and equity | $ | 8,148,472 | $ | 7,000,821 | ||||
The financial statements were authorized for issue by the board of directors on July 14, 2022 and were signed on its behalf by:
| “Mehran Ehsan” | Director | “Gregory Montgomery” | Director |
The accompanying notes are an integral part of these consolidated financial statements.
| F-3 |
PERMEX PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF LOSS AND COMPREHENSIVE LOSS
YEARS ENDED SEPTEMBER 30
| 2021 | 2020 | |||||||
| Revenue | ||||||||
| Oil and gas sales | $ | 46,703 | $ | 682,786 | ||||
| Royalty income | 37,922 | - | ||||||
| Total revenue | 84,625 | 682,786 | ||||||
| Operating expenses | ||||||||
| Producing | 59,671 | 557,624 | ||||||
| Accounting and audit | 78,090 | 66,710 | ||||||
| Accretion on decommissioning obligations | 11,722 | 45,371 | ||||||
| Consulting | 18,394 | 41,724 | ||||||
| Depletion and depreciation | 60,479 | 37,291 | ||||||
| Filing and transfer agent | 54,822 | 27,922 | ||||||
| Interest | 13,506 | 15,905 | ||||||
| Investor relations and news dissemination | 72,196 | 45,490 | ||||||
| Legal fees | 14,803 | 11,218 | ||||||
| Management fees | 149,806 | 144,288 | ||||||
| Marketing and promotion | 27,251 | 13,984 | ||||||
| Office and miscellaneous | 32,203 | 28,150 | ||||||
| Rent | 54,336 | 27,010 | ||||||
| Salaries | - | 24,816 | ||||||
| Share-based payments | 2,870 | 4,175 | ||||||
| Travel | 11,483 | 10,069 | ||||||
| Total operating expenses | (661,632 | ) | (1,101,747 | ) | ||||
| Operating loss | (577,007 | ) | (418,961 | ) | ||||
| Foreign exchange gain (loss) | (24,301 | ) | 5,402 | |||||
| Forfeiture of reclamation deposit | (50,165 | ) | - | |||||
| Gain on settlement of decommissioning obligations | - | 10,415 | ||||||
| Other income | 10,191 | 9,683 | ||||||
| Settlement of trade payables | 9,682 | 23,329 | ||||||
| Loss on disposal of property and equipment | (613,457 | ) | (879,070 | ) | ||||
| Net loss | (1,245,057 | ) | (1,249,202 | ) | ||||
| Other comprehensive income (loss) | ||||||||
| Foreign currency translation adjustment | 141,703 | (39,084 | ) | |||||
| Comprehensive loss | $ | (1,102,709 | ) | $ | (1,288,083 | ) | ||
| Basic and diluted loss per common share | $ | (0.03 | ) | $ | (0.03 | ) | ||
The accompanying notes are an integral part of these consolidated financial statements.
| F-4 |
PERMEX PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
| Number of Shares | Share capital | Reserves | Share subscription proceeds | Accumulated other comprehensive loss | Deficit | Total equity | ||||||||||||||||||||||
| Balance, September 30, 2019 | 40,024,114 | $ | 6,453,039 | $ | 1,387,846 | $ | 30,456 | $ | (231,151 | ) | $ | (3,047,470 | ) | $ | 4,592,720 | |||||||||||||
| Share-based payments | - | - | 4,175 | - | - | - | 4,175 | |||||||||||||||||||||
| Adjustment on cancelation of stock options | - | - | (199,898 | ) | - | - | 199,898 | - | ||||||||||||||||||||
| Net loss | - | - | - | - | - | (1,249,202 | ) | (1249,202 | ) | |||||||||||||||||||
| Other comprehensive income | - | - | - | - | (39,084 | ) | - | (39,084 | ) | |||||||||||||||||||
| Balance, September 30, 2020 | 40,024,114 | $ | 6,453,039 | $ | 1,192,123 | $ | 30,456 | $ | (270,235 | ) | $ | (4,096,774 | ) | $ | 3,308,609 | |||||||||||||
| Acquisition of property | 25,000,000 | 2,468,750 | - | - | - | - | 2,468,750 | |||||||||||||||||||||
| Acquisition of property - warrants | - | - | 1,180,718 | - | - | - | 1,180,718 | |||||||||||||||||||||
| Shares issued for services | 1,156,250 | 54,958 | - | - | - | - | 54,958 | |||||||||||||||||||||
| Share-based payments | - | - | 2,870 | - | - | - | 2,870 | |||||||||||||||||||||
| Adjustment on cancelation of stock options | - | - | (23,062 | ) | - | - | 23,062 | - | ||||||||||||||||||||
| Net loss | - | - | - | - | - | (1,245,057 | ) | (1,245,057 | ) | |||||||||||||||||||
| Other comprehensive income | - | - | - | - | 141,703 | - | 141,703 | |||||||||||||||||||||
| Balance, September 30, 2021 | 66,180,364 | $ | 8,976,747 | $ | 2,352,649 | $ | 30,456 | $ | (128,532 | ) | $ | (5,318,769 | ) | $ | 5,912,551 | |||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-5 |
PERMEX PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30
| 2021 | 2020 | |||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||
| Net loss | $ | (1,245,057 | ) | $ | (1,249,202 | ) | ||
| Adjustments to reconcile net loss to net cash from operating activities: | ||||||||
| Accretion on decommissioning obligations | 11,722 | 45,371 | ||||||
| Depletion and depreciation | 60,479 | 37,291 | ||||||
| Foreign exchange loss (gain) | 87,747 | (2,208 | ) | |||||
| Forfeiture of reclamation bond | 50,165 | - | ||||||
| Interest | 13,506 | 15,904 | ||||||
| Gain on settlement of decommissioning obligations | - | (10,415 | ) | |||||
| Settlement of trade payables | (9,682 | ) | (23,329 | ) | ||||
| Proceeds from redemption of credit card deposit | - | 18,600 | ||||||
| Share-based payments | 2,870 | 4,175 | ||||||
| Shares issued for services | 54,958 | - | ||||||
| Loss on disposal of property and equipment | 613,457 | 879,070 | ||||||
| Trade and other receivables | 34,092 | 58,169 | ||||||
| Prepaid expenses and deposits | (29,977 | ) | 40,218 | |||||
| Trade and other payables | (234,475 | ) | 82,876 | |||||
| Amounts due to related parties | (162,598 | ) | 102,052 | |||||
| Right of use asset and lease liability | 46,942 | 24,194 | ||||||
| Net cash used in operating activities | (705,851 | ) | 22,766 | |||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||
| Capital expenditures on property and equipment | (265,717 | ) | (128,752 | ) | ||||
| Proceeds from sale of oil and gas interests | 1,123,244 | - | ||||||
| Net cash provided by (used in) investing activities | 857,527 | (128,752 | ) | |||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||
| Convertible debentures | (79,000 | ) | 148,800 | |||||
| Loan proceeds | - | 29,760 | ||||||
| Loan from related party | (8,455 | ) | (48,793 | ) | ||||
| Lease payments | (43,932 | ) | (20,962 | ) | ||||
| Net cash provided by (used in) financing activities | (131,387 | ) | 108,805 | |||||
| Change in cash during the year | 20,289 | 2,819 | ||||||
| Cash, beginning of the year | 5,517 | 2,698 | ||||||
| Cash, end of the year | $ | 25,806 | $ | 5,517 | ||||
| Supplemental disclosures of non-cash investing and financing activities: | ||||||||
| Common stock issued in connection with property acquisition agreement | $ | 2,468,750 | $ | - | ||||
| Common stock purchase warrants issued in connection with property acquisition agreement | 1,180,718 | - | ||||||
| Trade and other payables related to property and equipment | 68,735 | 157,240 | ||||||
| Adjustments to decommissioning liabilities | 796,809 | 189,375 | ||||||
| Supplemental cash flow disclosures: | ||||||||
| Interest paid | 13,090 | - | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-6 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 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 500, 666 Burrard Street, Vancouver, British Columbia, Canada, V6C 2X8 and its US office at Suite 700, 100 Crescent Court, Dallas, Texas, 75201. Its registered office is located at 10th 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”.
| 2. | Significant Accounting Policies |
Basis of presentation
These consolidated financial statements include the accounts of the Company and its wholly owned subsidiary, Permex Petroleum US Corporation and have been prepared in accordance with generally accepted accounting principles in the United States of America (“US GAAP”).
These consolidated financial statements are presented in United States dollars (“USD”). The functional currency of the Company is the Canadian dollar (“CAD”). The functional currency for the subsidiary of the Company is the United States dollar (“USD”).
Principles of Consolidation
The accompanying consolidated financial statements include the assets, liabilities, revenue and expenses of all wholly-owned subsidiaries. All intercompany balances and transactions have been eliminated.
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) amounts subject to allowances and returns; (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 decommissioning liabilities; (iv) income taxes receivable or payable; (v) the useful lives of assets for the purposes of depreciation; (vi) petroleum and natural gas reserves; 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.
Cash
The Company considers all highly liquid investments with an original maturity of three months or less when purchased to be cash and cash equivalents. Cash and cash equivalents are recorded at cost, which approximates fair value.
| F-7 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 2. | Significant Accounting Policies (cont’d…) |
Trade and other receivables
Trade and other receivables are stated at net realizable value. The majority of customers are not extended credit and therefore time to maturity for receivables is short. On a periodic basis, management evaluates its accounts receivable and determines whether to provide an allowance or if any accounts should be written off based on a past history of write-offs, collections, and current credit conditions. A receivable is considered past due if the Company has not received payments based on agreed-upon terms. Given the nature and balances of the Company’s receivables the Company has no material loss allowance as at September 30, 2021 and September 30, 2020.
Property and equipment
The Company follows the successful efforts method of accounting for its oil and gas properties. All costs for development wells along with related acquisition costs, the costs of drilling development wells, and related asset retirement obligation (ARO) assets are capitalized. Exploration costs, such as exploratory geological and geophysical costs, and costs associated with non-productive exploratory wells, delay rentals and exploration overhead are expensed. Costs of drilling exploratory wells are capitalized pending determination of whether the wells found proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company groups its oil and gas properties with a common geological structure or stratigraphic condition (“common operating field”) for purposes of computing depletion expenses, assessing proved property impairments and accounting for asset dispositions.
Capitalized costs of proved oil and gas properties are depleted by individual field using a unit-of-production method based on proved and probable developed reserves. Proved reserves are estimated using reserve engineer reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids, which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible.
Proved oil and natural gas properties are assessed for possible impairment by comparing their carrying values with their associated undiscounted, future net cash flows. Events that can trigger assessments for possible impairments include write-downs of proved reserves based on field performance, significant decreases in the market value of an asset (including changes to the commodity price forecast or carbon costs), significant change in the extent or manner of use of or a physical change in an asset, and a more-likely-than-not expectation that a long-lived asset or asset group will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their discounted, future net cash flows. For proved oil and natural gas properties, the Company performs impairment reviews on a field basis, annually or as appropriate.
Other corporate equipment consist primarily of leasehold improvements and computer equipment and are stated at cost less accumulated depreciation. The capitalized costs are generally depreciated on a straight line basis over their estimated useful lives as follows:
| Computer equipment | 2 years |
| Leasehold improvements | 5 years |
| F-8 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 3. | SIGNIFICANT ACCOUNTING POLICIES (cont’d…) |
Property and equipment (cont’d…)
For property dispositions, measurement is at fair value, unless the transaction lacks commercial substance or fair value cannot be reliably measured. Where the exchange is measured at fair value, a gain or loss is recognized in net income. Any deferred consideration recorded on property dispositions are recognized as revenue in the statement of loss and comprehensive loss over the reserve life.
Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s depletion rate. These gains and losses are classified as asset dispositions in the accompanying consolidated statements of loss and comprehensive loss. Partial common operating field sales or dispositions deemed not to significantly alter the depletion rates are generally accounted for as adjustments to capitalized costs with no gain or loss recognized.
Impairment of long-lived assets
The Company assesses long-lived assets for impairment in accordance with the provisions of Financial Accounting Standards Board ASC 360, Property, Plant and Equipment. Long-lived assets (asset group), such as property and equipment and capitalized software development costs subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. The amount of impairment loss, if any, is measured as the difference between the carrying value of the asset and its estimated fair value. Fair value is determined through various valuation techniques, including discounted cash flow models, quoted market values, and third-party independent appraisals, as considered necessary. As of September 30, 2021 and 2020, no impairment charge has been recorded.
Decommissioning liabilities
The Company’s activities give rise to dismantling, decommissioning, and site disturbance remediation activities. A provision is made for the estimated cost of site restoration and capitalized in the relevant asset category.
Decommissioning liabilities are measured at the present value of management’s best estimate of the expenditure required to settle the present obligation at the reporting date. Changes in the present value of the estimated expenditure are reflected as an adjustment to the provision and the relevant asset. The unwinding of the discount on the decommissioning provision is recognized as an accretion expense. Actual costs incurred upon settlement of the decommissioning liabilities are charged against the provision to the extent the provision was recognized.
Decommissioning obligations require the use of management’s best estimates of future decommissioning expenditures, expected timing of expenditures and future inflation rates. A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risk specific to the liability. Provisions are not recognized for future operating losses.
Provisions for decommissioning associated with the Company’s oil and gas operations are based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows may differ from estimates due to changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean up technology. Estimates are made using internal and external information.
| F-9 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 3. | SIGNIFICANT ACCOUNTING POLICIES (cont’d…) |
Fair value measurement
Fair value accounting is applied for all assets and liabilities and nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Fair value is defined as the exchange price that would be received for an asset or an exit price that would be paid to transfer a liability in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The Company follows the established framework for measuring fair value and expands disclosures about fair value measurements.
The Company categorizes its assets and liabilities measured at fair value into a three-level hierarchy based on the priority of the inputs to the valuation technique used to determine fair value. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). If the inputs used in the determination of the fair value measurement fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement.
Assets and liabilities valued at fair value are categorized based on the inputs to the valuation techniques as follows:
Level 1 – Inputs that utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access.
Level 2 – Inputs that include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. Fair values for these instruments are estimated using pricing models, quoted prices of securities with similar characteristics, or discounted cash flows.
Level 3 – Inputs that are unobservable inputs for the asset or liability, which are typically based on an entity’s own assumptions, as there is little, if any, related market activity.
The financial statements as of and for the years ended September 30, 2021 and 2020, do not include any recurring or nonrecurring fair value measurements relating to assets or liabilities.
Subsequent to initial recognition, the Company may re-measure the carrying value of assets and liabilities measured on a nonrecurring basis to fair value. Adjustments to fair value usually result when certain assets are impaired. Such assets are written down from their carrying amounts to their fair value.
Professional standards allow entities the irrevocable option to elect to measure certain financial instruments and other items at fair value for the initial and subsequent measurement on an instrument-by-instrument basis. The Company has not elected to measure any existing financial instruments at fair value. However, it may elect to measure newly acquired financial instruments at fair value in the future.
| F-10 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 3. | SIGNIFICANT ACCOUNTING POLICIES (cont’d…) |
Leases
At inception of a contract, the Company assesses whether a contract is, or contains a lease based on whether the contract conveys the right to control the use of an identified asset for a period in exchange for consideration.
The Company recognizes a right-of-use asset and a lease obligation at the lease commencement date. The right-of-use asset is initially measured based on the initial amount of the lease obligation adjusted for any lease payments made at or before the commencement date.
The lease obligation is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Company’s incremental borrowing rate. Generally, the Company uses its incremental borrowing rate as the discount rate. Variable lease payments that do not depend on an index or rate are not included in the measurement of the lease obligation. The lease obligation is subsequently measured at amortized cost using the effective interest rate method.
Share capital
The Company records proceeds from the issuance of its common shares as equity. Incremental costs directly attributable to the issue of new common shares are shown in equity as a deduction, net of tax, from the proceeds. Common shares issued for consideration other than cash are valued based on their market value at the date that the shares are issued.
Warrants issued with private placement units are classified as equity and initially recorded at fair value with no subsequent remeasurement. Proceeds from the issuance of private placement units are allocated between the private placement warrants and common shares on a relative fair value basis.
Earnings (loss) per share
Basic earnings (loss) per share (“EPS”) is calculated by dividing the EPS attributable to common shareholders by the weighted average number of common shares outstanding in the period. The diluted EPS reflects all dilutive potential common shares equivalents, in the weighted average number of common shares outstanding during the period, if dilutive. All of the outstanding convertible securities, stock options and warrants were anti-dilutive for the years ended September 30, 2021 and 2020.
| F-11 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 3. | SIGNIFICANT ACCOUNTING POLICIES (cont’d…) |
Share-based payments
The Company issues stock options and other share-based compensation to directors, employees and others service providers. Equity awards including stock options and share purchase warrants are measured at grant date at the fair value of the instruments issued and amortized over the vesting periods using a graded approach. The amount recognized as an expense is adjusted to reflect the actual number of share options that are expected to vest. Each tranche in an award is considered a separate grant with a different vesting date and fair value and is accounted for on that basis.
The offset to the recorded cost is to share-based payments reserve. The number of options expected to vest is reviewed and adjusted at the end of each reporting period such that the amount ultimately recognized as an expense is based on the number of options that eventually vest. Consideration received on the exercise of stock options is recorded as share capital and the related share-based payments reserve is transferred to share capital.
The fair value of the equity awards is determined using the Black-Scholes option pricing model. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility (based on weighted average historic volatility), weighted average expected life of the instruments (based on historical experience), expected dividends, and the risk-free interest rate (based on government bonds).
Revenue
In accordance with ASC 606, Revenue from Contracts with Customers, the Company recognizes revenue when a customer obtains control of a promised good. For natural gas, this is generally at the time product enters the pipeline. For crude oil, this is generally at the time the product reaches a trucking terminal. For natural gas liquids, this is generally at the time the product reaches a gas plant. The amount of revenue recognized reflects consideration that the Company expects to be entitled to receive in exchange for these goods, net of discounts, customs duties, royalties and withholding tax. Royalty income represents net revenue interests from the sale of crude oil and natural gas and is recognized when the operators of the properties complete the sale of crude oil and natural gas.
For natural gas, this is generally at the time product enters the pipeline. For crude oil, this is generally at the time the product reaches a trucking terminal. For natural gas liquids, this is generally at the time the product reaches a gas plant. Revenue is measured net of discounts, customs duties, royalties and withholding tax. Royalty income represents net revenue interests from the sale of crude oil and natural gas and is recognized upon the operators of the properties completing the sale of crude oil and natural gas.
The Company records revenue in the month production is delivered to the purchaser. However, production statements for oil and gas sales may not be received until the following month end after the products are purchased, and as a result, the Company is required to estimate the amount of revenue to be received. The Company records the differences between its estimates and the actual amounts received for revenue in the month that payment is received from the customer. Identified differences between the Company’s revenue estimates and actual revenue received historically have not been significant. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to sales volumes and prices for those good sold are estimated and recorded.
The Company does not have any contract assets or liabilities, or capitalized contract costs.
| F-12 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 3. | SIGNIFICANT ACCOUNTING POLICIES (cont’d…) |
Foreign currencies
Foreign currency transactions are translated into the functional currency using exchange rates prevailing at the dates of the transactions. At the end of each reporting period, monetary assets and liabilities that are denominated in foreign currencies are translated at the rates prevailing at that date. Non-monetary assets and liabilities are translated using the historical rate on the date of the transaction. Non-monetary assets and liabilities that are stated at fair value are translated using the historical rate on the date that the fair value was determined. All gains and losses on translation of these foreign currency transactions are charged to profit or loss.
Financial statements of the parent company prepared under their functional currencies are translated into United States dollars for consolidation purposes as follows: assets and liabilities are translated using the exchange rate prevailing at the reporting date; revenue and expenses are translated using the average rates of exchange for the period. Gains and losses resulting from translation adjustments are recorded to other comprehensive income (loss) and accumulated as a separate component of shareholders’ equity, described as foreign currency translation adjustment.
Income taxes
Current taxes receivable or payable are estimated on taxable income or loss for the current year at the statutory tax rates enacted or substantively enacted at the reporting date.
Deferred income tax is recognized on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Deferred income tax assets and liabilities are measured at the tax rates that have been enacted or substantially enacted at the end of the reporting period and are expected to apply when the related deferred income tax asset is realized or the deferred income tax liability is settled. Deferred income tax assets also result from unused loss carry forwards, resource related pools and other deductions. At the end of each reporting year the Company reassesses unrecognized deferred tax assets. Deferred income tax assets are recognized for unused tax losses, tax credits and deductible temporary differences, only to the extent that it is probable that future taxable profit will be available against which they can be utilized.
Deferred income tax assets and deferred income tax liabilities are offset if a legally enforceable right exists to offset current tax assets against current tax liabilities and the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority.
| F-13 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 3. | SIGNIFICANT ACCOUNTING POLICIES (cont’d…) |
New accounting standards
In August 2020, the FASB issued ASU No. 2020-06, Debt — Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging — Contracts in Entity’s Own Equity (Subtopic 815-40) – Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity (“ASU 2020-06”). ASU 2020-06 simplifies the guidance on the issuer’s accounting for convertible debt instruments by removing the separation models for (1) convertible debt with a cash conversion feature and (2) convertible instruments with a beneficial conversion feature. As a result, entities will not separately present in equity an embedded conversion feature in such debt. Instead, they will account for a convertible debt instrument wholly as debt, and for convertible preferred stock wholly as preferred stock, unless (1) a convertible instrument contains features that require bifurcation as a derivative under ASC 815 or (2) a convertible debt instrument was issued at a substantial premium. The elimination of these models will reduce reported interest expense and increase reported net income for entities that have issued a convertible instrument that is within the scope of ASU 2020-06. ASU 2020-06 requires entities to provide expanded disclosures about the terms and features of convertible instruments, how the instruments have been reported in the entity’s financial statements, and information about events, conditions, and circumstances that can affect the amount or timing of an entity’s future cash flows related to those instruments. ASU 2020-06 further removes three of the conditions for equity classification from ASC 815-40-25-10 and requires freestanding contracts on an entity’s own equity that do not qualify as equity under ASC 815-40 to be accounted for at fair value, with changes in fair value recognized in earnings, irrespective of whether such contracts meet the definition of a derivative in ASC 815. ASU 2020-06 also requires the application of the if-converted method for calculating diluted earnings per share and the treasury stock method will be no longer available. ASU 2020-06 is effective for fiscal years beginning after December 15, 2023, with early adoption permitted, but no earlier than fiscal years beginning after December 15, 2020. The Company adopted ASU 2020-06 during the year ended September 30, 2021.
In June 2016, the FASB issued ASU No. 2016-13 (Topic 326), Financial Instruments — Credit Losses – Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”). ASU 2016-13 changes how to recognize expected credit losses on financial assets. The standard requires more timely recognition of credit losses on loans and other financial assets and also provides additional transparency about credit risk. The current credit loss standard generally requires that a loss actually be incurred before it is recognized, while the new standard will require recognition of full lifetime expected losses upon initial recognition of the financial instrument. Originally, ASU 2016-13 was effective for fiscal years beginning after December 15, 2019, with early adoption permitted. In November 2019, FASB issued ASU No. 2019-10, Financial Instruments — Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842). This ASU defers the effective date of ASU 2016-13 for non-public companies to fiscal years beginning after December 15, 2022. The Company is currently evaluating the impact of this standard on its financial statements and related disclosures.
| 3. | CONCENTRATION OF CREDIT RISK |
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.
During the year ended September 30, 2021, the Company generated 49% of total revenue from one customer (2020 - 45%). As at September 30, 2021, one customer represented $2,927 (26%) of the trade receivable balance (2020 - one customer represented $38,465 (95%)). It is in management’s opinion that the Company is not exposed to significant credit risk.
| F-14 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 4. | NON-CURRENT ASSETS |
The Company is engaged in the exploration for, and the development of, petroleum and natural gas projects in the United States. The Company holds 100% working interests and 71.9% to 81.75% net revenue interests and certain royalty interests in the various oil and gas properties located in Texas and New Mexico.
Reclamation bonds
As of September 30, 2021, the Company held reclamation bonds of $144,847 (2020 - $194,750), which are expected to be released after all reclamation work has been completed with regard to its oil and natural gas interests. During the year ended September 30, 2021, the Company wrote off $50,165 of reclamation deposit forfeited by the Texas State government due to violation on a previous owned property.
Property and equipment
Property and equipment as of September 30, 2021 and 2020 consisted of the following:
| 2021 | 2020 | |||||||
| Oil and natural gas properties | $ | 7,954,807 | $ | 3,803,800 | ||||
| Corporate assets | - | 42,436 | ||||||
| Property and equipment, at cost | 7,954,807 | 3,846,236 | ||||||
| Less: accumulated depreciation and depletion | (108,662 | ) | (80,322 | ) | ||||
| Property and equipment, net | $ | 7,846,145 | $ | 3,765,914 | ||||
Depreciation and depletion expense was $60,479 and $37,291 for the years ended September 30, 2021 and 2020, respectively.
Acquisition
During the year ended September 30, 2021, the Company, through its wholly owned subsidiary, Permex Petroleum US Corporation, acquired a 100% Working Interest and a 81.75% Net Revenue Interest in the Breedlove “B” Clearfork leases located in Martin County, Texas. The Company issued 25,000,000 common shares and 12,500,000 share purchase warrants as consideration for this acquisition. The Company valued the 25,000,000 common shares issued at a fair value of $2,468,750. The share purchase warrants were valued at $1,180,718 using the Black-Scholes option pricing model (assuming a risk-free interest rate of 1.51%, an expected life of 10-years, annualized volatility of 131.82% and a dividend rate of 0%). The warrants have an exercise price $0.16 per share (CAD$0.20) and are exercisable until October 1, 2031.
Dispositions
During the year ended September 30, 2021, the Company sold its interests in the Peavy leases together with reclamation obligations for $10,000 and recognized a loss of $604,687 from the sale. The Company also recognized a loss of $8,770 from the disposal of equipment.
| F-15 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 4. | NON-CURRENT ASSETS (cont’d…) |
Assets held for sale
During the year ended September 30, 2020, the Company initiated a plan to dispose of its interest in certain oil and gas leases. As a result, the carrying costs of the related assets and its associated decommissioning liabilities were included in a disposal group and classified as assets held for sale and liabilities held for sale, respectively, at September 30, 2020. The disposal group classified as held for sale were measured at the fair value less costs to sell and an impairment loss of $879,070 was recognized in the profit and loss during the year ended September 30, 2020. The Company believes the disposal group is not a separate major line of business; therefore, disclosure of discontinued operation is not being presented.
The recoverable amount of the disposal group as of September 30, 2020 is as follows.
| Assets held for sale | ||||
| Oil and gas properties | $ | 2,924,465 | ||
| Liabilities held for sale | ||||
| Decommissioning liabilities | $ | 1,801,221 | ||
During the year ended September 30, 2021, the Company sold its interest in the oil and gas leases classified in assets and liabilities held for sale for $1,123,244.
| 5. | DECOMMISSIONING OBLIGATIONS |
The total future decommissioning obligations are based on the Company’s net ownership in wells and facilities, estimated costs to reclaim and abandon the wells and facilities, and the estimated timing of the costs to be incurred in future periods. The total undiscounted amount of estimated cash flows required to settle the Company’s obligations is approximately $2,836,777 as at September 30, 2021 (2020 - $1,271,020) and expected to be incurred between 2031 to 2041. The estimated net present value of the decommissioning obligations was calculated using an inflation factor of 2.0% (2020 - 2.0%) and discounted using a risk-free rate of 2.02% (2020 - 1.93%) based on expected settlement date.
Changes to the decommissioning obligations are as follows:
| 2021 | 2020 | |||||||
| Decommissioning obligations, beginning of the year | $ | 792,814 | $ | 2,382,573 | ||||
| Obligations acquired | 784,418 | - | ||||||
| Obligations derecognized | (140,704 | ) | (116,192 | ) | ||||
| Change in estimates | 234,331 | - | ||||||
| Change in discount rate | (81,236 | ) | 295,152 | |||||
| Accretion expense | 11,722 | 45,371 | ||||||
| Reclassification to liabilities held for sale | - | (1,801,221 | ) | |||||
| Foreign exchange movement | 26,120 | (12,869 | ) | |||||
| $ | 1,627,465 | $ | 792,814 | |||||
| F-16 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 5. | DECOMMISSIONING OBLIGATIONS (cont’d…) |
During the year ended September 30, 2021, the Company derecognized $140,704 (2020 - $116,192) in decommissioning obligations as a result of an assignment of certain oil and gas interests. The decommissioning obligations were offset by the decommissioning provision of $127,510 (2020 - $105,777) and a gain of $13,194 was netted against the loss realized from the sale of properties (2020 - a gain of $10,415 realized).
| 6. | DEBT |
Convertible debentures
The Company issued a total of $150,000 (CAD$200,000) in convertible debentures to the CEO and a director of the Company on October 17, 2019 and February 21, 2020 for cash. The debentures are secured by an interest in all of the Company’s right, title, and interest in all of its oil and gas assets, have a maturity date of September 30, 2021 and February 20, 2022, and bear interest at a rate of 12% per annum, payable on maturity. The debentures are convertible at the holder’s option into units of the Company at $0.12 (CAD$0.15) per unit. Each unit will be comprised of one common share of the Company and one share purchase warrant; each warrant entitles the holder to acquire one additional common share for a period of three years at an exercise price of $0.16 (CAD$0.20).
During the year ended September 30, 2021 and 2020, the Company accrued interest of $9,480 and $13,991, respectively, and is included within amounts due to related party on the consolidated balance sheets. During the year ended September 30, 2021, the Company repaid $79,000 (CAD$100,000) of the convertible debenture together with accrued interest of $13,090.
Loan payable
In May 2020, the Company opened a Canada Emergency Business Account (“CEBA”) and received a loan of $30,000 (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 and not-for-profits to help them cover operating costs during the COVID-19 pandemic. The loan is unsecured and non-interest bearing with an original repayment deadline of December 31, 2022. In January 2022, the Canadian government extended the repayment deadline to December 31, 2023 in order for the loan to be considered for partial forgiveness of up to one-third of the balance. Any loans not repaid by December 31, 2023 convert to two-year term loans bearing interest at an annual rate of 5% starting January 1, 2024, with loans fully due by December 31, 2025.
| 7. | COMMITMENTS AND CONTINGENCIES |
Lease Liability
The Company has entered into office lease agreements for its office premises for terms ending in 2023. As of September 30, 2021, the Company’s lease had a weighted-average remaining term of 1.6 years. The undiscounted future lease payments as of September 30, 2021 are as follows:
| 2022 | $ | 55,402 | ||
| 2023 | 31,885 | |||
| $ | 87,287 |
| F-17 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 7. | COMMITMENTS AND CONTINGENCIES (cont’d…) |
Lease Liability (cont’d…)
The components of lease expense were as follows:
| 2021 | 2020 | |||||||
| Fixed lease expense | $ | 43,932 | $ | 20,962 | ||||
| Variable lease expense | 10,404 | 6,048 | ||||||
| Total | $ | 54,336 | $ | 27,010 | ||||
The following is a continuity schedule of lease liability:
| 2021 | 2020 | |||||||
| Balance, beginning of the year | $ | 53,128 | $ | - | ||||
| Addition | 57,357 | 66,432 | ||||||
| Interest expense | 9,812 | 7,233 | ||||||
| Lease payments | (43,932 | ) | (20,962 | ) | ||||
| Foreign exchange movement | 2,584 | 425 | ||||||
| Balance, end of the year | $ | 78,949 | $ | 53,128 | ||||
| Current liability | $ | 51,963 | $ | 21,202 | ||||
| Long-term liability | $ | 26,986 | $ | 31,926 | ||||
| 8. | RELATED PARTY TRANSACTIONS |
During the year ended September 30, 2020, the Company issued a total of $150,000 (CAD$200,000) in convertible debentures to the CEO and a director of the Company for cash (Note 6). During the year ended September 30, 2021, the Company repaid $79,000 (CAD$100,000) of the convertible debenture due to a director of the Company together with accrued interest of $13,090. As of September 30, 2021, $78,500 (CAD$100,000) of the debenture loan remained outstanding and the interest accrued on the loan was $15,176 (2020 - $14,104).
During the year ended September 30, 2021, the Company incurred management fees of $149,806 (2020 - $144,288) to a company controlled by the CEO of the Company. The Company considers this a related party transaction, as it relates to key management personnel and entities over which it has control or significant influence.
| F-18 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 9. | EQUITY |
Common stock
The Company has authorized an unlimited number of common shares with no par value. At September 30, 2021 and 2020, the Company had 66,180,364 and 40,024,114 common shares issued and outstanding, respectively. During the year ended September 30, 2021, the Company issued the following shares:
| a) | 1,156,250 common shares of the Company with a fair value of $54,313 pursuant to service agreements. | |
| b) | 25,000,000 common shares of the Company with a value of $2,468,750 pursuant to a property acquisition agreement (Note 4). |
There were no common shares issued during the year ended September 30, 2020.
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.
Stock option transactions are summarized as follows:
| Number of options | Weighted Average Exercise Price | |||||||
| Balance, September 30, 2019 | 2,540,189 | $ | 0.36 | |||||
| Granted | 300,000 | 0.04 | ||||||
| Cancelled | (500,000 | ) | 0.37 | |||||
| Balance, September 30, 2020 | 2,340,189 | $ | 0.31 | |||||
| Cancelled | (65,189 | ) | 0.40 | |||||
| Balance, September 30, 2021 | 2,275,000 | $ | 0.33 | |||||
| Exercisable at September 30, 2021 | 2,125,000 | $ | 0.35 | |||||
| Weighted average fair value of options granted during the year | $ | nil | (2020 - $0.03 | ) | ||||
The aggregate intrinsic value of options outstanding and exercisable as at September 30, 2021 was $nil (2020 - $nil).
| F-19 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 9. | EQUITY (cont’d…) |
Share-based payments (cont’d…)
The options outstanding as of September 30, 2021 equalled 2,275,000 shares, and have exercise prices in the range of $0.04 to $0.39 and a weighted average remaining contractual life of 6.60 years. The weighted average fair value of options granted during the year ended September 30, 2020 was $0.03. There were no options granted during the year ended September 30, 2021.
During the years ended September 30, 2021 and 2020, the Company recognized share-based payment expense of $2,870 and $4,175, respectively, for the portion of stock options that vested during the year. The following weighted average assumptions were used for the Black-Scholes valuation of stock options granted:
| 2021 | 2020 | |||||||
| Risk-free interest rate | - | 0.78 | % | |||||
| Expected life of options | - | 10 Years | ||||||
| Expected annualized volatility | - | 120 | % | |||||
| Dividend rate | - | Nil | ||||||
As at September 30, 2021, the following stock options were outstanding:
| Number of Options | Exercise Price | Expiry Date | ||||||
| 1,675,000 | $ | 0.39 | December 4, 2027 | |||||
| 300,000 | $ | 0.24 | November 1, 2028 | |||||
| 300,000 | $ | 0.04 | March 16, 2030 | |||||
| 2,275,000 | ||||||||
Warrants
Warrant transactions are summarized as follows:
| Number of Warrants | Weighted Average Exercise Price | |||||||
| Balance, September 30, 2019 and 2020 | 4,805,206 | $ | 0.21 | |||||
| Granted | 12,500,000 | 0.16 | ||||||
| Warrants expired | (4,805,206 | ) | 0.22 | |||||
| Balance, September 30, 2021 | 12,500,000 | $ | 0.16 | |||||
The 12,500,000 warrants outstanding at September 30, 2021 have an exercise price of $0.16 and expire on October 1, 2031.
| F-20 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 10. | LOSS PER SHARE |
The calculation of basic and diluted loss per share for the years ended September 30, 2021 and 2020 was based on the losses attributable to common shareholders. The following table sets forth the computation of basic and diluted loss per share:
| 2021 | 2020 | |||||||
| Net loss | $ | (1,245,057 | ) | $ | (1,249,202 | ) | ||
| Weighted average common shares outstanding | 40,737,470 | 40,024,114 | ||||||
| Basic and diluted loss per share | $ | (0.03 | ) | $ | (0.03 | ) | ||
As of September 30, 2021, $78,500 (CAD$100,000) of convertible debentures convertible into 666,667 common shares, 2,275,000 (2020 - 240,189) stock options and 12,500,000 (2020 - 4,805,206) warrants were excluded from the diluted weighted average number of common shares calculation as their effect would have been anti-dilutive.
| 11. | INCOME TAXES |
A reconciliation of income taxes at statutory rates with the reported taxes is as follows:
| 2021 | 2020 | |||||||
| Loss before income taxes | $ | (1,245,057 | ) | $ | (1,249,202 | ) | ||
| Expected income tax recovery at statutory rates | $ | (336,000 | ) | $ | (337,000 | ) | ||
| Change in statutory, foreign tax, foreign exchange rates and other | (26,000 | ) | (6,000 | ) | ||||
| Permanent differences | 1,000 | 2,000 | ||||||
| Adjustment to prior years provision versus statutory tax returns | (11,000 | ) | (13,000 | ) | ||||
| Unrecognized temporary differences | 372,000 | 354,000 | ||||||
| Deferred income tax recovery | $ | - | $ | - | ||||
The significant components of the Company’s deferred tax assets and liabilities are as follows:
| 2021 | 2020 | |||||||
| Non-capital losses available for future periods | $ | 780,000 | $ | 571,000 | ||||
| Property and equipment | (9,000 | ) | (204,000 | ) | ||||
| Financing fees | 38,000 | 70,000 | ||||||
| 809,000 | 437,000 | |||||||
| Unrecognized deferred income tax assets | (809,000 | ) | (437,000 | ) | ||||
| Net deferred income tax assets | $ | - | $ | - | ||||
The significant components of the Company’s temporary differences include financing fees and non-capital losses available for future periods. For the years ended September 30, 2021 and 2020, the Company had financing fees of $140,000 and $254,000, respectively, with expiration dates between 2041 and 2043. The Company also had non-capital losses available for future periods in both Canada and the United States. For the years ended September 30, 2021 and 2020, the Canada losses totaled $2,703,000 and $1,241,000, respectively, with expiration dates ranging from 2037 to 2041 and 2037 to 2040, respectively. The United States non-capital losses for the years ended September 30, 2021 and 2020 totaled $213,000 and $106,000, respectively, and had no expiration dates.
| F-21 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 12. | SEGMENTED INFORMATION |
Operating segments
The Company operates in a single reportable segment – the acquisition, development and production of oil and gas properties in the United States.
| 13. | EVENTS AFTER THE REPORTING PERIOD |
Subsequent to September 30, 2021, The Company
| i) | Completed a non-brokered private placement of 2,647,037 units at a price of $0.22 (CAD$0.27) per unit for gross proceeds of $571,760 (CAD$714,700). Each unit is comprised of one common share and one half of one share purchase warrant; each whole warrant entitles the holder to acquire one additional common share for a period of 24 months at an exercise price of $0.43 (CAD$0.54). $137,946 of the proceeds was allocated to the warrants. The Company paid $34,733 and issued 160,800 agent’s warrants as a finders’ fee. The finder’s warrants have the same terms as the warrants issued under the private placement. The finder’s warrants were valued at $24,543 using the Black-Scholes option pricing model (assuming a risk-free interest rate of 0.98%, an expected life of 2 year, annualized volatility of 153.02% and a dividend rate of 0%). The Company also incurred filing and other expenses of $800 in connection with the private placement. | |
| ii) | Completed a brokered private placement of 47,128,625 units at a price of $0.16 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 entitles the holder to acquire one additional common share for a period of 5 years at an exercise price of $0.21. $607,170 of the proceeds was allocated to the warrants. ThinkEquity LLC acted as sole placement agent for the private placement. In connection with the private placement, ThinkEquity received a cash commission of $754,058, broker warrants of 4,712,862 and expense reimbursement of $131,560. The broker’s warrants have the same terms as the warrants issued under the private placement. The broker’s warrants were valued at $858,429 using the Black-Scholes option pricing model (assuming a risk-free interest rate of 2.45%, an expected life of 5 year, annualized volatility of 134.66% and a dividend rate of 0%). The Company also incurred filing and other expenses of $140,475 in connection with the private placement. | |
| iii) | Granted stock options to directors and consultants of the Company to purchase 3,300,000 common shares at an exercise price of $0.19 (CAD$0.24) per share for a period of 10 years. | |
| iv) | Amended the employment with the CEO of the Company for an annual base salary of $250,000, with no specified term. The CEO is also eligible on an annual basis for a cash bonus of up to 100% of annual salary. The employment agreement may be terminated with a termination payment equal to three years of base salary and a bonus equal to 20% of the annual base salary. | |
| v) | Entered into an employment with the CFO of the Company for an annual base salary of $50,000, with no specified term. The CFO is also eligible on an annual basis for a cash bonus of up to 100% of annual salary. The employment agreement may be terminated with a termination payment equal to two months of base salary. |
| F-22 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 14. | SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED) |
Supplemental unaudited information regarding Permex’s oil and gas activities is presented in this note. All of Permex’s reserves are located within the U.S.
Costs Incurred in Oil and Gas Producing Activities
| 12 Months Ended | 12 Months Ended | |||||||
| September 30, 2021 | September 30, 2020 | |||||||
| Acquisition of proved properties | $ | 4,612,981 | $ | — | ||||
| Acquisition of unproved properties | — | — | ||||||
| Development costs | 162,498 | 254,299 | ||||||
| Exploration costs | — | — | ||||||
| Total costs incurred | $ | 4,775,479 | $ | 254,299 | ||||
Results of Operations from Oil and Gas Producing Activities
| 12 Months Ended | 12 Months Ended | |||||||
| September 30, 2021 | September 30, 2020 | |||||||
| Oil and gas revenues | $ | 84,625 | $ | 682,786 | ||||
| Production costs | (59,671 | ) | (557,624 | ) | ||||
| Exploration expenses | — | — | ||||||
| Depletion, depreciation and amortization | (52,439 | ) | (28,660 | ) | ||||
| Impairment of oil and gas properties | — | — | ||||||
| Result of oil and gas producing operations before income taxes | (27,485 | ) | 96,502 | |||||
| Provision for income taxes | — | — | ||||||
| Results of oil and gas producing activities | $ | (27,485 | ) | $ | 96,502 | |||
Proved Reserves
The Company’s proved oil and natural gas reserves have been estimated by the certified independent engineering firm, MKM Engineering. Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods when the estimates were made. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history; acquisitions of oil and natural gas properties; and changes in economic factors.
| F-23 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 14. | SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED) (cont’d…) |
Our proved reserves are summarized in the table below:
| Oil (Barrels) | Natural Gas (Mcf) | BOE (Barrels) | ||||||||||
| Proved developed and undeveloped reserves: | ||||||||||||
| September 30, 2019 | 3,992,240 | 498,180 | 4,075,270 | |||||||||
| Revisions(1) | 440,160 | 251,196 | 482,026 | |||||||||
| Discoveries and extensions | — | — | — | |||||||||
| Sale of reserves(2) | (709,800 | ) | — | (709,800 | ) | |||||||
| Production | (16,240 | ) | (9,196 | ) | (17,773 | ) | ||||||
| September 30, 2020 | 3,706,360 | 740,180 | 3,829,723 | |||||||||
| Revisions(3) | (88,263 | ) | 38,640 | (81,823 | ) | |||||||
| Purchase of proved reserves(4) | 5,408,560 | 2,859,590 | 5,885,158 | |||||||||
| Sale reserves(5) | (2,826,290 | ) | (618,650 | ) | (2,929,398 | ) | ||||||
| Production | (947 | ) | (1,410 | ) | (1,182 | ) | ||||||
| September 30, 2021 | 6,199,420 | 3,018,350 | 6,702,478 | |||||||||
| Proved developed reserves: | ||||||||||||
| September 30, 2019 | 921,410 | 104,000 | 938,743 | |||||||||
| September 30, 2020 | 549,390 | 82,430 | 563,128 | |||||||||
| September 30, 2021 | 587,450 | 411,910 | 656,102 | |||||||||
| Proved undeveloped reserves: | ||||||||||||
| September 30, 2019 | 3,070,830 | 394,180 | 3,136,527 | |||||||||
| September 30, 2020 | 3,156,970 | 657,750 | 3,266,595 | |||||||||
| September 30, 2021 | 5,611,970 | 2,606,440 | 6,046,377 | |||||||||
(1) Revisions in 2020 included 120,850 bbls additional proved undeveloped reserves due to economic conditions and approximately 373,000 bbls of oil and 242,000 mcf of natural gas added to the ODC Gaines County property due to two additional productive zones evaluated and included in proved reserves.
(2) During 2020, the Company sold their McMurtry-Loving property.
(3) Revisions in 2021 included 120,850 bbls in proved undeveloped reserves being classified as probable in the 2021 reserve report, net of other immaterial revisions in several properties.
(4) During 2021, the Company purchased 6,046 net acres in Martin County, Texas.
(5) During 2021, the Company sold ODC and Taylor properties.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of September 30, 2021 and September 30, 2020 in accordance with ASC 932, “Extractive Activities – Oil and Gas” which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.
Future cash inflows for the years ended September 30, 2021 and September 30, 2020 were estimated as specified by the SEC through calculation of an average price based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from October through September during each respective fiscal year. The resulting net cash flow are reduced to present value by applying a 10% discount factor.
| 12 Months Ended | ||||||||
| September 30, 2021 | September 30, 2020 | |||||||
| Future cash inflows | $ | 355,958,000 | $ | 150,694,000 | ||||
| Future production costs(1) | (69,683,000 | ) | (50,268,000 | ) | ||||
| Future development costs | (71,700,000 | ) | (26,263,000 | ) | ||||
| Future income tax expenses | (57,206,000 | ) | (19,689,000 | ) | ||||
| Future net cash flows | 157,369,000 | 54,474,000 | ||||||
| 10% annual discount for estimated timing of cash flows | (84,100,000 | ) | (33,677,000 | ) | ||||
| Standardized measure of discounted future net cash flows at the end of the fiscal year | $ | 73,269,000 | $ | 20,797,000 | ||||
| (1) | Production costs include crude oil and natural gas operations expense, production ad valorem taxes, transportation costs and G&A expense supporting the Company’s crude oil and natural gas operations. |
| F-24 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED SEPTEMBER 30, 2021 AND 2020
| 14. | SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED) (cont’d…) |
Average hydrocarbon prices are set forth in the table below.
| Average Price | Natural | |||||||
| Crude Oil (Bbl) | Gas (Mcf) | |||||||
| Year ended September 30, 2019 (1) | $ | 53.60 | $ | 2.51 | ||||
| Year ended September 30, 2020 (1) | $ | 40.30 | $ | 1.77 | ||||
| Year ended September 30, 2021 (1) | $ | 55.98 | $ | 2.95 | ||||
| (1) | Average prices were based on 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from October through September during each respective fiscal year. |
Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved crude oil and natural gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.
Sources of Changes in Discounted Future Net Cash Flows
Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves, as required by ASC 932, at fiscal year-end are set forth in the table below.
| 12 Months Ended | ||||||||
| September 30, 2021 | September 30, 2020 | |||||||
| Standardized measure of discounted future net cash flows at the beginning of the year | $ | 20,797,000 | $ | 40,833,000 | ||||
| Extensions, discoveries and improved recovery, less related costs | — | — | ||||||
| Sales of minerals in place | (62,682,000 | ) | (7,509,000 | ) | ||||
| Purchase of minerals in place | 125,927,000 | — | ||||||
| Revisions of previous quantity estimates | (1,751,000 | ) | 5,099,000 | |||||
| Net changes in prices and production costs | 32,573,000 | (21,863,000 | ) | |||||
| Accretion of discount | 1,498,000 | 3,416,000 | ||||||
| Sales of oil produced, net of production costs | 13,000 | (125,000 | ) | |||||
| Changes in future development costs | (21,339,000 | ) | (919,000 | ) | ||||
| Changes in timing of future production | (2,580,000 | ) | (5,562,000 | ) | ||||
| Net changes in income taxes | (19,187,000 | ) | 7,427,000 | |||||
| Standardized measure of discounted future net cash flows at the end of the year | $ | 73,269,000 | $ | 20,797,000 | ||||
| F-25 |
PERMEX PETROLEUM CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
| March 31, 2022 | September 30, 2021 | |||||||
| ASSETS | ||||||||
| Current assets | ||||||||
| Cash | $ | 6,727,758 | $ | 25,806 | ||||
| Trade and other receivables | 146,403 | 12,984 | ||||||
| Prepaid expenses and deposits | 81,236 | 46,151 | ||||||
| 6,955,397 | 84,941 | |||||||
| Non-current assets | ||||||||
| Reclamation deposits | 145,000 | 144,847 | ||||||
| Property and equipment | 7,967,249 | 7,846,145 | ||||||
| Right of use asset | 49,736 | 72,539 | ||||||
| Total assets | $ | 15,117,382 | $ | 8,148,472 | ||||
| LIABILITIES AND EQUITY | ||||||||
| Current liabilities | ||||||||
| Trade and other payables | $ | 581,772 | $ | 402,979 | ||||
| Amounts due to related party | 2,290 | 16,628 | ||||||
| Convertible debentures | 80,000 | 78,500 | ||||||
| Lease liability – current portion | 47,559 | 51,963 | ||||||
| 711,621 | 550,070 | |||||||
| Non-current liabilities | ||||||||
| Decommissioning obligations | 1,655,428 | 1,627,465 | ||||||
| Lease liability | 8,414 | 26,986 | ||||||
| Loan payable | 32,000 | 31,400 | ||||||
| Total liabilities | 2,407,463 | 2,235,921 | ||||||
| Equity | ||||||||
| Common stock, no par value per share; unlimited shares authorized, | ||||||||
| 115,956,026 and 66,180,364 shares issued and outstanding | ||||||||
| as of March 31, 2022 and September 30, 2021, respectively. | 14,399,373 | 8,976,747 | ||||||
| Share subscription proceeds | 30,456 | 30,456 | ||||||
| Reserves | 4,585,413 | 2,352,649 | ||||||
| Accumulated other comprehensive loss | (18,845 | ) | (128,532 | ) | ||||
| Deficit | (6,286,478 | ) | (5,318,769 | ) | ||||
| Total equity | 12,709,919 | 5,912,551 | ||||||
| Total liabilities and equity | $ | 15,117,382 | $ | 8,148,472 | ||||
The financial statements were authorized for issue by the board of directors on July 14, 2022 and were signed on its behalf by:
| “Mehran Ehsan” | Director | “Gregory Montgomery” | Director |
The accompanying notes are an integral part of these condensed interim consolidated financial statements.
| F-26 |
PERMEX PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF LOSS AND COMPREHENSIVE LOSS
(UNAUDITED)
| Three
Months Ended March 31, 2022 | Three
Months Ended March 31, 2021 | Six
Months Ended March 31, 2022 | Six
Months Ended March 31, 2021 | |||||||||||||
| Revenue | ||||||||||||||||
| Oil and gas sales | $ | 228,497 | $ | 40 | $ | 318,487 | $ | 3,094 | ||||||||
| Royalty income | 13,389 | - | 29,848 | - | ||||||||||||
| Total revenue | 241,886 | 40 | 348,335 | 3,094 | ||||||||||||
| Expenses | ||||||||||||||||
| Producing | 115,000 | 9,949 | 196,879 | 10,213 | ||||||||||||
| Accounting and audit | 51,280 | 18,397 | 65,480 | 29,947 | ||||||||||||
| Accretion on decommissioning obligations | 8,223 | 2,931 | 16,476 | 5,805 | ||||||||||||
| Consulting | 3,151 | 10,095 | 16,773 | 13,903 | ||||||||||||
| Depletion and depreciation | 56,884 | 2,077 | 88,895 | 9,238 | ||||||||||||
| Filing and transfer agent | 13,856 | 27,924 | 39,825 | 34,360 | ||||||||||||
| Interest | 1,286 | 5,110 | 3,688 | 9,768 | ||||||||||||
| Investor relations | 18,266 | 1,351 | 41,733 | 2,406 | ||||||||||||
| Legal fees | 18,435 | - | 23,826 | 670 | ||||||||||||
| Management fees | 59,393 | 37,513 | 109,773 | 75,116 | ||||||||||||
| Marketing and promotion | 18,366 | 12,257 | 48,818 | 20,654 | ||||||||||||
| Office and general | 10,188 | 6,024 | 30,223 | 10,658 | ||||||||||||
| Rent | 18,434 | 10,471 | 33,518 | 20,136 | ||||||||||||
| Share-based payments | (2,649 | ) | 915 | 604,676 | 1,915 | |||||||||||
| Travel | 1,119 | 453 | 4,918 | 872 | ||||||||||||
| Total operating expenses | (391,232 | ) | (145,467 | ) | (1,325,501 | ) | (245,660 | ) | ||||||||
| Operating loss | (149,346 | ) | (145,427 | ) | (977,166 | ) | (242,566 | ) | ||||||||
| Foreign exchange loss | (13,081 | ) | (10,476 | ) | (8,135 | ) | (27,152 | ) | ||||||||
| Forfeiture of reclamation deposit | - | (50,483 | ) | - | (50,483 | ) | ||||||||||
| Other income | 17,483 | 2,645 | 17,592 | 5,128 | ||||||||||||
| Settlement of trade payables | - | 7,718 | - | 7,718 | ||||||||||||
| 4,402 | (50,596 | ) | 9,457 | (64,789 | ) | |||||||||||
| Net loss | (144,944 | ) | (196,023 | ) | (967,709 | ) | (307,356 | ) | ||||||||
| Other comprehensive income | ||||||||||||||||
| Foreign currency translation adjustment | 82,825 | 40,389 | 109,687 | 196,182 | ||||||||||||
| Comprehensive loss | $ | (62,119 | ) | $ | (155,634 | ) | $ | (858,022 | ) | $ | (111,173 | ) | ||||
| Basic and diluted loss per common share | $ | (0.00 | ) | $ | (0.00 | ) | $ | (0.01 | ) | $ | (0.01 | ) | ||||
The accompanying notes are an integral part of these condensed interim consolidated financial statements.
| F-27 |
PERMEX PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(UNAUDITED)
Three months ended March 31
| Number of Shares | Share capital | Reserves | Share subscription proceeds | Accumulated other comprehensive loss | Deficit | Total equity | ||||||||||||||||||||||
| Balance, December 31, 2021 | 68,827,401 | $ | 9,350,485 | $ | 3,122,463 | $ | 30,456 | $ | (101,670 | ) | $ | (6,141,525 | ) | $ | 6,260,209 | |||||||||||||
| Private placements | 47,128,625 | 6,933,410 | 607,170 | - | - | - | 7,540,580 | |||||||||||||||||||||
| Share issuance costs | - | (1,884,522 | ) | 858,429 | - | - | - | (1,026,093 | ) | |||||||||||||||||||
| Share-based payments | - | - | (2,649 | ) | - | - | - | (2,649 | ) | |||||||||||||||||||
| Net loss | - | - | - | - | - | (144,953 | ) | (144,953 | ) | |||||||||||||||||||
| Other comprehensive income | - | - | - | - | 82,825 | - | 82,825 | |||||||||||||||||||||
| Balance, March 31, 2022 | 115,956,026 | $ | 14,399,373 | $ | 4,585,413 | $ | 30,456 | $ | (18,845 | ) | $ | (6,286,478 | ) | $ | 12,709,919 | |||||||||||||
| Number of Shares | Share capital | Reserves | Share subscription proceeds | Accumulated other comprehensive loss | Deficit | Total equity | ||||||||||||||||||||||
| Balance, December 31, 2020 | 40,680,364 | $ | 6,473,147 | $ | 1,193,123 | $ | 30,465 | $ | (114,074 | ) | $ | (4,208,107 | ) | $ | 3,374,545 | |||||||||||||
| Share-based payments | - | - | 915 | - | - | - | 915 | |||||||||||||||||||||
| Net loss | - | - | - | - | - | (196,023 | ) | (196,023 | ) | |||||||||||||||||||
| Other comprehensive income | - | - | - | - | 40,389 | - | 40,389 | |||||||||||||||||||||
| Balance, March 31, 2021 | 40,680,364 | $ | 6,473,147 | $ | 1,194,038 | $ | 30,456 | $ | (73,685 | ) | $ | (4,404,130 | ) | $ | 3,219,826 | |||||||||||||
The accompanying notes are an integral part of these condensed interim consolidated financial statements.
| F-28 |
PERMEX PETROLEUM CORPORATION
CONDENSED INTERIM CONSOLIDATED STATEMENTS OF EQUITY (cont’d…)
(UNAUDITED)
Six months ended March 31
| Number of Shares | Share capital | Reserves | Share subscription proceeds | Accumulated other comprehensive loss | Deficit | Total equity | ||||||||||||||||||||||
| Balance, September 30, 2021 | 66,180,364 | $ | 8,976,747 | $ | 2,352,649 | $ | 30,456 | $ | (128,532 | ) | $ | (5,318,769 | ) | $ | 5,912,551 | |||||||||||||
| Private placements | 49,775,662 | 7,367,224 | 745,116 | - | - | - | 8,112,340 | |||||||||||||||||||||
| Share issuance costs | - | (1,944,598 | ) | 882,972 | - | - | - | (1,061,626 | ) | |||||||||||||||||||
| Share-based payments | - | - | 604,676 | - | - | - | 604,676 | |||||||||||||||||||||
| Net loss | - | - | - | - | - | (967,709 | ) | (967,709 | ) | |||||||||||||||||||
| Other comprehensive income | - | - | - | - | 109,687 | - | 109,687 | |||||||||||||||||||||
| Balance, March 31, 2022 | 115,956,026 | $ | 14,399,373 | $ | 4,585,413 | $ | 30,456 | $ | (18,845 | ) | $ | (6,286,478 | ) | $ | 12,709,919 | |||||||||||||
| Number of Shares | Share capital | Reserves | Share subscription proceeds | Accumulated other comprehensive loss | Deficit | Total equity | ||||||||||||||||||||||
| Balance, September 30, 2020 | 40,024,114 | $ | 6,453,039 | $ | 1,192,123 | $ | 30,456 | $ | (270,235 | ) | $ | (4,096,774 | ) | $ | 3,308,609 | |||||||||||||
| Shares issued for services | 656,250 | 20,108 | - | - | - | - | 20,108 | |||||||||||||||||||||
| Share-based payments | - | - | 1,915 | - | - | - | 1,915 | |||||||||||||||||||||
| Net loss | - | - | - | - | - | (307,356 | ) | (307,356 | ) | |||||||||||||||||||
| Other comprehensive income | - | - | - | - | 196,550 | - | 196,550 | |||||||||||||||||||||
| Balance, March 31, 2021 | 40,680,364 | $ | 6,473,147 | $ | 1,194,038 | $ | 30,456 | $ | (73,685 | ) | $ | (4,404,130 | ) | $ | 3,219,826 | |||||||||||||
The accompanying notes are an integral part of these condensed interim consolidated financial statements.
| F-29 |
PERMEX PETROLEUM CORPORATION
CONDENSED INTERIM CONSOLIDATED STATEMENTS OF CASH FLOWS
SIX MONTHS ENDED MARCH 31
(UNAUDITED)
| 2022 | 2021 | |||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||
| Net loss | $ | (967,709 | ) | $ | (307,356 | ) | ||
| Adjustments to reconcile net loss to net cash from operating activities: | ||||||||
| Accretion on decommissioning obligations | 16,476 | 5,805 | ||||||
| Depletion and depreciation | 88,895 | 9,238 | ||||||
| Foreign exchange loss | 9,873 | 87,814 | ||||||
| Forfeiture of reclamation bond | - | 49,530 | ||||||
| Interest | 3,688 | 8,642 | ||||||
| Settlement of trade payables | - | (7,572 | ) | |||||
| Share-based payments | 604,676 | 1,915 | ||||||
| Shares issued for services | - | 16,696 | ||||||
| Trade and other receivables | (133,289 | ) | 43,009 | |||||
| Prepaid expenses and deposits | (33,877 | ) | (19,013 | ) | ||||
| Trade and other payables | 171,583 | (286,934 | ) | |||||
| Amounts due to related parties | (18,960 | ) | (162,477 | ) | ||||
| Right of use asset and lease liability | 27,513 | 17,917 | ||||||
| Net cash used in operating activities | (231,131 | ) | (542,786 | ) | ||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||
| Capital expenditures on property and equipment | (90,657 | ) | (195,419 | ) | ||||
| Proceeds from sale of oil and gas interests | - | 1,123,244 | ||||||
| Net cash provided by (used in) investing activities | (90,657 | ) | 927,825 | |||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||
| Proceeds from issuance of share capital | 8,112,340 | - | ||||||
| Share issuance costs | (1,061,626 | ) | - | |||||
| Convertible debentures | - | (2,730 | ) | |||||
| Loan from related party | 800 | (78,000 | ) | |||||
| Lease payments | (27,774 | ) | (16,389 | ) | ||||
| Net cash provided by (used in) financing activities | 7,023,740 | (97,119 | ) | |||||
| Change in cash during the period | 6,701,952 | 287,920 | ||||||
| Cash, beginning of the period | 25,806 | 5,517 | ||||||
| Cash, end of the period | $ | 6,727,758 | $ | 293,437 | ||||
| Supplemental disclosures of non-cash investing and financing activities: | ||||||||
| Trade and other payables related to property and equipment | $ | 82,054 | $ | 76,855 | ||||
| Share issued for services included in prepaid | - | 3,413 | ||||||
| Share purchase warrants issued in connection with private placement | 1,628,088 | - | ||||||
| Supplemental cash flow disclosures: | ||||||||
| Interest paid | 18,960 | - | ||||||
The accompanying notes are an integral part of these condensed interim consolidated financial statements.
| F-30 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SIX MONTHS ENDED MARCH 31, 2022
(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 500, 666 Burrard Street, Vancouver, British Columbia, Canada, V6C 2X8 and its US office at Suite 700, 100 Crescent Court, Dallas, Texas, 75201. Its registered office is located at 10th 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”.
| 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, 2022 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 notes thereto included in the Company’s Form S-1 for the fiscal year ended September 30, 2021 filed with the SEC on June 24, 2022. There have been no material changes in the Company’s significant accounting policies from those that were disclosed in the fiscal 2021 financial statements, except as noted below.
Principles of Consolidation
The accompanying consolidated financial statements include the assets, liabilities, revenue and expenses of all wholly-owned subsidiaries. All intercompany balances and transactions have been eliminated.
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) amounts subject to allowances and returns; (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 decommissioning liabilities; (iv) income taxes receivable or payable; (v) the useful lives of assets for the purposes of depreciation; (vi) petroleum and natural gas reserves; 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.
| F-31 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SIX MONTHS ENDED MARCH 31, 2022
(UNAUDITED)
| 2. | Significant Accounting Policies (cont’d…) |
Foreign Currency
These consolidated financial statements include the accounts of the Company and its wholly owned subsidiary, Permex Petroleum US Corporation. These consolidated financial statements are presented in United States dollars (“USD”). The functional currency of the Company is the Canadian dollar (“CAD”). The functional currency for the subsidiary of the Company is the United States dollar (“USD”).
Recently adopted accounting pronouncement
None.
| 3. | CONCENTRATION OF CREDIT RISK |
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.
During the six months ended March 31, 2022, the Company generated 75% of total revenue from one customer (2021 - 100%). As at March 31, 2022, one customer represented $55,255 (40%) of the trade receivable balance (September 30, 2021 - $2,927 (26%)). It is in management’s opinion that the Company is not exposed to significant credit risk.
| 4. | NON-CURRENT ASSETS |
The Company is engaged in the exploration for, and the development of, petroleum and natural gas projects in the United States. The Company holds 100% working interests and 71.9% to 81.75% net revenue interests and certain royalty interests in the various oil and gas properties located in Texas and New Mexico.
Reclamation bonds
As of March 31, 2022, the Company held reclamation bonds of $145,000 (September 30, 2021 - $144,847), which are expected to be released after all reclamation work has been completed with regard to its oil and natural gas interests. During the year ended September 30, 2021, the Company wrote off US$50,165 of reclamation deposit forfeited by the Texas State government due to violation on a previous owned property.
Property and equipment
Property and equipment consisted of the following:
| March 31, 2022 | September 30, 2021 | |||||||
| Oil and natural gas properties, at cost | $ | 8,166,294 | $ | 7,954,807 | ||||
| Less: accumulated depreciation | (199,045 | ) | (108,662 | ) | ||||
| Property, net | $ | 7,967,249 | $ | 7,846,145 | ||||
Depreciation expense was $88,895 and $9,238 for the six month periods ended March 31, 2022 and 2021, respectively.
| F-32 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SIX MONTHS ENDED MARCH 31, 2022
(UNAUDITED)
| 4. | NON-CURRENT ASSETS (cont’d…) |
Acquisition
During the year ended September 30, 2021, the Company, through its wholly owned subsidiary, Permex Petroleum US Corporation, acquired a 100% Working Interest and a 81.75% Net Revenue Interest in the Breedlove “B” Clearfork leases located in Martin County, Texas. The Company issued 25,000,000 common shares and 12,500,000 share purchase warrants as consideration for this acquisition. The Company valued the 25,000,000 common shares issued at a fair value of $2,468,750. The share purchase warrants were valued at $1,180,718 using the Black-Scholes option pricing model (assuming a risk-free interest rate of 1.51%, an expected life of 10-years, annualized volatility of 131.82% and a dividend rate of 0%). The warrants have an exercise price $0.16 per share (CAD$0.20) and are exercisable until October 1, 2031.
| 5. | DECOMMISSIONING OBLIGATIONS |
The total future decommissioning obligations are based on the Company’s net ownership in wells and facilities, estimated costs to reclaim and abandon the wells and facilities, and the estimated timing of the costs to be incurred in future periods. The total undiscounted amount of estimated cash flows required to settle the Company’s obligations is approximately $2,245,388 as at March 31, 2022 (September 30, 2021 - $2,836,777) and expected to be incurred between 2031 to 2041. The estimated net present value of the decommissioning obligations was calculated using an inflation factor of 2.0% (2020 - 2.0%) and discounted using a risk-free rate of 2.02% (2020 - 1.93%) based on expected settlement date.
Changes to the decommissioning obligations are as follows:
| March 31, 2022 | September 30, 2021 | |||||||
| Decommissioning obligations, beginning of the year | $ | 1,627,465 | $ | 792,814 | ||||
| Obligations acquired | - | 784,418 | ||||||
| Obligations derecognized | - | (140,704 | ) | |||||
| Change in estimates | - | 234,331 | ||||||
| Change in discount rate | - | (81,236 | ) | |||||
| Accretion expense | 16,476 | 11,722 | ||||||
| Foreign exchange movement | 11,487 | 26,120 | ||||||
| $ | 1,655,428 | $ | 1,627,465 | |||||
During the year ended September 30, 2021, the Company derecognized $140,704 in decommissioning obligations as a result of an assignment of certain oil and gas interests. The decommissioning obligations were offset by the decommissioning provision of $127,510 (2020 - $105,777) and a gain of $13,194 was netted against the loss realized from the sale of properties.
| F-33 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SIX MONTHS ENDED MARCH 31, 2022
(UNAUDITED)
| 6. | DEBT |
Convertible debentures
The Company issued a total of $157,000 (CAD$200,000) in convertible debentures to the CEO and a director of the Company on October 17, 2019 and February 21, 2020 for cash. The debentures are secured by an interest in all of the Company’s right, title, and interest in all of its oil and gas assets, have a maturity date of September 30, 2021 and February 20, 2022, and bear interest at a rate of 12% per annum, payable on maturity. The debentures are convertible at the holder’s option into units of the Company at $0.12 (CAD$0.15) per unit. Each unit will be comprised of one common share of the Company and one share purchase warrant; each warrant entitles the holder to acquire one additional common share for a period of three years at an exercise price of $0.16 (CAD$0.20). As of March 31, 2022, $80,000 (CAD$100,000) (September 30, 2021 - $78,500) of debenture loan remained outstanding and the interest accrued on the loan was $nil (September 30, 2021 - $15,176).
During the six months ended March 31, 2022 and 2021, the Company recorded interest of $3,688 and $9,768, respectively, and is included within amounts due to related party on the consolidated balance sheets. During the year ended September 30, 2021, the Company repaid $79,000 (CAD$100,000) of the convertible debenture together with accrued interest of $13,090. During the six months ended March 31, 2022, the Company paid interest of $18,960 (2020 - $13,090) accrued on the debentures.
Loan payable
In May 2020, the Company opened a Canada Emergency Business Account (“CEBA”) and received a loan of $32,000 (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 and not-for-profits to help them cover operating costs during the COVID-19 pandemic. The loan is unsecured and non-interest bearing with an original repayment deadline of December 31, 2022. In January 2022, the Canadian government extended the repayment deadline to December 31, 2023 in order for the loan to be considered for partial forgiveness of up to one-third of the balance. Any loans not repaid by December 31, 2023 convert to two-year term loans bearing interest at an annual rate of 5% starting January 1, 2024, with loans fully due by December 31, 2025.
| 7. | COMMITMENTS AND CONTINGENCIES |
Lease Liability
The Company has entered into office lease agreements for its office premises for terms ending in 2023. As of March 31, 2022, the Company’s lease had a weighted-average remaining term of 1.16 years. The undiscounted future lease payments as of March 31, 2022 are as follows:
| 2022 | $ | 27,921 | ||
| 2023 | 32,288 | |||
| $ | 60,209 |
| F-34 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SIX MONTHS ENDED MARCH 31, 2022
(UNAUDITED)
| 7. | COMMITMENTS AND CONTINGENCIES (cont’d…) |
The components of lease expense the six month periods ended March 31 were as follows:
| 2022 | 2021 | |||||||
| Fixed lease expense | $ | 27,774 | $ | 16,389 | ||||
| Variable lease expense | 5,744 | 3,747 | ||||||
| Total | $ | 33,518 | $ | 20,136 | ||||
The following is a continuity schedule of the lease liability:
| March 31, 2022 | September 30, 2021 | |||||||
| Balance, beginning of the year | $ | 78,949 | $ | 53,128 | ||||
| Addition | - | 57,357 | ||||||
| Interest expense | 4,169 | 9,812 | ||||||
| Lease payments | (27,774 | ) | (43,932 | ) | ||||
| Foreign exchange movement | 629 | 2,584 | ||||||
| Balance, end of the year | $ | 55,973 | $ | 78,949 | ||||
| Current liability | $ | 47,559 | $ | 51,963 | ||||
| Long-term liability | $ | 8,414 | $ | 26,986 | ||||
| 8. | RELATED PARTY TRANSACTIONS |
During the year ended September 30, 2020, the Company issued a total of $157,000 (CAD$200,000) in convertible debentures to the CEO and a director of the Company for cash. During the year ended September 30, 2021, the Company repaid $79,000 (CAD$100,000) of the convertible debenture due to a director of the Company together with accrued interest of $13,090. As of March 31, 2022, $80,000 (CAD$100,000) (September 30, 2021 - $78,500) of debenture loan remained outstanding and the interest accrued on the loan was $nil (September 30, 2021 - $15,176).
During the six months ended March 31, 2022, the Company incurred management fees of $109,773 (2021 - $75,116) to a company controlled by the CEO of the Company. The Company considers this a related party transaction, as it relates to key management personnel and entities over which it has control or significant influence.
Subsequent to March 31, 2022, the Company amended the employment with the CEO of the Company for an annual base salary of $250,000, with no specified term. The CEO is also eligible on an annual basis for a cash bonus of up to 100% of annual salary. The employment agreement may be terminated with a termination payment equal to three years of base salary and a bonus equal to 20% of the annual base salary.
Subsequent to March 31, 2022, the Company entered into an employment with the CFO of the Company for an annual base salary of $50,000, with no specified term. The CFO is also eligible on an annual basis for a cash bonus of up to 100% of annual salary. The employment agreement may be terminated with a termination payment equal to two months of base salary.
| F-35 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SIX MONTHS ENDED MARCH 31, 2022
(UNAUDITED)
| 9. | EQUITY |
Common stock
The Company has authorized an unlimited number of common shares with no par value. At March 31, 2022 and September 30, 2021, the Company had 115,956,026 and 66,180,364 common shares issued and outstanding, respectively.
During the six months ended March 31, 2022, the Company:
| a) | Completed a non-brokered private placement of 2,647,037 units at a price of $0.22 (CAD$0.27) per unit for gross proceeds of $571,760 (CAD$714,700). Each unit is comprised of one common share and one half of one share purchase warrant; each whole warrant entitles the holder to acquire one additional common share for a period of 24 months at an exercise price of $0.43 (CAD$0.54). $137,946 of the proceeds was allocated to the warrants. The Company paid $34,733 and issued 160,800 agent’s warrants as a finders’ fee. The finder’s warrants have the same terms as the warrants issued under the private placement. The finder’s warrants were valued at $24,543 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%). The Company also incurred filing and other expenses of $800 in connection with the private placement. | |
| b) | Completed a brokered private placement of 47,128,625 units at a price of $0.16 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 entitles the holder to acquire one additional common share for a period of 5 years at an exercise price of $0.21. $607,170 of the proceeds was allocated to the warrants. ThinkEquity LLC acted as sole placement agent for the private placement. In connection with the private placement, ThinkEquity received a cash commission of $754,058, 4,712,863 broker warrants and expense reimbursement of $131,560. The broker’s warrants have the same terms as the warrants issued under the private placement. The broker’s warrants were valued at $858,429 using the Black-Scholes option pricing model (assuming a risk-free interest rate of 2.45%, an expected life of 5 years, annualized volatility of 134.66% and a dividend rate of 0%). The Company also incurred filing and other expenses of $140,475 in connection with the private placement. |
During the year ended September 30, 2021, the Company:
| a) | Issued 1,156,250 common shares of the Company with a fair value of $54,313 pursuant to service agreements. | |
| b) | Issued 25,000,000 common shares of the Company with a value of $2,468,750 pursuant to a property acquisition agreement. |
| F-36 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SIX MONTHS ENDED MARCH 31, 2022
(UNAUDITED)
| 9. | EQUITY (cont’d…) |
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.
Stock option transactions are summarized as follows:
Number of options | Weighted Average Exercise Price | |||||||
| Balance, September 30, 2020 | 2,340,189 | $ | 0.31 | |||||
| Cancelled | (65,189 | ) | 0.40 | |||||
| Balance, September 30, 2021 | 2,275,000 | $ | 0.33 | |||||
| Granted | 3,300,000 | 0.19 | ||||||
| Balance, March 31, 2022 | 5,575,000 | $ | 0.25 | |||||
| Exercisable at March 31, 2022 | 5,500,000 | $ | 0.25 | |||||
| Weighted average fair value of options granted | $ | 0.19 | (2021 - $nil) | |||||
The aggregate intrinsic value of options outstanding and exercisable as at March 31, 2022 was $nil (2021 - $nil).
The options outstanding as of March 31, 2022 equaled 5,575,000 shares, and have exercise prices in the range of $0.04 to $0.40 and a weighted average remaining contractual life of 8.13 years. The weighted average fair value of options granted during the six months ended March 31, 2022 was $0.19. There were no options granted during the year ended September 30, 2021.
During the six month periods ended March 31, 2022 and 2021, the Company recognized share-based payment expense of $604,676 and $1,915, respectively, for the portion of stock options that vested during the period. The following weighted average assumptions were used for the Black-Scholes valuation of stock options granted:
| 2022 | 2021 | |||||||
| Risk-free interest rate | 1.50 | % | - | |||||
| Expected life of options | 10 Years | - | ||||||
| Expected annualized volatility | 131 | % | - | |||||
| Dividend rate | Nil | - | ||||||
| F-37 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SIX MONTHS ENDED MARCH 31, 2022
(UNAUDITED)
| 9. | EQUITY (cont’d…) |
Share-based payments (cont’d…)
As at March 31, 2022, the following stock options were outstanding:
Number of Options | Exercise Price | Expiry Date | |||||
| 1,675,000 | $ | 0.40 | December 4, 2027 | ||||
| 300,000 | $ | 0.24 | November 1, 2028 | ||||
| 300,000 | $ | 0.04 | March 16, 2030 | ||||
| 3,300,000 | $ | 0.19 | October 6, 2031 | ||||
| 5,575,000 | |||||||
Warrants
Warrants are measured at fair value on the date of the grant as determined using the Black-Scholes option pricing model.
Warrant transactions are summarized as follows:
| Number of Warrants | Weighted Average Exercise Price | |||||||
| Balance, September 30, 2020 | 4,805,206 | $ | 0.21 | |||||
| Granted | 12,500,000 | 0.16 | ||||||
| Warrants expired | (4,805,206 | ) | 0.22 | |||||
| Balance, September 30, 2021 | 12,500,000 | $ | 0.16 | |||||
| Granted | 53,325,806 | 0.22 | ||||||
| Balance, March 31, 2022 | 65,825,806 | $ | 0.21 | |||||
As at March 31, 2022, the following warrants were outstanding:
Number of Options | Exercise Price | Expiry Date | |||||
| 1,484,318 | $ | 0.43 | November 4, 2023 | ||||
| 51,841,488 | $ | 0.21 | March 29, 2027 | ||||
| 12,500,000 | $ | 0.16 | October 1, 2031 | ||||
| 65,825,806 | |||||||
| F-38 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SIX MONTHS ENDED MARCH 31, 2022
(UNAUDITED)
| 10. | LOSS PER SHARE |
The calculation of basic and diluted loss per share for the six month periods ended March 31, 2022 and 2021 was based on the losses attributable to common shareholders. The following table sets forth the computation of basic and diluted loss per share:
| 2022 | 2021 | |||||||
| Net loss | $ | (967,709 | ) | $ | (307,356 | ) | ||
| Weighted average common shares outstanding | 69,078,031 | 40,503,681 | ||||||
| Basic and diluted loss per share | $ | (0.01 | ) | $ | (0.01 | ) | ||
As of March 31, 2022, $80,000 (CAD$100,000) of convertible debentures convertible into 666,667 common shares, 5,575,000 (2021 - 2,340,189) stock options and 65,825,806 (2021 - 4,805,206) warrants were excluded from the diluted weighted average number of common shares calculation as their effect would have been anti-dilutive.
| 11. | SEGMENTED INFORMATION |
Operating segments
The Company operates in a single reportable segment – the acquisition, development and production of oil and gas properties in the United States.
| F-39 |
98,970,113 Common Shares
Permex Petroleum Corporation
| PROSPECTUS |
August 12, 2022
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