UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
| ☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Quarterly Period Ended June 30,March 31, 20222023
OR
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 333-265883001-41558
Permex Petroleum Corporation
(Exact name of registrant as specified in its charter)
| British Columbia, Canada | 98-1384682 | |
| (State or other jurisdiction of | (I.R.S. Employer | |
| incorporation or organization) | Identification No.) | |
| Dallas, Texas | ||
| (Address of principal executive offices) | (Zip Code) |
(214)(469) 459-2782804-1306
(Registrant’s telephone number, including area code)
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act: None
Indicate by checkmark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☐ No ☒ No ☐
Indicate by checkmark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company. or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large Accelerated Filer ☐ | Accelerated Filer ☐ | |
| Non-accelerated Filer ☒ | Smaller Reporting Company ☒ | |
| Emerging Growth Company ☒ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
As of August 29, 2022,May 15, 2023, there were common shares of the registrant issued and outstanding.
PERMEX PETROLEUM CORPORATION
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2022MARCH 31, 2023
TABLE OF CONTENTS
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EXPLANATORY NOTE
Unless otherwise indicated or the context otherwise requires, all references in this Quarterly Report on Form 10-Q (this “Report”) to “we,” “us,” “our,” “Permex,” and the “Company” are to Permex Petroleum Corporation., a corporation existing under the laws of the Province of British Columbia, Canada, and our wholly-owned subsidiary.
Unless otherwise indicated in this Report, natural gas volumes are stated at the legal pressure base of the state or geographic area in which the reserves are located at 60 degrees Fahrenheit. Crude oil and natural gas equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids.
The following definitions shall apply to the technical terms used in this Report.
Terms used to describe quantities of crude oil and natural gas:
“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGLs.
“Boe.” A barrel of oil equivalent and is a standard convention used to express crude oil, NGL and natural gas volumes on a comparable crude oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil or NGL.
“MBoe” One thousand barrels of oil equivalent.
“MBbl.” One thousand barrels of crude oil, condensate or NGLs.
“Mcf.” One thousand cubic feet of natural gas.
“NGLs.” Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.
Terms used to describe our interests in wells and acreage:
“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil, NGLs, and/or natural gas.
“Developed acreage.” Acreage consisting of leased acres spaced or assignable to productive wells. Acreage included in spacing units of infill wells is classified as developed acreage at the time production commences from the initial well in the spacing unit. As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.
“Development well.” A well drilled within the proved area of a crude oil, NGL, or natural gas reservoir to the depth of a stratigraphic horizon (rock layer or formation) known to be productive for the purpose of extracting proved crude oil, NGL, or natural gas reserves.
“Differential.” The difference between a benchmark price of crude oil and natural gas, such as the NYMEX crude oil spot price, and the wellhead price received.
“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.
“Gross acres or Gross wells.” The total acres or wells, as the case may be, in which a working interest is owned.
“Held by operations.” A provision in an oil and gas lease that extends the stated term of the lease as long as drilling operations are ongoing on the property.
“Held by production” or “HBP” A provision in an oil and gas lease that extends the stated term of the lease as long as the property produces a minimum quantity of crude oil, NGLs, and natural gas.
“Hydraulic fracturing.” The technique of improving a well’s production by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.
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“Infill well.” A subsequent well drilled in an established spacing unit of an already established productive well in the spacing unit. Acreage on which infill wells are drilled is considered developed commencing with the initial productive well established in the spacing unit. As such, the addition of an infill well does not have any impact on a company’s amount of developed acreage.
“Net acres.” The percentage ownership of gross acres. Net acres are deemed to exist when the sum of fractional ownership working interests in gross acres equals one (e.g., a 10% working interest in a lease covering 640 gross acres is equivalent to 64 net acres).
“NYMEX.” The New York Mercantile Exchange.
“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“Recompletion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil, NGLs or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible crude oil, NGLs and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
“Undeveloped acreage.” Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil, NGLs, and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage includes net acres held by operations until a productive well is established in the spacing unit.
“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“Wellbore.” The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.
“Working interest.” The right granted to the lessee of a property to explore for and to produce and own crude oil, NGLs, natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
“Workover.” Operations on a producing well to restore or increase production.
Terms used to assign a present value to or to classify our reserves:
“Possible reserves.” The additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves.
“Pre-tax PV-10% or PV-10.” The estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the United States Securities and Exchange Commission (the “SEC”).
“Probable reserves.” The additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but which together with proved reserves, are as likely as not to be recovered.
“Proved reserves.” The quantities of crude oil, NGLs and natural gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
“Proved undeveloped reserves” or “PUDs.” Proved Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
“SEC Pricing” means pricing calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules based on the unweighted arithmetic average of oil and natural gas prices as of the first day of each of the 12 months ended on the given date.
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CAUTIONARY NOTICE REGARDING FORWARD LOOKING STATEMENTS
We desire to take advantage of the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. This Report contains a number of forward-looking statements that reflect management’s current views and expectations with respect to our business, strategies, products, future results and events, and financial performance. All statements made in this Report other than statements of historical fact, including statements that address operating performance, the economy, events or developments that management expects or anticipates will or may occur in the future, including the adequacy of funds from operations, cash flows and financing, potential strategic transactions, statements regarding future operating results and non-historical information, are forward-looking statements. In particular, the words such as “believe,” “expect,” “intend,” “anticipate,” “estimate,” “may,” “will,” “can,” “plan,” “predict,” “could,” “future,” “continue,” variations of such words, and similar expressions identify forward-looking statements, but are not the exclusive means of identifying such statements and their absence does not mean that the statement is not forward-looking.
When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors.”Factors” in our annual report on Form 10-K for the fiscal year ended September 30, 2022. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.
Forward-looking statements may include statements about:
| ● | our business strategy; | |
| ● | our reserves; | |
| ● | our financial strategy, liquidity and capital requirements; | |
| ● | our realized or expected natural gas prices; | |
| ● | our timing and amount of future production of natural gas; | |
| ● | our future drilling plans and cost estimates; | |
| ● | our competition and government regulations; | |
| ● | our ability to make acquisitions; | |
| ● | ||
| general economic conditions; | ||
| ● | our future operating results; 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 the heading “Risk Factors.”Factors” in our annual report on Form 10-K for the fiscal year ended September 30, 2022.
Reserve engineering is a method of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of previous estimates. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas and oil that are ultimately recovered.
Should one or more of the risks or uncertainties described in this Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements, expressed or implied, included in this Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Report. Notwithstanding the foregoing, any public statements or disclosures by us following this Report that modify or impact any of the forward-looking statements contained in this Report will be deemed to modify or supersede such statements in this Report.
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PART 1 – FINANCIAL INFORMATION
| ITEM 1. | FINANCIAL STATEMENTS |
PERMEX PETROLEUM CORPORATION
CONDENSED INTERIM CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
| March 31, 2023 | September 30, 2022 | |||||||
| ASSETS | ||||||||
| Current assets | ||||||||
| Cash and cash equivalents | $ | 176,366 | $ | 3,300,495 | ||||
| Trade and other receivables, net | 156,095 | 137,214 | ||||||
| Prepaid expenses and deposits | 179,400 | 317,277 | ||||||
| Total current assets | 511,861 | 3,754,986 | ||||||
| Non-current assets | ||||||||
| Reclamation deposits | 145,000 | 145,000 | ||||||
| Property and equipment, net of accumulated depreciation and depletion | 10,308,317 | 8,426,776 | ||||||
| Right of use asset, net | 188,956 | 240,796 | ||||||
| Total assets | $ | 11,154,134 | $ | 12,567,558 | ||||
| LIABILITIES AND EQUITY | ||||||||
| Current liabilities | ||||||||
| Trade and other payables | $ | 2,661,112 | $ | 1,561,344 | ||||
| Convertible debenture | - | 38,291 | ||||||
| Lease liability – current portion | 84,514 | 104,224 | ||||||
| Total current liabilities | 2,745,626 | 1,703,859 | ||||||
| Non-current liabilities | ||||||||
| Asset retirement obligations | 252,400 | 236,412 | ||||||
| Lease liability, less current portion | 112,133 | 140,682 | ||||||
| Warrant liability | 1,066 | 23,500 | ||||||
| Total liabilities | 3,111,225 | 2,104,453 | ||||||
| Equity | ||||||||
| Common stock, no par value per share; shares authorized, shares* issued and outstanding as of March 31, 2023 and September 30, 2022 | 14,337,739 | 14,337,739 | ||||||
| Additional paid-in capital | 4,513,512 | 4,513,194 | ||||||
| Accumulated other comprehensive loss | (127,413 | ) | (127,413 | ) | ||||
| Deficit | (10,680,929 | ) | (8,260,415 | ) | ||||
| Total equity | 8,042,909 | 10,463,105 | ||||||
| Total liabilities and equity | $ | 11,154,134 | $ | 12,567,558 | ||||
| June 30, 2022 | September 30, 2021 | |||||||
| ASSETS | ||||||||
| Current assets | ||||||||
| Cash | $ | 5,366,789 | $ | 25,806 | ||||
| Trade and other receivables | 186,740 | 12,984 | ||||||
| Prepaid expenses and deposits | 878,119 | 46,151 | ||||||
| Total current assets | 6,431,648 | 84,941 | ||||||
| Non-current assets | ||||||||
| Reclamation deposits | 145,052 | 144,847 | ||||||
| Property and equipment | 7,838,520 | 7,846,145 | ||||||
| Right of use asset | 37,369 | 72,539 | ||||||
| Total assets | $ | 14,452,589 | $ | 8,148,472 | ||||
| LIABILITIES AND EQUITY | ||||||||
| Current liabilities | ||||||||
| Trade and other payables | $ | 1,123,635 | $ | 402,979 | ||||
| Amounts due to related party | 8,687 | 16,628 | ||||||
| Convertible debentures | 77,600 | 78,500 | ||||||
| Lease liability – current portion | 39,493 | 51,963 | ||||||
| Total current liabilities | 1,249,415 | 550,070 | ||||||
| Non-current liabilities | ||||||||
| Decommissioning obligations | 1,645,171 | 1,627,465 | ||||||
| Lease liability | 3,313 | 26,986 | ||||||
| Loan payable | - | 31,400 | ||||||
| Total liabilities | 2,897,899 | 2,235,921 | ||||||
| Equity | ||||||||
| Common shares 0 par value per share; shares authorized, and shares issued and outstanding as of June 30, 2022 and September 30, 2021, respectively | 14,381,071 | 8,976,747 | ||||||
| Share subscription proceeds | 30,456 | 30,456 | ||||||
| Reserves | 4,585,598 | 2,352,649 | ||||||
| Accumulated other comprehensive loss | (394,654 | ) | (128,532 | ) | ||||
| Deficit | (7,047,781 | ) | (5,318,769 | ) | ||||
| Total equity | 11,554,690 | 5,912,551 | ||||||
| Total liabilities and equity | $ | 14,452,589 | $ | 8,148,472 | ||||
| * | The number of shares has been restated to reflect the 60:1 reverse stock split (Note 1) |
The accompanying notes are an integral part of these condensed interim consolidated financial statements.
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PERMEX PETROLEUM CORPORATION
CONDENSED INTERIM CONSOLIDATED STATEMENTS OF LOSS AND COMPREHENSIVE LOSS
(UNAUDITED)
| Three Months Ended June 30, 2022 | Three Months Ended June 30, 2021 | Nine Months Ended June 30, 2022 | Nine Months Ended June 30, 2021 | |||||||||||||
| Revenue | ||||||||||||||||
| Oil and gas sales | $ | 258,757 | $ | 34,298 | $ | 577,244 | $ | 37,392 | ||||||||
| Royalty income | 17,965 | - | 47,813 | - | ||||||||||||
| Total revenue | 276,722 | 34,298 | 625,057 | 37,392 | ||||||||||||
| Expenses | ||||||||||||||||
| Producing | 135,467 | 11,179 | 332,346 | 21,392 | ||||||||||||
| Accounting and audit | 77,673 | 16,783 | 143,153 | 46,730 | ||||||||||||
| Accretion on decommissioning obligations | 8,238 | 2,987 | 24,714 | 8,792 | ||||||||||||
| Consulting | 47,436 | 3,571 | 64,209 | 17,474 | ||||||||||||
| Depletion and depreciation | 73,093 | 12,717 | 161,988 | 21,955 | ||||||||||||
| Filing and transfer agent | 19,484 | 8,925 | 59,309 | 43,285 | ||||||||||||
| Interest | 2,597 | 1,348 | 6,285 | 11,116 | ||||||||||||
| Investor relations | 54,860 | 43,685 | 96,593 | 46,091 | ||||||||||||
| Legal fees | 179,190 | 2,666 | 203,016 | 3,336 | ||||||||||||
| Management fees | 67,216 | 37,362 | 176,989 | 112,478 | ||||||||||||
| Marketing and promotion | 469,096 | 4,148 | 517,914 | 24,802 | ||||||||||||
| Office and general | 75,456 | 16,122 | 105,679 | 26,780 | ||||||||||||
| Rent | 21,389 | 14,655 | 54,907 | 34,791 | ||||||||||||
| Salaries | 7,500 | - | 7,500 | - | ||||||||||||
| Share-based payments | 185 | 486 | 604,861 | 2,401 | ||||||||||||
| Travel | 39,371 | 1,227 | 44,289 | 2,099 | ||||||||||||
| Total operating expenses | (1,278,251 | ) | (177,861 | ) | (2,603,752 | ) | (423,522 | ) | ||||||||
| Operating loss | (1,001,529 | ) | (143,563 | ) | (1,978,695 | ) | (386,130 | ) | ||||||||
| Foreign exchange gain (loss) | 222,539 | (14,195 | ) | 214,404 | (41,347 | ) | ||||||||||
| Forfeiture of reclamation deposit | - | 318 | - | (50,165 | ) | |||||||||||
| Forgiveness of loan payable | 7,900 | - | 7,900 | - | ||||||||||||
| Other income | 9,787 | 2,515 | 27,379 | 7,643 | ||||||||||||
| Settlement of trade payables | - | 1,965 | - | 9,683 | ||||||||||||
| Non-operating income (expense) | 240,226 | (9,397 | ) | 249,683 | (74,186 | ) | ||||||||||
| Net loss | (761,303 | ) | (152,960 | ) | (1,729,012 | ) | (460,316 | ) | ||||||||
| Other comprehensive income | ||||||||||||||||
| Foreign currency translation adjustment | (375,809 | ) | 49,419 | (266,122 | ) | 245,969 | ||||||||||
| Comprehensive loss | $ | (1,137,112 | ) | $ | (103,541 | ) | $ | (1,995,134 | ) | $ | (214,347 | ) | ||||
| Basic and diluted loss per common share | $ | (0.00 | ) | $ | (0.00 | ) | $ | (0.02 | ) | $ | (0.01 | ) | ||||
| Three Months Ended March 31, 2023 | Three Months Ended March 31, 2022 | Six Months Ended March 31, 2023 | Six Months Ended March 31, 2022 | |||||||||||||
| Revenues | ||||||||||||||||
| Oil and gas sales | $ | 170,989 | $ | 228,497 | $ | 384,743 | $ | 318,487 | ||||||||
| Royalty income | 9,649 | 13,389 | 17,837 | 29,848 | ||||||||||||
| Total revenues | 180,638 | 241,886 | 402,580 | 348,335 | ||||||||||||
| Operating expenses | ||||||||||||||||
| Lease operating expense | 234,478 | 115,000 | 527,157 | 196,879 | ||||||||||||
| General and administrative | 1,010,542 | 204,366 | 2,225,648 | 1,013,972 | ||||||||||||
| Depletion and depreciation | 42,977 | 56,884 | 83,173 | 88,895 | ||||||||||||
| Accretion on asset retirement obligations | 7,994 | 8,223 | 15,988 | 16,476 | ||||||||||||
| Foreign exchange gain (loss) | 1,070 | 3,644 | 4,380 | 8,614 | ||||||||||||
| Total operating expenses | (1,297,061 | ) | (388,117 | ) | (2,856,346 | ) | (1,324,836 | ) | ||||||||
| Loss from operations | (1,116,423 | ) | (146,231 | ) | (2,453,766 | ) | (976,501 | ) | ||||||||
| Other income (expense) | ||||||||||||||||
| Interest income | - | 2 | - | 2 | ||||||||||||
| Other income | 6,000 | 12,000 | 12,000 | 12,000 | ||||||||||||
| Finance expense | - | (1,180 | ) | (1,182 | ) | (24,648 | ) | |||||||||
| Change in fair value of warrant liability | (900 | ) | (22,519 | ) | 22,434 | 80,031 | ||||||||||
| Total other income (expense) | 5,100 | (11,697 | ) | 33,252 | 67,385 | |||||||||||
| Net loss and comprehensive loss | $ | (1,111,323 | ) | $ | (157,928 | ) | $ | (2,420,514 | ) | $ | (909,116 | ) | ||||
| Basic and diluted loss per common share | $ | (0.57 | ) | $ | (0.13 | ) | $ | (1.25 | ) | $ | (0.79 | ) | ||||
| Weighted average number of common shares outstanding* | 1,932,604 | 1,172,727 | 1,932,604 | 1,151,301 | ||||||||||||
| * | The number of shares has been restated to reflect the 60:1 reverse stock split (Note 1) |
The accompanying notes are an integral part of these condensed interim consolidated financial statements.
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PERMEX PETROLEUM CORPORATION
CONDENSED INTERIM CONSOLIDATED STATEMENTS OF EQUITY
(UNAUDITED)
Three Monthsmonths ended June 30, 2022March 31
| Number of Shares | Share capital | Reserves | Share subscription proceeds | Accumulated other comprehensive loss | Deficit | Total equity | ||||||||||||||||||||||
| Balance, March 31, 2022 | 115,956,026 | $ | 14,399,373 | $ | 4,585,413 | $ | 3,456 | $ | (18,845 | ) | $ | (6,286,478 | ) | $ | 12,709,919 | |||||||||||||
| Share issuance costs | - | (18,302 | ) | - | - | - | - | (18,302 | ) | |||||||||||||||||||
| Share-based payments | - | - | 185 | - | - | - | 185 | |||||||||||||||||||||
| Net loss | - | - | - | - | - | (761,303 | ) | (761,303 | ) | |||||||||||||||||||
| Other comprehensive income | - | - | - | - | (375,809 | ) | - | (375,809 | ) | |||||||||||||||||||
| Shares issued for services | - | - | - | - | - | - | - | |||||||||||||||||||||
| Shares issued for services, shares | - | - | - | - | - | - | - | |||||||||||||||||||||
| Private placements | - | - | - | - | - | - | - | |||||||||||||||||||||
| Private placements, shares | - | - | - | - | - | - | - | |||||||||||||||||||||
| Balance, June 30, 2022 | 115,956,026 | $ | 14,381,071 | $ | 4,585,598 | $ | 30,456 | $ | (394,654 | ) | $ | (7,047,781 | ) | $ | 11,554,690 | |||||||||||||
| Number of Shares* | Share capital | Additional paid-in capital | Accumulated other comprehensive loss | Deficit | Total equity | |||||||||||||||||||
| Balance, December 31, 2022 | 1,932,604 | $ | 14,337,739 | $ | 4,513,369 | $ | (127,413 | ) | $ | (9,569,606 | ) | $ | 9,154,089 | |||||||||||
| Share-based payments | - | - | 143 | - | - | 143 | ||||||||||||||||||
| Net loss | - | - | - | - | (1,111,323 | ) | (1,111,323 | ) | ||||||||||||||||
| Balance, March 31, 2023 | 1,932,604 | $ | 14,337,739 | $ | 4,513,512 | $ | (127,413 | ) | $ | (10,680,929 | ) | $ | 8,042,909 | |||||||||||
| Number of Shares | Share capital | Reserves | Share subscription proceeds | Accumulated other comprehensive loss | Deficit | Total equity | ||||||||||||||||||||||
| Balance, March 31, 2021 | 40,680,364 | $ | 6,473,147 | $ | 1,194,038 | $ | 30,456 | $ | (73,685 | ) | $ | (4,404,130 | ) | $ | 3,219,826 | |||||||||||||
| Shares issued for services | 500,000 | 34,850 | - | - | - | - | 34,850 | |||||||||||||||||||||
| Share-based payments | - | - | 486 | - | - | - | 486 | |||||||||||||||||||||
| Net loss | - | - | - | - | - | (152,960 | ) | (152,960 | ) | |||||||||||||||||||
| Other comprehensive income | - | - | - | - | 49,419 | - | 49,419 | |||||||||||||||||||||
| Balance, June 30, 2021 | 41,180,364 | $ | 6,507,997 | $ | 1,194,524 | $ | 30,456 | $ | (24,266 | ) | $ | (4,557,090 | ) | $ | 3,151,621 | |||||||||||||
| Number of Shares* | Share capital | Additional paid-in capital | Accumulated other comprehensive loss | Deficit | Total equity | |||||||||||||||||||
| Balance, December 31, 2021 | 1,147,127 | $ | 9,307,648 | $ | 3,108,585 | $ | (127,413 | ) | $ | (6,296,987 | ) | $ | 5,991,833 | |||||||||||
| Private placements | 785,477 | 6,933,410 | 607,170 | - | - | 7,540,580 | ||||||||||||||||||
| Share issuance costs | - | (1,884,523 | ) | 858,429 | - | - | (1,026,094 | ) | ||||||||||||||||
| Share-based payments | - | - | (2,649 | ) | - | - | (2,649 | ) | ||||||||||||||||
| Net loss | - | - | - | - | (157,928 | ) | (157,928 | ) | ||||||||||||||||
| Balance, March 31, 2022 | 1,932,604 | $ | 14,356,535 | $ | 4,571,535 | $ | (127,413 | ) | $ | (6,454,915 | ) | $ | 12,345,742 | |||||||||||
| * | The number of shares has been restated to reflect the 60:1 share consolidation (Note 1) |
The accompanying notes are an integral part of these condensed interim consolidated financial statements.
| 8 |
PERMEX PETROLEUM CORPORATION
CONDENSED INTERIM CONSOLIDATED STATEMENTS OF EQUITY (cont’d…)
(UNAUDITED)
Six months ended March 31
(UNAUDITED)
Nine Months ended June 30, 2022
| 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 | - | (1,962,900 | ) | 882,972 | - | - | - | (1,079,928 | ) | |||||||||||||||||||
| Share-based payments | - | - | 604,861 | - | - | - | 604,861 | |||||||||||||||||||||
| Net loss | - | - | - | - | - | (1,729,012 | ) | (1,729,012 | ) | |||||||||||||||||||
| Other comprehensive income | - | - | - | - | (266,122 | ) | - | (266,122 | ) | |||||||||||||||||||
| Balance, June 30, 2022 | 115,956,026 | $ | 14,381,071 | $ | 4,585,598 | $ | 30,456 | $ | (394,654 | ) | $ | (7,047,781 | ) | $ | 11,554,690 | |||||||||||||
| Number of Shares* | Share capital | Additional paid-in capital | Accumulated other comprehensive loss | Deficit | Total equity | |||||||||||||||||||
| Balance, September 30, 2022 | 1,932,604 | $ | 14,337,739 | $ | 4,513,194 | $ | (127,413 | ) | $ | (8,260,415 | ) | $ | 10,463,105 | |||||||||||
| Share-based payments | - | - | 318 | - | - | 318 | ||||||||||||||||||
| Net loss | - | - | - | - | (2,420,514 | ) | (2,420,514 | ) | ||||||||||||||||
| Balance, March 31, 2023 | 1,932,604 | $ | 14,337,739 | $ | 4,513,512 | $ | (127,413 | ) | $ | (10,680,929 | ) | $ | 8,042,909 | |||||||||||
| 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 | |||||||||||||
| Beginning balance | 40,024,114 | $ | 6,453,039 | $ | 1,192,123 | $ | 30,456 | $ | (270,235 | ) | $ | (4,096,774 | ) | $ | 3,308,609 | |||||||||||||
| Shares issued for services | 1,156,250 | 54,958 | - | - | - | - | 54,958 | |||||||||||||||||||||
| Share-based payments | - | - | 2,401 | - | - | - | 2,401 | |||||||||||||||||||||
| Net loss | - | - | - | - | - | (460,316 | ) | (460,316 | ) | |||||||||||||||||||
| Other comprehensive income | - | - | - | - | 245,969 | - | 245,969 | |||||||||||||||||||||
| Balance, June 30, 2021 | 41,180,364 | $ | 6,507,997 | $ | 1,194,524 | $ | 30,456 | $ | (24,266 | ) | $ | (4,557,090 | ) | $ | 3,151,621 | |||||||||||||
| Ending balance | 41,180,364 | $ | 6,507,997 | $ | 1,194,524 | $ | 30,456 | $ | (24,266 | ) | $ | (4,557,090 | ) | $ | 3,151,621 | |||||||||||||
| Number of Shares* | Share capital | Additional paid-in capital | Accumulated other comprehensive loss | Deficit | Total equity | |||||||||||||||||||
| Balance, September 30, 2021 | 1,103,010 | $ | 8,976,747 | $ | 2,476,717 | $ | (127,413 | ) | $ | (5,545,799 | ) | $ | 5,780,252 | |||||||||||
| Balance | 1,103,010 | $ | 8,976,747 | $ | 2,476,717 | $ | (127,413 | ) | $ | (5,545,799 | ) | $ | 5,780,252 | |||||||||||
| Private placements | 829,594 | 7,303,161 | 607,170 | - | - | 7,910,331 | ||||||||||||||||||
| Share issuance costs | - | (1,923,373 | ) | 882,972 | - | - | (1,040,401 | ) | ||||||||||||||||
| Share-based payments | - | - | 604,676 | - | - | 604,676 | ||||||||||||||||||
| Net loss | - | - | - | - | (909,116 | ) | (909,116 | ) | ||||||||||||||||
| Balance, March 31, 2022 | 1,932,604 | $ | 14,356,535 | $ | 4,571,535 | $ | (127,413 | ) | $ | (6,454,915 | ) | $ | 12,345,742 | |||||||||||
| Balance | 1,932,604 | $ | 14,356,535 | $ | 4,571,535 | $ | (127,413 | ) | $ | (6,454,915 | ) | $ | 12,345,742 | |||||||||||
| * | The number of shares has been restated to reflect the 60:1 reverse stock split (Note 1). |
The accompanying notes are an integral part of these condensed interim consolidated financial statements.
| 9 |
PERMEX PETROLEUM CORPORATION
CONDENSED INTERIM CONSOLIDATED STATEMENTS OF CASH FLOWS
NINESIX MONTHS ENDED JUNE 30MARCH 31
(UNAUDITED)
| 2022 | 2021 | 2023 | 2022 | |||||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||||||
| Net loss | $ | (1,729,012 | ) | $ | (460,316 | ) | $ | (2,420,514 | ) | $ | (909,116 | ) | ||||
| Adjustments to reconcile net loss to net cash from operating activities: | ||||||||||||||||
| Accretion on decommissioning obligations | 24,714 | 8,792 | ||||||||||||||
| Accretion on asset retirement obligations | 15,988 | 16,476 | ||||||||||||||
| Depletion and depreciation | 161,988 | 21,955 | 83,173 | 88,895 | ||||||||||||
| Foreign exchange loss (gain) | (214,133 | ) | 109,103 | - | 2,710 | |||||||||||
| Forfeiture of reclamation bond | - | 50,165 | ||||||||||||||
| Forgiveness of loan payable | (7,900 | ) | - | |||||||||||||
| Interest | 6,285 | 11,116 | ||||||||||||||
| Settlement of trade payables | - | (9,683 | ) | |||||||||||||
| Finance expense | - | 12,359 | ||||||||||||||
| Change in fair value of warrant liability | (22,434 | ) | (80,031 | ) | ||||||||||||
| Share-based payments | 604,861 | 2,401 | 318 | 604,676 | ||||||||||||
| Shares issued for services | - | 54,958 | ||||||||||||||
| Changes in operating assets and liabilities: | ||||||||||||||||
| Trade and other receivables | (174,362 | ) | 35,414 | (18,881 | ) | (133,419 | ) | |||||||||
| Prepaid expenses and deposits | (833,922 | ) | (21,336 | ) | 137,877 | (35,085 | ) | |||||||||
| Trade and other payables | 711,083 | (293,869 | ) | 303,263 | 179,859 | |||||||||||
| Amounts due to related parties | (10,618 | ) | (164,560 | ) | - | (18,960 | ) | |||||||||
| Right of use asset and lease liability | 40,731 | 32,669 | 3,581 | (261 | ) | |||||||||||
| Net cash used in operating activities | (1,420,285 | ) | (623,192 | ) | (1,917,629 | ) | (271,897 | ) | ||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||||||
| Capital expenditures on property and equipment | (202,136 | ) | (283,298 | ) | (1,168,209 | ) | (90,219 | ) | ||||||||
| Proceeds from sale of oil and gas interests | - | 1,123,244 | ||||||||||||||
| Net cash provided by (used in) investing activities | (202,136 | ) | 839,946 | |||||||||||||
| Net cash used in investing activities | (1,168,209 | ) | (90,219 | ) | ||||||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||||||
| Proceeds from issuance of share capital | 8,112,340 | - | ||||||||||||||
| Proceeds from issuance of private placement units | - | 8,112,340 | ||||||||||||||
| Share issuance costs | (1,079,928 | ) | - | - | (1,049,072 | ) | ||||||||||
| Convertible debenture repayment | - | (79,000 | ) | (38,291 | ) | - | ||||||||||
| Loan repayment | (23,700 | ) | - | |||||||||||||
| Loan from related party | (3,647 | ) | (6,329 | ) | - | 800 | ||||||||||
| Lease payments | (41,661 | ) | (30,193 | ) | ||||||||||||
| Net cash provided by (used in) financing activities | 6,963,404 | (115,522 | ) | (38,291 | ) | 7,064,068 | ||||||||||
| Change in cash during the period | 5,340,983 | 101,232 | ||||||||||||||
| Change in cash and cash equivalents during the period | (3,124,129 | ) | 6,701,952 | |||||||||||||
| Cash, beginning of the period | 25,806 | 5,517 | ||||||||||||||
| Cash and cash equivalents, beginning of the period | 3,300,495 | 25,806 | ||||||||||||||
| Cash, end of the period | $ | 5,366,789 | $ | 106,749 | ||||||||||||
| Cash and cash equivalents, end of the period | $ | 176,366 | $ | 6,727,758 | ||||||||||||
| Supplemental disclosures of non-cash investing and financing activities: | ||||||||||||||||
| Share purchase warrants issued in connection with private placements | - | 1,692,151 | ||||||||||||||
| Trade and other payables related to property and equipment | $ | 93,960 | $ | 69,262 | 1,443,757 | 82,054 | ||||||||||
| Share purchase warrants issued in connection with private placement | 1,628,088 | - | ||||||||||||||
| Supplemental cash flow disclosures: | ||||||||||||||||
| Interest paid | 18,960 | 13,090 | 1,182 | 18,960 | ||||||||||||
The accompanying notes are an integral part of these condensed interim consolidated financial statements.
| 10 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS
NINETHREE AND SIX MONTHS ENDED JUNE 30, 2022MARCH 31, 2023
(UNAUDITED)
1. BACKGROUND
Permex Petroleum Corporation (the “Company”) was incorporated on April 24, 2017 under the laws of British Columbia, Canada and maintains its head office at Suite 500, 666 Burrard Street, Vancouver, British Columbia, Canada, V6C 2X8 and its US office at Suite 700, 100 Crescent Court,925, 2911 Turtle Creek Blvd, Dallas, Texas, 75201.75219. 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”.
On October 26, 2022, the Company’s board of directors approved a reverse stock split of the Company’s issued and outstanding common stock at a 1 for 60 ratio, which was effective November 2, 2022. The par value and authorized shares of common stock were not adjusted as a result of the reverse stock split. All issued and outstanding common stock, options, and warrants to purchase common stock and per share amounts contained in the financial statements have been retroactively adjusted to reflect the reverse stock split for all periods presented.
2. SIGNIFICANT ACCOUNTING POLICIES
Basis of presentation
The unaudited condensed interim 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, 20222023 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 amended Form S-1footnotes for the fiscal year ended September 30, 2021 filed with the Securities and Exchange Commission (“SEC”) on August 8, 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 the Company’s wholly-owned subsidiary.subsidiary, Permex Petroleum US Corporation. All intercompany balances and transactions have been eliminated.
| 11 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS
THREE AND SIX MONTHS ENDED MARCH 31, 2023
(UNAUDITED)
2. Significant Accounting Policies (cont’d…)
Going concern of operations
These consolidated financial statements have been prepared on a going concern basis which assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business. The Company has incurred losses since inception in the amount of $10,680,929 and has not yet achieved profitable operations. The Company has been relying on equity financing and loans from related parties to fund its operation in the past. While the Company has been successful in securing financing to date, there can be no assurances that it will be able to do so in the future. The aforementioned factors raise substantial doubt about the Company’s ability to continue as a going concern within one year after the date that the financial statements are issued.
Management plans to fund operations of the Company with its current working capital and through increasing production from its oil and gas leases. The Company also expects to raise additional funds through equity financings. There are no written agreements in place for such funding or issuance of securities and there can be no assurance that such will be available in the future. Management believes that this plan provides an opportunity for the Company to continue as a going concern.
In view of these matters, continuation as a going concern is dependent upon continued operations of the Company, which in turn is dependent upon the Company’s ability to meet its financial requirements, raise additional capital, and the success of its future operations. The financial statements do not include any adjustments to the amount and classification of assets and liabilities that may be necessary should the Company not continue as a going concern.
Use of Estimates
The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities at the date of the financial statements and the reported amount of revenue and expenses during the reporting period. Management evaluates these estimates and judgments on an ongoing basis and bases its estimates on experience, current and expected future conditions, third-party evaluations and various other assumptions that management believes are reasonable under the circumstances. Significant estimates have been used by management in conjunction with the following: (i) 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)(ii) the costs of site restoration when determining decommissioning liabilities; (iv) income taxes receivable or payable; (v)(iii) the useful lives of assets for the purposes of depletion and depreciation; (vi)(iv) petroleum and natural gas reserves; and (vii)(v) share-based payments. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, and makes adjustments when facts and circumstances dictate. These estimates are based on information available as of the date of the financial statements; therefore, actual results could differ from those estimates.
New accounting standards
There are not currently any new or pending accounting standards that are expected to have a significant impact on the Company’s consolidated financial statements.
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS
NINETHREE AND SIX MONTHS ENDED JUNE 30, 2022MARCH 31, 2023
(UNAUDITED)
3. 2. Significant Accounting PoliciesREVENUE (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 areRevenue from contracts with customers is presented in United States dollars (“USD,” “US” or “$”). The functional currency“Oil and gas sales” on the Consolidated Statements of the Company is the Canadian dollar (“CAD”). The functional currency for the subsidiary of the Company is USD.Loss.
As of March 31, 2023 and September 30, 2022, receivable from contracts with customers, included in trade and other receivables, were $Recently adopted accounting pronouncement69,359 and $56,639
None., respectively.
The following table present our revenue from contracts with customers disaggregated by product type and geographic areas.
SCHEDULE OF REVENUE DISAGGREGATED BY PRODUCT TYPE AND GEOGRAPHIC AREAS
| Three months ended March 31, 2023 | Texas | New Mexico | Total | |||||||||
| Crude oil | $ | 129,618 | $ | 34,543 | $ | 164,161 | ||||||
| Natural gas | 6,828 | - | 6,828 | |||||||||
| Revenue | $ | 136,446 | $ | 34,543 | $ | 170,989 | ||||||
| Three months ended March 31, 2022 | Texas | New Mexico | Total | |||||||||
| Crude oil | $ | 169,747 | $ | 48,247 | $ | 217,994 | ||||||
| Natural gas | 10,503 | - | 10,503 | |||||||||
| Revenue | $ | 180,250 | $ | 48,247 | $ | 228,497 | ||||||
| 1 | 2 | 3 | ||||||||||
| Six months ended March 31, 2023 | Texas | New Mexico | Total | |||||||||
| Crude oil | $ | 303,579 | $ | 74,055 | $ | 377,634 | ||||||
| Natural gas | 7,109 | - | 7,109 | |||||||||
| Revenue | $ | 310,688 | $ | 74,055 | $ | 384,743 | ||||||
| Six months ended March 31, 2022 | Texas | New Mexico | Total | |||||||||
| Crude oil | $ | 239,908 | $ | 48,247 | $ | 288,155 | ||||||
| Natural gas | 30,332 | - | 30,332 | |||||||||
| Revenue | $ | 270,240 | $ | 48,247 | $ | 318,487 | ||||||
3.4. CONCENTRATION OF CREDIT RISK
The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents and trade receivables. The Company’s cash balances sometimes exceed the United States’ Federal Deposit Insurance Corporation insurance limits. The Company mitigates this risk by placing its cash and cash equivalents with high credit quality financial institutions and attempts to limit the amount of credit exposure with any one institution. To date, the Company has not recognized any losses caused by uninsured balances.
DuringThe majority of the nine months ended JuneCompany’s receivable balance is concentrated in trade receivables, with a balance of $106,845 as of March 31, 2023 (September 30, 2022 the Company generated 54% of total revenue from one customer (2021 - $10091,928%). As at June 30, 2022, one customerTwo customers represented $107,73857,730 (7154%) of the trade receivable balance. The Company routinely assesses the financial strength of its customers. The non-trade receivable balance (September 30, 2021 -consists of goods and services tax (“GST”) recoverable of $2,92749,250 (26%)). GST recoverable is due from the Canadian Government. It is in management’s opinion that the Company is not exposed to significant credit risk. To date, the Company has not recognized any credit losses on its receivables.
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 June 30, 2022, the Company held reclamation bonds of $145,052 (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.
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 common shares and share purchase warrants as consideration for this acquisition. The Company valued the common shares issued at a fair value of $2,468,750. The share purchase warrants were valued at $ using the Black-Scholes option pricing model (assuming a risk-free interest rate of %, an expected life of -years, annualized volatility of % and a dividend rate of %). The warrants have an exercise price $ per share (CAD$) and are exercisable until October 1, 2031.
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS
NINETHREE AND SIX MONTHS ENDED JUNE 30, 2022MARCH 31, 2023
(UNAUDITED)
4. NON-CURRENT ASSETS (cont’d…)
Property and equipment5. PROPERTY AND EQUIPMENT
Property and equipment consisted of the following:
SCHEDULE OF PROPERTY AND EQUIPMENT
| June 30, 2022 | September 30, 2021 | March 31, 2023 | September 30, 2022 | |||||||||||||
| Oil and natural gas properties, at cost | $ | 8,044,184 | $ | 7,954,807 | $ | 10,376,481 | $ | 8,029,234 | ||||||||
| Vehicle, at cost | 63,918 | - | ||||||||||||||
| Less: accumulated depletion and depreciation | (269,582 | ) | (108,662 | ) | ||||||||||||
| Construction in progress | - | 460,306 | ||||||||||||||
| Less: accumulated depletion | (243,515 | ) | (184,658 | ) | ||||||||||||
| Oil and natural gas properties, net | 10,132,966 | 8,304,882 | ||||||||||||||
| Other property and equipment, at cost | 205,315 | 127,542 | ||||||||||||||
| Less: accumulated depreciation | (29,964 | ) | (5,648 | ) | ||||||||||||
| Other property and equipment, net | 175,351 | 121,894 | ||||||||||||||
| Property and equipment, net | $ | 7,838,520 | $ | 7,846,145 | $ | 10,308,317 | $ | 8,426,776 | ||||||||
Depletion and depreciation expense was $161,98883,173 and $21,95588,895 for the ninesix month periods ended June 30,March 31, 2023 and March 31, 2022, respectively. Depletion and 2021,depreciation expense for the three month periods ended March 31, 2023 and March 31, 2022 was $42,977 and $56,884, respectively.
5.6. DECOMMISSIONING OBLIGATIONSLEASES
The total future decommissioning obligations are based onAll of the Company’s net ownership in wells and facilities, estimated costsright-of-use assets are operating leases related to reclaim and abandon the wells and facilities, and the estimated timingits office premises. Details 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 June 30, 2022 (September 30, 2021 - $2,836,777)right-of-use assets 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% (2021 - 2.0%) and discounted using a risk-free rate of 2.02% (2021 - 1.93%) based on expected settlement date.
Changes to the decommissioning obligationslease liabilities are as follows:
SCHEDULE OF DECOMMISSIONING OBLIGATIONSRIGHT OF USE OPERATING LEASES
| June 30, 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 | 24,714 | 11,722 | ||||||
| Foreign exchange movement | (7,008 | ) | 26,120 | |||||
| Decommissioning obligation | $ | 1,645,171 | $ | 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 and a gain of $13,194 was netted against the loss realized from the sale of properties.
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS
NINE MONTHS ENDED JUNE 30, 2022
(UNAUDITED)
6. DEBT
Convertible debentures
| March 31, 2023 | September 30, 2022 | |||||||
| Right-of-use assets | $ | 188,956 | $ | 240,796 | ||||
| Lease liabilities | ||||||||
| Balance, beginning of the year | $ | 244,906 | $ | 78,949 | ||||
| Addition | - | 220,368 | ||||||
| Liability accretion | 13,402 | 9,042 | ||||||
| Lease payments | (61,661 | ) | (63,453 | ) | ||||
| Balance, end of the year | $ | 196,647 | $ | 244,906 | ||||
| Current lease liabilities | $ | 84,514 | $ | 104,224 | ||||
| Long-term lease liabilities | $ | 112,133 | $ | 140,682 | ||||
The Company issued afollowing table presents the Company’s total of $lease cost.
157,000SCHEDULE OF LEASE COST (CAD$
| Three Months Ended March 31, 2023 | Three Months Ended March 31, 2022 | Six Months Ended March 31, 2023 | Six Months Ended March 31, 2022 | |||||||||||||
| Operating lease cost | $ | 29,845 | $ | 13,813 | $ | 65,243 | $ | 27,774 | ||||||||
| Variable lease expense | 18,822 | 9,869 | 25,997 | 17,426 | ||||||||||||
| Sublease income | (10,391 | ) | (10,730 | ) | (20,395 | ) | (15,598 | ) | ||||||||
| Rent subsidy | - | - | - | (1,674 | ) | |||||||||||
| Net lease cost | $ | 38,276 | $ | 12,952 | $ | 70,845 | $ | 27,928 | ||||||||
200,000) in convertible debentures to the CEO and a directorAs of the Company on October 17, 2019 and February 21, 2020 for cash. The debentures are secured by an interest in allMarch 31, 2023, maturities of the Company’s right, title, and interest in all of its oil and gas assets, had 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 $0.12 (CAD$) 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 $0.16 (CAD$). As of June 30, 2022, $77,600 (CAD$100,000) (September 30, 2021 - $78,500) of debenture loan remained outstanding and the interest accrued on the loan was $4,241 (September 30, 2021 - $15,176).
During the nine months ended June 30, 2022 and 2021, the Company recorded interest of $6,285 and $11,116, respectively, and is included within amounts due to related party on the condensed 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 nine months ended June 30, 2022, the Company paid interest of $18,960 (2021 - $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 was 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. During the nine months ended June 30, 2022, the Company repaid the loan balance of $23,700 (CAD$30,000) and recognized a gain of $7,900 (CAD$10,000) on the forgiven amount.
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 June 30, 2022, the Company’s lease had a weighted-average remaining term of 0.93 year. The undiscounted future lease payments as of June 30, 2022liabilities are as follows:
SCHEDULE OF UNDISCOUNTED FUTURE LEASE PAYMENTS
| 2022 | $ | 13,785 | ||||||
| Year | ||||||||
| 2023 | 31,643 | $ | 49,127 | |||||
| 2024 | 82,190 | |||||||
| 2025 | 84,664 | |||||||
| 2026 | 14,180 | |||||||
| Total lease payments | $ | 45,428 | 230,161 | |||||
| Less: imputed interest | (33,514 | ) | ||||||
| Total lease liabilities | $ | 196,647 | ||||||
| 14 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS
NINETHREE AND SIX MONTHS ENDED JUNE 30, 2022MARCH 31, 2023
(UNAUDITED)
7. COMMITMENTS AND CONTINGENCIES ASSET RETIREMENT OBLIGATIONS(cont’d…)
The componentsAsset retirement obligations reflects the estimated present value of lease expense for the nine month periods ended June 30 wereamount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties. Changes to the asset retirement obligations are as follows:
SCHEDULE OF COMPONENTS OF LEASE EXPENSEASSET RETIREMENT OBLIGATIONS
| 2022 | 2021 | |||||||
| Fixed lease expense | $ | 41,661 | $ | 30,194 | ||||
| Variable lease expense | 13,246 | 4,597 | ||||||
| Total | $ | 54,907 | $ | 34,791 | ||||
The following is a continuity schedule of the lease liability:
SCHEDULE OF LEASE LIABILITY
| June 30, 2022 | September 30, 2021 | |||||||
| Balance, beginning of the year | $ | 78,949 | $ | 53,128 | ||||
| Addition | - | 57,357 | ||||||
| Interest expense | 5,714 | 9,812 | ||||||
| Lease payments | (41,661 | ) | (43,932 | ) | ||||
| Foreign exchange movement | (196 | ) | 2,584 | |||||
| Balance, end of the year | $ | 42,806 | $ | 78,949 | ||||
| Current liability | $ | 39,493 | $ | 51,963 | ||||
| Long-term liability | $ | 3,313 | $ | 26,986 | ||||
8. RELATED PARTY TRANSACTIONS
| March 31, 2023 | September 30, 2022 | |||||||
| Asset retirement obligations, beginning of the year | $ | 236,412 | $ | 552,594 | ||||
| Revisions of estimates | - | (371,212 | ) | |||||
| Accretion expense | 15,988 | 55,030 | ||||||
| Asset retirement obligations, ending of the year | $ | 252,400 | $ | 236,412 | ||||
During the year ended September 30, 2020,2022, the Company issued a totalhad revision of estimates totaling $157,000371,212 (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 debentureprimarily due to a director of the Company together with accrued interest of $13,090. As of June 30, 2022, $77,600 (CAD$100,000) (September 30, 2021 - $78,500) of debenture loan remained outstandingchanges in future cost estimates and the interest accrued on the loan was $4,241 (September 30, 2021 - $15,176).retirement dates for its oil and gas assets.
During the nine months ended June 30, 2022, the Company incurred management fees of $176,989 (2021 - $112,478) to 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.Reclamation deposits
On May 1, 2022,As of March 31, 2023, the Company amended the employment with the CEO of the Company for an annual base salaryheld reclamation deposits of $250,000145,000 (September 30, 2022 - $145,000), which are expected to be released after all reclamation work has been completed with no specified term. The CEO is also eligible on an annual basis for a cash bonus of upregard to 100% of annual salary. The employment agreement may be terminated with a termination payment equal to three years of base salaryits oil and a bonus equal to 20% of the annual base salary.natural gas interests.
On May 1, 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.
| 15 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS
NINETHREE AND SIX MONTHS ENDED JUNE 30, 2022MARCH 31, 2023
(UNAUDITED)
8. DEBT
Convertible debenture – Related party
As of September 30, 2022, the Company had a debenture loan of $73,000 (CAD$100,000) from the CEO of the Company outstanding. The debenture loan was secured by an interest in all of the Company’s right, title, and interest in all of its oil and gas assets, bore interest at a rate of 12% per annum and had a maturity date of December 20, 2022. The debenture was convertible at the holder’s option into units of the Company at $6.57 (CAD$) per unit. Each unit would be comprised of one common share of the Company and one share purchase warrant; each warrant entitled the holder to acquire one additional common share for a period of three years at an exercise price of $8.76 (CAD $).
During the year ended September 30, 2022, the Company repaid $34,709 of the loan (CAD$47,546). In November 2022, the Company repaid the remaining principal loan amount of $38,291 (CAD$52,454).
The Company recorded interest of $1,182 and $nil for the three and six months ended March 31, 2023. The Company recorded interest of $1,286 and $3,688 for the three and six months ended March 31, 2022.
Loan payable
In May 2020, the Company opened a Canada Emergency Business Account (“CEBA”) and received a loan of $28,640 (CAD$40,000) from the Canadian Government. The CEBA program was established to provide interest-free loans of up to CAD$60,000 to small businesses to help them cover operating costs during the COVID-19 pandemic. The loan was unsecured and non-interest bearing with a repayment deadline of December 31, 2023. During the year ended September 30, 2022, the Company repaid the loan balance of $23,600 (CAD$30,000) and recognized a gain of $7,800 (CAD$10,000) on the forgiven amount.
9. RELATED PARTY TRANSACTIONS
The convertible debenture loan from the CEO of the Company mentioned in Note 8 was repaid during the six months ended March 31, 2023.
SCHEDULE OF BASIC AND DILUTED LOSS PER SHARE
| Three Months Ended March 31, 2023 | Three Months Ended March 31, 2022 | Six Months Ended March 31, 2023 | Six Months Ended March 31, 2022 | |||||||||||||
| Net loss | $ | (1,111,323 | ) | $ | (157,928 | ) | $ | (2,420,514 | ) | $ | (909,116 | ) | ||||
| Weighted average common shares outstanding | 1,932,604 | 1,172,727 | 1,932,604 | 1,151,301 | ||||||||||||
| Basic and diluted loss per share | $ | (0.57 | ) | $ | (0.13 | ) | $ | (1.25 | ) | $ | (0.79 | ) | ||||
For the three and six months ended March 31, 2023, stock options and warrants were excluded from the diluted weighted average number of common shares calculation as their effect would have been anti-dilutive. For the three and six months ended March 31, 2022, stock options and warrants were excluded from the diluted weighted average number of common shares calculation as their effect would have been anti-dilutive.
| 16 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS
THREE AND SIX MONTHS ENDED MARCH 31, 2023
(UNAUDITED)
11. EQUITY
Common sharesstock
The Company has authorized an number of common shares with 0no par value. At June 30, 2022March 31, 2023 and September 30, 2021,2022, the Company had
There were no share issuance transactions during the six months ended March 31, 2023.
During the nine monthsyear ended JuneSeptember 30, 2022, the Company:
| a) | Completed a non-brokered private placement of units at a price of $ (CAD$) per unit for gross proceeds of $571,760 (CAD$714,700) |
| b) | Completed a brokered private placement of units at a price of $ per unit for gross proceeds of $7,540,580 |
During the year ended September 30, 2021, the Company:
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS
NINE MONTHS ENDED JUNE 30, 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 sharesstock 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 sharesstock as calculated on the date of grant. The options can be granted for a maximum term of years and vest at the discretion of the Board of Directors at the time of grant.
| 17 |
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS
THREE AND SIX MONTHS ENDED MARCH 31, 2023
(UNAUDITED)
11. EQUITY (cont’d…)
Share-based payments (cont’d…)
Stock option transactions are summarized as follows:
SCHEDULE OF STOCK OPTION TRANSACTIONS
| Number of options | Weighted 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, June 30, 2022 | 5,575,000 | $ | 0.24 | |||||
| Exercisable at June 30, 2022 | 5,500,000 | $ | 0.25 | |||||
| Weighted average fair value of options granted | $ | 0.19 | (2021 - $) | |||||
| Number of options | Weighted Average Exercise Price | |||||||
| Balance, September 30, 2021 | 37,917 | $ | 19.51 | |||||
| Granted | 55,000 | 10.51 | ||||||
| Cancelled | (8,334 | ) | 17.34 | |||||
| Balance, September 30, 2022 | $ | |||||||
| Cancelled | (3,333 | ) | 10.66 | |||||
| Balance, March 31, 2023 | $ | |||||||
| Exercisable at March 31, 2023 | 81,250 | $ | 13.56 | |||||
The aggregate intrinsic value of options outstanding and exercisable as at June 30, 2022March 31, 2023 was $ (2021(September 30, 2022 - $).
The options outstanding as of June 30, 2022 equaled shares, andMarch 31, 2023 have exercise prices in the range of $ to $ and a weighted average remaining contractual life of years. The weighted average fair value of options granted during the nine months ended June 30, 2022 was $. There were options granted during the year ended September 30, 2021.
During the ninesix months ended June 30,March 31, 2023 and 2022, and 2021, the Company recognized share-based payment expense of $ and $, respectively, for the portion of stock options that vested during the period. The share-based payment expense for the three months ended March 31, 2023 and 2022 was $ and $, respectively. The following weighted average assumptions were used for the Black-Scholes valuation of stock options granted:
| 2022 | 2021 | 2023 | 2022 | |||||||||||||
| Risk-free interest rate | % | % | ||||||||||||||
| Expected life of options | Years | Years | ||||||||||||||
| Expected annualized volatility | % | % | ||||||||||||||
| Dividend rate | ||||||||||||||||
| Weighted average fair value of options granted | $ | |||||||||||||||
SCHEDULE OF STOCK OPTIONS OUTSTANDING
| Number of Options | Exercise Price | Issuance Date | Expiry Date | |||||||
| 27,917 | $ | 22.20 | ||||||||
| 5,000 | $ | 13.32 | ||||||||
| 5,000 | $ | 2.22 | ||||||||
| 48,333 | $ | 10.66 | ||||||||
| 81,250 | ||||||||||
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS
NINETHREE AND SIX MONTHS ENDED JUNE 30, 2022MARCH 31, 2023
(UNAUDITED)
9.11. EQUITY (cont’d…)
Share-based payments(cont’d…)
As at June 30, 2022, the following stock options were outstanding:
SCHEDULE OF STOCK OPTIONS OUTSTANDING
| Number of Options | Exercise Price | Expiry Date | ||||||
| 1,675,000 | $ | 0.39 | ||||||
| 300,000 | $ | 0.23 | ||||||
| 300,000 | $ | 0.04 | ||||||
| 3,300,000 | $ | 0.19 | ||||||
| 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:
SCHEDULE OF WARRANTS TRANSACTIONS
| Number of Warrants | Weighted Average Price | 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 | 208,333 | $ | 9.42 | ||||||||||
| Granted | 53,325,806 | 0.21 | 888,763 | 12.91 | ||||||||||||
| Balance, June 30, 2022 | 65,825,806 | $ | 0.21 | |||||||||||||
| Balance, September 30, 2022 and March 31, 2023 | 1,097,096 | $ | 12.12 | |||||||||||||
As at June 30, 2022,March 31, 2023, the following warrants were outstanding:
SCHEDULE OF WARRANTS OUTSTANDING
| Number of Options | Exercise Price | Expiry Date | ||||||
| 1,484,318 | $ | 0.42 | ||||||
| 51,841,488 | $ | 0.20 | ||||||
| 12,500,000 | $ | 0.16 | ||||||
| 65,825,806 | ||||||||
PERMEX PETROLEUM CORPORATION
NOTES TO THE CONDENSED INTERIM CONSOLIDATED FINANCIAL STATEMENTS
NINE MONTHS ENDED JUNE 30, 2022
(UNAUDITED)
| Number of Warrants | Exercise Price | Issuance Date | Expiry Date | |||||||
| 24,739 | $ | 23.98 | ||||||||
| 864,024 | $ | 12.60 | ||||||||
| 208,333 | $ | 8.88 | ||||||||
| 1,097,096 | ||||||||||
10. LOSS PER SHARE22,059
The calculation of basic and diluted loss per share for the nine month periods ended June 30, warrants issued with private placement units during fiscal 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 | $ | (1,729,012 | ) | $ | (460,316 | ) | ||
| Weighted average common shares outstanding | 84,704,029 | 40,588,217 | ||||||
| Basic and diluted loss per share | $ | (0.02 | ) | $ | (0.01 | ) | ||
As of June 30, 2022, $77,600 (CAD$100,000) of convertible debentures convertible into common shares, (2021 - ) stock options and (2021 - )have an exercise price denominated in CAD. These warrants were excluded frominitially valued at $202,009 using the diluted weighted average numberBlack-Scholes option pricing model (assuming a risk-free interest rate of common shares calculation%, an expected life of years, annualized volatility of % and a dividend rate of %) and recorded as their effect would have been anti-dilutive.a warrant liability. These warrants were subsequently revalued and a gain on fair value adjustment of $178,509 was recorded during the year ended September 30, 2022. During the six months ended March 31, 2023, a gain on fair value adjustment of $22,434 was recorded (2022 - $80,031). During the three months ended March 31, 2023, a loss on fair value adjustment of $900 was recorded (2022 - $22,519).
Operating segmentsSCHEDULE OF VALUATION OF WARRANTS
The Company operates in a single reportable segment – the acquisition, development and production of oil and gas properties in the United States.
| March 31, 2023 | September 30, 2022 | |||||||
| Risk-free interest rate | 3.78 | % | 3.79 | % | ||||
| Expected life of options | 0.50 Year | 1 Year | ||||||
| Expected annualized volatility | 120.78 | % | 135.59 | % | ||||
| Dividend rate | Nil | Nil | ||||||
| Weighted average fair value of options granted | $ | 0.06 | $ | 1.46 | ||||
| 19 |
| ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. |
This Report contains forward-looking statements. These statements relate to future events or our future financial performance. These statements are only predictions. Actual events or results may differ materially. In evaluating these statements, you should specifically consider various factors, including the risks outlined at the beginning of this Report under “Cautionary Notice Regarding Forward-Looking Statements” the risks outlined under the heading “Risk Factors” in our annual report on Form 10-K for the fiscal year ended September 30, 2022 and in our other reports we file with the SEC. These factors may cause our actual results to differ materially from any forward-looking statements. All amounts in this report are in U.S. dollars, unless otherwise noted.
Reserve engineering is a method of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of previous estimates. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas and oil that are ultimately recovered.
Company Overview
The Company was incorporated on April 24, 2017 under the laws of British Columbia, Canada. The Company is an independent energy company engaged in the acquisition, exploration, development and production of oil and gas properties on private, state and federal land in the United States, primarily in the Permian Basin which includes the Midland Basin and Delaware Basin. The Company focuses on acquiring producing assets at a discount to market, increasing production and cash-flow through recompletion and re-entries, secondary recovery and lower risk infill drilling and development. Currently, the Company owns and operates various oil and gas properties located in Texas and New Mexico. In addition, the Company holds various royalty interests in 73 wells and five5 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 producing oil and gas assets, 6762 shut-in opportunities, and 17 salt water disposal wells that help eliminate water disposal fees and lower operating expenses and two water supply wells allowing for waterflood secondary recovery.
The Company’s common shares are listed on the Canadian Securities Exchange under the symbol “OIL” on the OTCQB under the symbol “OILCF”, and on the Frankfurt Stock Exchange under the symbol “75P”. On June 28, 2022, the Company filed a Registration Statement on Form S-1 (as amended, the “Registration Statement”) under the Securities Act of 1933, as amended (the “Securities Act”) with the SEC to register for resale the securities issued by the Company in a brokered private placement completed in March 2022. The Registration Statement became effective on August 12, 2022, which has resulted in the Company becoming a reporting company under the United States Securities Exchange Act of 1934, as amended.
Key activities:
| ● | On October |
| |
| ● | On |
| ● | On |
| 20 |
Impact of COVID-19
In March 2020 the World Health Organization declared coronavirus (“COVID-19”) a global pandemic. 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 an Appraisal of Certain Oil and Gas Interests owned by Permex Petroleum Corporation located in New Mexico andBreedlove “B” Clearfork Leases - 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 the Company 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 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 such Appraisal Report or in the securities of the Company. Because the Company’s current size, the Company does not have any technical person at the Company responsible for overseeing the preparation of the reserve estimates presented herein (or have any internal control policies pertaining to estimates of oil and gas reserves) and consequently the Company relies exclusively on the Appraisal Reports in the preparation of the reserve estimates present in this Report.
Since allIn September 2021, we, through our wholly-owned subsidiary, Permex U.S., acquired a 100% Working Interest and an 81.75% Net Revenue Interest in the Breedlove “B” Clearfork leases located in Martin County, Texas. The Breedlove “B” Clearfork properties situated in Martin County, Texas are over 12 contiguous sections for a total of 7,870.23 gross and 7,741.67 net acres, of which 98% is held by production in the core of the Company’s reservesPermian 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 conventional reservoirs, MKM Engineering assumed forthis well to the purposes of its appraisal reports thatinjections wells on the technologyproperty prior to be used to developputting the Company’s reserves would include horizontally drilled wells, fracturing, and acidizing.well back on pump. By doing so management is avoiding unnecessary operating expenses from water disposal in third party disposal facilities.
Pittcock Leases - Texas
The Pittcock Leases are situated in Stonewall County. Stonewall County is in Northwest Texas, in the central part of the North Central Plains and consists of the Pittcock North property, the Pittcock South property and the Windy Jones Property. It is bounded on the north by King County, on the east by Haskell County, on the south by Fisher and Jones Counties, and on the west by Kent County. The Pittcock North property covers 320 acres held by production. There is currently one producing well, ten shut-in wells, two saltwater disposal wells, and a water supply well. We hold a 100% working interest in the Pittcock North Property and an 81.25% net revenue interest. The Pittcock South property covers 498 acres in four tracts. There are currently 19 shut-in wells and two saltwater disposal wells. We hold a 100% working interest in the lease and a 71.90% net revenue interest. The Windy Jones Property consists of 40 acres and includes two injection wells and two suspended oil wells. The sole purpose of the Windy Jones property is to provide waterflood to the offset wells being the Pittcock wells located east boundary of the Windy Jones Property. We hold a 100% working interest in the Windy Jones Property and a 78.9% net revenue interest.
Mary Bullard Property - Texas
We acquired the Mary Bullard Property in August 2017 for a cash consideration of approximately $50,000. The Mary Bullard Property is located in Stonewall County, about 5 ½ miles south west of Aspermont, Texas. It is bounded on the north by King County, on the east by Haskell County, on the south by Fisher and Jones Counties, and on the west by Kent County. The asset is situated on the Eastern Shelf of the Midland Basin in the central part of the North Central Plains. The Mary Bullard Property covers 241 acres held by production and is productive in the Clearfork formation at a depth of approximately 3,200 feet. There is currently one producing well, four shut-in wells, and two water injection wells. We hold a 100% working interest in the Mary Bullard Property and a 78.625% net revenue interest.
West Henshaw Property - New Mexico
The West Henshaw Property is located in Eddy County, New Mexico, 12 miles northeast of Loco Hills in the Delaware Basin. Eddy County is in Southeast New Mexico. It is bounded by Chaves County to the north, Otero County to the east, Loving County, Texas to the south, and Lea County to the west. The West Henshaw Property covers 1,880 acres held by production. There are two producing wells, seven shut-in wells and four saltwater disposal wells. We hold a 100% working interest in the West Henshaw Property and a 72% net revenue interest.
In January 2022, we began the pilot re-entry on the West Henshaw well #15-3, one out of the 67 shut-in wells we currently owns. The re-entry and re-stimulation involved the West Henshaw property targeting the Grayburg formation at a depth of 2,850 feet. The recompletion was successful and came online at an initial rate of 30 bopd and has stabilized at 15 bopd.
In April 2022, we began the re-entry on the West Henshaw well #6-10. The re-entry and re-stimulation involved the West Henshaw property targeting the Grayburg formation at a depth of 2,850 feet. The recompletion was successful and came online at an initial rate of 15 bopd and has stabilized at 10 bopd.
The remaining 67 shut-in wells that we plan to re-enter have potential to yield similar results increasing our total daily production solely by re-entering shut-in wells.
| 21 |
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.Oxy Yates Property - New Mexico
Composite Proved Reserve EstimatesThe 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 Economic Forecasts forLea 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,
| 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 | |||||||||||||||
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 we acquired royalty interests in 73 producing oil condensate, and gas reserveswells located in Texas 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.New Mexico for $179,095.
Conversion of Undeveloped Acreage
The Company’s process for converting undeveloped acreage to developed acreage is tied to whether there is any drilling being conducted on the acreage in question. DuringThe Company has started development and conversion of its undeveloped acreage located in Martin County, Texas. The PPC Eoff #3 well, operated by Permex Petroleum, is the fiscal year endedfirst of two permitted wells to be drilled by Permex on the 7,780 gross acre Breedlove oilfield. Drilling of the first well commenced on September 30, 2021,14, 2022. Management furthermore expects to commence lateral drilling of the well in June 2023, subject to the Company did not commence drilling on any undeveloped acreage and no undeveloped reserves were converted into proved developed reserves. The Company also did not make any investments in, or make any progress towards, converting proved undeveloped reserves to proved developed reserves duringacquiring 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.necessary financing.
An aggregate of 5,6125,083 MBO and 2,6062,136 MMCF, of the Company’s proved undeveloped reserves as of September 30, 20212022, 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 located2022. Management currently anticipates spending approximately $10 million 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 tocapital expenditures towards developing the Company’s proved undeveloped reserves from September 30, 2020during the 2023 fiscal year, subject to September 30, 2021 were as follows:the Company acquiring the necessary financing.
| 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 | ||||||||||||||||||
Financing of Proved and Probable Undeveloped Reserves
The Company currently estimates that the total cost to develop the Company’s proved undeveloped reserves of 5,612.05,083.2 MBbl of oil and 2,606.42,136.4 Mcf of natural gas as of September 30, 20212022 is $67,940,950.The$68,818,530. The Company expects to finance these capital costs through a combination of current cash on hand, debt financing through a line of credit or similar debt instrument, one or more offerings of debt or equity, and from cash generated from estimated revenues from sales of oil and natural gas produced at the Company’s wells.
The Company currently estimates that the total cost to develop the Company’s probable undeveloped reserves of 7,346.77,334.3 MBbl of oil and 10,245.810,307.1 Mcf of natural gas as of September 30, 20212022 is $102,884,900.$107,884,900. The Company expects to finance these capital costs through a combination of joint ventures, farm-in agreements, direct participation programs, one or more offerings of equity, a debt offering or entering into a line of credit, and from cash generated from estimated revenues from sales of oil and natural gas produced at the Company’s wells.
Drilling Activities
The Company did not drill any wellsdrilled one well during the last three fiscal years. As at September 30, 2021,March 31, 2023, the Company had 95held leases for 78 gross wells and 17.29 nethad leases and royalty interests in an aggregate of 102 gross productive wells with 89(including 73 wells producing oil and six wells producing natural gas, and thethat we acquired royalty interests in 2021). The Company’s gross developed acreage totaled 5,177 and net developed acreage totaled 3,942 with the following geographicproperty breakdown:
| Property | Gross Developed Acreage | Net Developed Acreage | Gross Productive Wells | Net Productive Wells | Gross Developed Acreage | Net Developed Acreage | Gross Productive Wells | Net Productive Wells | ||||||||||||||||||||||||
| Pittcock | 818 | 664.63 | 1 | 0.81 | 818 | 664.63 | 1 | 0.81 | ||||||||||||||||||||||||
| Henshaw | 1,880 | 1,353.60 | 2 | 1.44 | 1,880 | 1,353.60 | 6 | 4.32 | ||||||||||||||||||||||||
| Oxy Yates | 680 | 489.60 | 2 | 1.44 | 680 | 489.60 | 5 | 3.60 | ||||||||||||||||||||||||
| Bullard | 241 | 187.98 | 1 | 0.78 | 241 | 187.98 | 1 | 0.78 | ||||||||||||||||||||||||
| Breedlove | 1,558 | 1,246.4 | 16 | 12.80 | 1,558 | 1,246.40 | 16 | 12.80 | ||||||||||||||||||||||||
| Royalty Interest Properties | - | - | 73 | 0.01 | — | — | 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%5% of these leases have a terman expiry date that expires withinis less than two years offrom the date of this Report.
| 22 |
Results of Operations
Sales and Production
The average sales prices of the Company’s oil and gas products sold in the ninesix months ended June 30,March 31, 2023 and 2022, and the fiscal yearsyear ended September 30, 20212022 was $75.35/Boe, $79.93/Boe, and 2020$89.14/Boe, respectively. The average sales prices of the Company’s oil and gas products sold in the three months ended March 31, 2023 and 2022 was $81.16, $46.86,$69.86/Boe and $38.51,$89.20/Boe, respectively.
The Company’s net production quantities by final product sold in the ninesix months ended June 30,March 31, 2023 and 2022, and the fiscal yearsyear ended September 30, 2021 and 20202022 was 8,945.607,004.20 Boe, 1,081.545,498.85 Boe, and 20,112.4412,597.45 Boe, respectively. The Company’s net production quantities by final product sold in the three months ended March 31, 2023 and 2022 was 3,381.30 Boe and 3,500.32 Boe, respectively.
The Company’s average production costs per unit for the ninesix months ended June 30,March 31, 2023 and 2022, and the fiscal yearsyear ended September 30, 20212022, was $75.26/Boe, $35.70/Boe, and 2020,$65.82/Boe, respectively. The Company’s average production costs per unit for the three months ended March 31, 2023 and 2022 was $37.15, $27.93,$70.70/Boe and $32.59,$33.67/Boe, respectively.
The breakdown of production and prices between oil/condensate and natural gas was as follows:
| Net Production Volumes | Nine Months Ended June 30, 2022 | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | |||||||||
| Oil/Condensate (Bbl) | 7,325 | 947 | 16,240 | |||||||||
| Natural Gas (Mcf) | 9,726 | 1,410 | 9,196 | |||||||||
| Net Production Volumes | Three Months Ended March 31, 2023 | Three Months Ended March 31, 2022 | Six Months Ended March 31, 2023 | Six Months Ended March 31, 2022 | ||||||||||||
| Oil/Condensate (Bbl) | 3,026 | 3,105 | 6,567 | 4,379 | ||||||||||||
| Natural Gas (Mcf) | 2,134 | 2,370 | 2,621 | 6,717 | ||||||||||||
| Average Sales Price | Nine Months Ended June 30, 2022 | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | |||||||||
| Oil/Condensate ($/Bbl) | 92.07 | 58.36 | 41.09 | |||||||||
| Natural Gas ($/Mcf) | 5.31 | 3.40 | 1.44 | |||||||||
| Average Sales Price | Three Months Ended March 31, 2023 | Three Months Ended March 31, 2022 | Six Months Ended March 31, 2023 | Six Months Ended March 31, 2022 | ||||||||||||
| Oil/Condensate ($/Bbl) | 73.64 | 95.16 | 77.88 | 88.49 | ||||||||||||
| Natural Gas ($/Mcf) | 6.28 | 7.06 | 6.22 | 7.74 | ||||||||||||
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 | Nine Months Ended June 30, 2022 | Fiscal Year Ended September 30, 2021 | Fiscal Year Ended September 30, 2020 | |||||||||
| Oil/Condensate (Bbl) | 4,897 | - | - | |||||||||
| Natural Gas (Mcf) | 9,726 | 419 | - | |||||||||
| Net Production Volumes | Three Months Ended March 31, 2023 | Three Months Ended March 31, 2022 | Six Months Ended March 31, 2023 | Six Months Ended March 31, 2022 | ||||||||||||
| Oil/Condensate (Bbl) | 1,962 | 1,856 | 4,573 | 2,788 | ||||||||||||
| Natural Gas (Mcf) | 2,134 | 2,370 | 2,621 | 6,717 | ||||||||||||
Henshaw
| Net Production Volumes | Three Months Ended March 31, 2023 | Three Months Ended March 31, 2022 | Six Months Ended March 31, 2023 | Six Months Ended March 31, 2022 | ||||||||||||
| Oil/Condensate (Bbl) | 723 | 762 | 1,488 | 762 | ||||||||||||
| Natural Gas (Mcf) | - | - | - | - | ||||||||||||
Pittcock & Mary Bullard
| Net Production Volumes | Three Months Ended March 31, 2023 | Three Months Ended March 31, 2022 | Six Months Ended March 31, 2023 | Six Months Ended March 31, 2022 | ||||||||||||
| Oil/Condensate (Bbl) | 340 | 488 | 507 | 829 | ||||||||||||
| Natural Gas (Mcf) | - | - | - | - | ||||||||||||
Henshaw
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ODC San Andres
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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 (“HBP”) 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 (“SWD”) and 9 that are shut-in opportunities. Permex holds a 100% working interest and an 81.75% net revenue interest in the Breedlove “B” Clearfork Property.
Pittcock Leases - Texas
The Pittcock Leases are situated in Stonewall County. Stonewall County is in Northwest Texas, in the central part of the North Central Plains and consist of the Pittcock North property, the Pittcock South property and the Windy Jones Property.
The Pittcock North property covers 320 acres held by production. There is currently one producing well, ten shut-in wells, two saltwater disposal wells, and a water supply well. Permex holds a 100% working interest in the Pittcock North Property, and an 81.25% net revenue interest.
The Pittcock South property covers 498 acres in four tracts. There are currently 19 shut-in wells and two saltwater disposal wells. Permex holds a 100% working interest in the lease, and a 71.90% net revenue interest.
The Windy Jones Property consists of forty acres and includes two injection wells and two suspended oil wells. The sole purpose of the Windy Jones property is to provide waterflood to the offset wells being the Pittcock wells located east boundary of the Windy Jones property. Permex holds a 100% working interest in the Windy Jones Property, and a 78.9% net revenue interest.
Mary Bullard Property - Texas
The Mary Bullard Property is located in Stonewall County, about 5 ½ miles south west of Aspermont, Texas. The asset is situated on the Eastern Shelf of the Midland Basin in the central part of the North Central Plains. The Mary Bullard Property covers 241 acres held by production and is productive in the Clearfork formation at a depth of approximately 3,200 feet. There is currently one producing well, four shut-in wells, and two water injection wells. Permex holds a 100% working interest in the Mary Bullard Property, and a 78.625% net revenue interest.
West Henshaw Property and Oxy Yates Property - New Mexico
The West Henshaw Property is located in Eddy County, New Mexico, 12 miles northeast of Loco Hills in the Delaware basin. Eddy County is in Southeast New Mexico. It is bounded by Chaves County to the north, Otero County to the east, Loving County, Texas to the south, and Lea County to the west. The West Henshaw Property covers 1,880 acres held by production. There are two producing wells, seven shut-in wells and four saltwater disposal wells. Permex holds a 100% working interest in the West Henshaw Property, and a 72% net revenue interest.
The Oxy Yates Property is located in Eddy County, approximately eight miles north of Carlsbad, New Mexico in the Delaware Basin. The Oxy Yates Property covers 680 acres held by production. There is one producing well and nine shut-in wells. The Yates formation is located at an average depth of 1,200 feet and overlies the Seven River formation and underlies the Tansill formation. Permex holds a 100% working interest in the Oxy Yates Property, and a 77% net revenue interest.
Discussion of Operations
Summary Of QuarterlyOperating Results
The following table sets forth selected unaudited financial information for the Company’s eight most recent quarters ending with the last quarter for the three month period ended June 30, 2022.
| For the Three Months Ended | ||||||||||||||||||||||||||||||||
| Fiscal 2022 | Fiscal 2021 | Fiscal 2020 | ||||||||||||||||||||||||||||||
| Jun. 30, 2022 | Mar. 31, 2022 | Dec. 31, 2021 | Sept. 30, 2021 | Jun. 30, 2021 | Mar. 31, 2021 | Dec. 31, 2020 | Sept. 30, 2020 | |||||||||||||||||||||||||
| ($) | ($) | ($) | ($) | ($) | ($) | ($) | ($) | |||||||||||||||||||||||||
| Total revenues | 276,722 | 241,886 | 106,449 | 9,575 | 34,298 | 40 | 2,790 | 135,215 | ||||||||||||||||||||||||
| Net income (loss) | (761,303 | ) | (144,944 | ) | (822,765 | ) | (784,742 | ) | (152,960 | ) | (196,023 | ) | (111,332 | ) | (1,087,376 | ) | ||||||||||||||||
| Earnings (loss) per share - basic and diluted | (0.01 | ) | (0.00 | ) | (0.01 | ) | (0.02 | ) | (0.00 | ) | (0.00 | ) | (0.00 | ) | (0.03 | ) | ||||||||||||||||
Three month period ended June 30,Months Ended March 31, 2023 and 2022
During the three months ended June 30, 2022,March 31, 2023, the Company reported a net loss of $761,303$1,111,323 as compared to a net loss of $152,960$157,928 for the three months ended June 30, 2021March 31, 2022 mostly as a result of increased revenues being more than offset by increased expenses during the thirdsecond quarter of 20222023 compared to the same quarter in 2021. Revenue for the third quarter of 2022 consisted of2022.
The Company reported oil and gas sales revenue of $258,757 (compared to $34,298$170,989 in revenues from oil and gas sales in the third quarter of 2021) and royalty income of $17,965 (compared to no royalty income in the third quarter of 2021). Revenue from the Company’s newly acquired Breedlove “B” Clearfork leases accounted for 75% of the total oil and gas sales in the third quarter of 2022. The direct producing expenses were $135,170 in the third quarter of 2022 compared to $11,179 in the third quarter of 2021, representing approximately 52% and 33% of the gross sales in the third quarters of 2022 and 2021, respectively. This increase in producing expenses in the third quarter of 2022 was the result of increased production in 2022 compared to 2021 mostly as a result of the Company’s acquisition of the Breedlove “B” Clearfork leases in September 2021, and the Company bringing the Pittcock North, Mary Bullard, and West Henshaw wells back online during the second quarter of 2022. For the three-month period ended June 30, 2022,current fiscal year compared with revenue of $228,497 in the Company has produced 37same quarter during the last fiscal year. The decrease was mainly due to the decrease in oil and gas prices in the current quarter to $69.86/Boe from $89.20/Boe in the comparative quarter. Net oil-equivalent production by final product sold in the current quarter average 37.57 barrels of oil per day, (“bopd”) compared to six bopd forwith 38.47 barrels per day in the same quarter of 2021.the previous fiscal year.
The Company’s total operating expenses for the three months ended June 30, 2022March 31, 2023 was $1,278,251$1,297,061 compared to $177,861$388,117 for the same period in 2021.2022. The increase in total operating expenses in the thirdsecond quarter of 20222023 compared to the thirdsecond quarter of 20212022 was mainly attributable to increased general and administrative expenses in the current quarter including accounting and audit fees of $77,673 in the third quarter$202,557 (2022 - $51,280), insurance of 2022 (compared to $16,783 in third quarter of 2021)$122,695 (2022 - $1,220), legal fees of $179,190 in the third quarter of 2022 (compared to $2,666 in the third quarter of 2021)$114,358 (2022 - $18,266), and marketing and promotion of $469,096 in the third quarter$177,905 (2022 - $18,366), and salaries of 2022 (compared to $4,148 in the third quarter of 2021)$108,544 (2022 - $59,393). The increase in general administrative expenses in the current quarter is mainly due to the increase in oil and gas production and development and general corporate activities as a result of the increased oil and gas productions, the brokered financing completed incompared to the second quarter of 2022, and the preparation and filing of the Registration Statement and all required amendments with the SEC.2022.
Nine month period ended June 30,Six Months Ended March 31, 2023 and 2022
During the ninesix months ended June 30, 2022,March 31, 2023, the Company reported a net loss of $1,729,012$2,420,514 as compared to a net loss of $460,316$909,116 for the ninesix months ended June 30, 2021 mostly as a result of increased revenues in 2022 being more than offset by increased expenses duringMarch 31, 2022. The net loss for the first nine monthshalf of 2022current fiscal year was mainly attributable to operating expenses of $2,856,346 compared to operating expenses of $1,324,836 in the same period in 2021. Revenue forthe previous fiscal year, being partially offset by revenue from oil and gas sales and royalty income of $402,580 compared to $348,335 in the fiscal 2022 period.
The Company reported oil and gas sales revenue of $384,743 in the first nine monthshalf of 2022 consistedthe current fiscal year compared with revenue of $318,487 in the same period during the last fiscal year. The increase was mainly due to revenue generated from sales of oil and gas salesextracted from our Breedlove “B” Clearfork properties, which accounted for 73% of $577,244 (compared to revenues of $37,392 forthe Company’s oil and gas sales in the first nine months of 2021) and royalty income of $47,813 (compared to no royalty income the first nine months of 2021). Revenue from the Company’s newly acquired Breedlove “B” Clearfork leases accounted for 71% of the Company’s total oil and gas sales in the third quarter of 2022.current quarter. The Company also brought Pittcock North, Mary Bullard, and West Henshaw wells back online during the second quarter of the last fiscal year. Net oil-equivalent production by final product sold in the current period average 38.48 barrels per day, compared with 30.05 barrels per day in the same quarter of the previous fiscal year.
The production expenses for the six months ended March 31, 2023 were $527,157 compared with $196,879 in the six months ended March 31, 2022. ForThe increase was mostly due to the nine-monthincrease in production in the current fiscal period ended June 30, 2022, the Company produced 33 bopd compared to two bopd for the same period in 2021. The Company’s direct producingthe previous fiscal year combined with increased maintenance expenses were $332,346 inon the first nine months of 2022 compared to $21,392 for the same period in 2021, representing approximately 52% and 57% of the gross sales for the first nine months of 2022 and 2021, respectively. This increase in producing expenses in the first nine months of 2022 was the result of increased production in 2022 compared to 2021 mostly as a result of the Company’s acquisition of the Breedlove “B” Clearfork leases and the Company bringing the Pittcock North, Mary Bullard, and West Henshaw wells back online.wells.
The Company’s total operatinggeneral and administrative expenses excluding share-based payment expenses for the nine month periodsix months ended June 30, 2022March 31, 2023 were $2,225,331, compared with $409,296 in the six months ended March 31, 2022. The increase was $2,603,752 comparedmainly due to $423,522 forthe increase in property development and corporate activities in general during in the current fiscal period. Specifically, the variance in the first six months of the current fiscal year from the same period in 2021. The increase in total operating expenses in the first nine months of 2022 compared to the same period in 2021previous fiscal year was mainly attributable to increased general and administrative expenses in the current period including:to:
| ● | Accounting and audit fees of $522,178, which increased |
| ● | Consulting fees of $142,875 in the current period compared to $16,773 in the same period of the previous fiscal year, which in |
| ● | Investor relations and marketing expenses |
| ● | Legal fees |
| ● |
The Company also incurred share-based compensation expenses of $604,861 in the first nine months of 2022 compared to $2,401 in the same period of 2021, mostly as a result of the Company granting 3,300,000 stock options to the Company’s directors and consultants in October 2021. Share-based compensation expenses are a non-cash charge that are the estimated fair value of the stock options granted and vested during the period. The Company used the Black-Scholes option pricing model for the fair value calculation.
Liquidity and Capital Resources
As at June 30, 2022,March 31, 2023, the Company had a cash balance of $5,366,789, an increase$176,366, a decrease of $5,340,983$3,124,129 from the cash balance of $25,806$3,300,495 on September 30, 2021.2022. During the ninesix months ended June 30, 2022,March 31, 2023, cash used in operating activities was $1,420,285, primarily related to cash used in connection with an increase in net loss during 2022 combined with an increase in prepaid expenses and deposits being partially offset by cash provided by increased trade and other payables.$1,917,629. The Company used $202,136 of cashinvested $1,168,209 in investing activities as a result of capital expenditures on its oil and gas assets. Financing activities providedassets in the Company with cash of $6,963,404 mostly as a resultfirst half of the current fiscal year, compared to $90,219 invested in the comparative six months of the previous fiscal year. The Company receiving net proceeds of $7,032,412 from private placement financings, being partially offset by $41,661 of cash used for office lease payments and the repaymentalso repaid $38,291 of a loan using $23,700 of cash.debenture loan.
The Company had a working capital deficiency of $5,182,233$2,233,765 as at June 30, 2022March 31, 2023 compared to a working capital deficiency of $465,129$2,051,127 as at September 30, 2021.2022.
Management has currently budgeted approximately $10 million in capital expenditures for the 2023 fiscal year, which we plan to finance principally from one or more equity financings and/or a line or credit. The amount and timing of capital expenditures will depend on several factors including, but not limited to, the speed with which we are able to drill and complete our wells, our ability to complete an equity financing or to secure a suitable line of credit, commodity prices, supply/demand considerations and attractive rates of return. There are no guarantees that we will be able to acquire the necessary funds to meet our budgeted capital expenditures, and any postponement of our planned development of our proved undeveloped reserves could materially affect our business, financial condition and results of operations.
Although the Company expects to investhas budgeted investments of additional capital onin the continued development of itsour oil and gas operations, the Company currently does not have any material commitments for capital expenditures. AsHowever, as of both June 30, 2022 and the date of thisour Quarterly Report on Form 10-Q for the six months ended March 31, 2023, the Company believes it hasdoes not have sufficient working capital to meet its anticipated operating and capital requirements over the next 12 months.months and, consequently, the Company is currently evaluating options to support its funding requirements over this time period, including but not limited to, completing a financing transaction. The Company will also continue to monitor the current economic and financial market conditions and evaluate their impact on the Company’s liquidity and future prospects.
Critical Accounting Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amount of assets and liabilities at the date of the financial statements and the reported amount of revenue and expenses during the reporting period. Management evaluates these estimates and judgments on an ongoing basis and bases its estimates on experience, current and expected future conditions, third-party evaluations and various other assumptions that management believes are reasonable under the circumstances. Significant estimates have been used by management in conjunction with the following: (i) 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)(ii) the costs of site restoration when determining decommissioning liabilities; (iv) income taxes receivable or payable; (v)(iii) the useful lives of assets for the purposes of depletion and depreciation; (vi)(iv) petroleum and natural gas reserves; and (vii)(v) share-based payments. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, and makes adjustments when facts and circumstances dictate. These estimates are based on information available as of the date of the financial statements; therefore, actual results could differ from those estimates.
| 25 |
JOBS Act
On April 5, 2012, the Jumpstart Our Business StartupsJOBS Act of 2012 (the “JOBS Act”) was enacted. Section 107 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an “emerging growth company” can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies.
We have chosen to take advantage of the extended transition periods available to emerging growth companies under the JOBS Act for complying with new or revised accounting standards until those standards would otherwise apply to private companies provided under the JOBS Act. As a result, our financial statements may not be comparable to those of companies that comply with public company effective dates for complying with new or revised accounting standards.
Subject to certain conditions set forth in the JOBS Act, as an “emerging growth company,” we intend to rely on certain of these exemptions, including, without limitation, (i) providing an auditor’s attestation report on our system of internal controls over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002, as amended, and (ii) complying with any requirement that may be adopted by the Public Company Accounting Oversight Board regarding mandatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit and the financial statements, known as the auditor discussion and analysis. We will remain an “emerging growth company” until the earliest of (i) the last day of the fiscal year in which we have total annual gross revenues of $1.07 billion or more; (ii) the last day of our fiscal year following the fifth anniversary of the date of our initial public offering; (iii) the date on which we have issued more than $1 billion in nonconvertible debt during the previous three years; or (iv) the date on which we are deemed to be a large accelerated filer under the rules of the SEC.
| ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The Company is not required to provide the information required by this Item as it is a “smaller reporting company,” as defined in Rule 12b-2 of the Exchange Act.
| ITEM 4. | CONTROLS AND PROCEDURES. |
| Evaluation of disclosure controls and procedures |
We maintain disclosure controls and procedures (as such terms are defined under Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) that are designed to ensure that the information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b) as of the end of the period covered by this Report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of June 30, 2022.March 31, 2023.
The following control deficiencies constitute material weaknesses in internal control over financial reporting:
| Insufficient resources resulting in | ||
| ● | Lack of knowledge of US GAAP and ineffective controls associated with the conversion from IFRS to US GAAP | |
| ● | Ineffective controls over inputs used in the valuation of the Asset Retirement Obligation | |
| ● | Ineffective controls on the accounting and the valuation of complex financial instruments | |
| ● | Ineffective review of the financial statements due to the limited financial and reporting resources | |
| ● | Ineffective information technology general controls in the areas of user access and program change-management over certain information technology systems that support the Company’s financial reporting processes. |
Changes in internal controls
There were no changes in our internal controls over financial reporting during the three months ended June 30, 2022March 31, 2023 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
Limitations on Effectiveness of Controls and Procedures
In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.
PART II – OTHER INFORMATION
| ITEM 1. | LEGAL PROCEEDINGS |
We may be involved from time to time in various claims and legal actions arising in the ordinary course of business, including proceedings involving employee claims, contract disputes, product liability and other general liability claims, as well as trademark, copyright, and related claims and legal actions. We are not currently a party to any material legal proceedings and we are not aware of any pending or threatened legal proceeding against us that we believe could have a material adverse effect on our business, operating results, cash flows or financial condition.
| ITEM 1A | RISK FACTORS |
You should carefully considerThere have been no material changes to the following risk factors that may affectdisclosed in Item 1A. Risk Factors in our business, including our financial condition and results of operations. The risks and uncertainties described below are notannual report on Form 10-K for the only risks we face. Additional risks and uncertainties not presently known to us or that we currently deem immaterial also may impair our business. If any of the following risks actually occur, our business could be harmed, and the trading price of our common shares could decline.
Risks Related to Our Financial Position and Need for Capitalfiscal year ended September 30, 2022.
If we fail to obtain the capital necessary to fund our operations, we will be unable to continue our operations.
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 amounts we have raised to date may not be sufficient to meet our future needs and may be dilutive to our current shareholders. If adequate funds are not available on acceptable terms, or at all, our business, including our results of operations, financial condition and our continued viability will be materially adversely affected.
We have a limited operating history.
We have a limited operating history and our business is subject to all of the risks inherent in the establishment of a new business enterprise. Our likelihood of success must be considered in light of the problems, expenses, difficulties, complications and delays frequently encountered in connection with development and expansion of a new business enterprise. If we are unable to achieve profitability, we may be unable to continue our operations.
Our indebtedness could adversely affect our ability to raise additional capital to fund operations.
We currently have one outstanding secured convertible debenture in the original principal amount of $79,000 (CAD$100,000) (excluding interest accrued thereon) issued to Mehran Ehsan, our Chief Executive Officer, President and director, which is secured by all of our right, title and interest in the Properties (as defined in the Security Agreement between us the Mehran Ehsan dated February 21, 2020) together with all engineering reports and intellectual property related to, or generated by us, in connection with the Properties (collectively, the “Collateral”). The secured debenture remains outstanding as of the date of this Report.
If we cannot generate sufficient cash flow from operations to service our debt, we may need to, among other things, dispose of some or all of the Collateral or issue equity to obtain necessary funds. We do not know whether we will be able to do any of this on a timely basis, on terms satisfactory to us, or at all. Our indebtedness could have important consequences, including:
Risks Related to Our Business
Oil and gas prices are volatile, and declines in prices may adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.
The prices we receive for our oil and natural gas production heavily influence our revenue, operating results, profitability, access to capital, future rate of growth and carrying value of our properties. Oil and natural gas are commodities, and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand, as well as costs and terms of transport to downstream markets.
Historically, the commodities markets have been volatile, and these markets will likely continue to be volatile in the future. If the prices of oil and natural gas experience a substantial decline, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control and include the following:
Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.
Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for oil and, to a lesser extent, natural gas that we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In addition, we may need to record asset carrying value write-downs if prices fall. A significant decline in the prices of natural gas or oil could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.
The actual quantities and present value of our proved oil, gas, and NGL reserves may be less than we have estimated.
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their value. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Because of the high degree of judgment involved, the accuracy of any reserve estimate is inherently imprecise, and a function of the quality of available data and the engineering and geological interpretation. Our reserves estimates are based on 12-month average prices, except where contractual arrangements exist; therefore, reserves quantities will change when actual prices increase or decrease. In addition, results of drilling, testing, and production may substantially change the reserve estimates for a given reservoir over time. The estimates of our proved reserves and estimated future net revenues also depend on a number of factors and assumptions that may vary considerably from actual results, including:
For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of those reserves and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserves estimates may be subject to upward or downward adjustment, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates.
Additionally, because some of our reserves estimates are calculated using volumetric analysis, those estimates are less reliable than the estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure. In addition, realization or recognition of proved undeveloped reserves will depend on our development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.
Our acquisition strategy may subject us to certain risks associated with the inherent uncertainty in evaluating properties.
Although we perform a review of properties that we acquire that we believe is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in-depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher-value properties and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us as a buyer to become sufficiently familiar with the properties to assess fully and accurately their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future production rates and costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates. In addition, there can be no assurance that acquisitions will not have an adverse effect upon our operating results, particularly during the periods in which the operations of acquired businesses are being integrated into our ongoing operations.
We may be unable to successfully integrate recently acquired assets or any assets we may acquire in the future into our business or achieve the anticipated benefits of such acquisitions.
Our ability to achieve the anticipated benefits of our acquisitions will depend in part upon whether we can integrate the acquired assets into our existing business in an efficient and effective manner. We may not be able to accomplish this integration process successfully. The successful acquisition of producing properties requires an assessment of several factors, including:
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we have performed reviews of the subject properties that we believe to be generally consistent with industry practices. The reviews are based on our analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines without review by an independent petroleum engineering firm. Data used in such reviews are typically furnished by the seller or obtained from publicly available sources. Our review may not reveal all existing or potential problems or permit us to fully assess the deficiencies and potential recoverable reserves for all of the acquired properties, and the reserves and production related to the acquired properties may differ materially after such data is reviewed by an independent petroleum engineering firm or further by us. Inspections will not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or a portion of the underlying deficiencies. The integration process may be subject to delays or changed circumstances, and we can give no assurance that our acquired assets will perform in accordance with our expectations or that our expectations with respect to integration or cost savings as a result of such acquisitions will materialize.
Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations.
Our drilling activities are subject to many risks, including the risk that they will not discover commercially productive reservoirs. Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, drilling and producing operations on our acreage may be curtailed, delayed or canceled as a result of other factors, including:
In addition to causing curtailments, delays and cancellations of drilling and producing operations, many of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.
Our future success depends on our ability to replace reserves.
Because the rate of production from oil and natural gas properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional oil and natural gas reserves. Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as our reserves are produced. Future oil and natural gas production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot assure you that we will be able to find or acquire and develop additional reserves at an acceptable cost. We may acquire significant amounts of unproved property to further our development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We seek to acquire both proved and producing properties as well as undeveloped acreage that we believe will enhance growth potential and increase our earnings over time. However, we cannot assure you that all of these properties will contain economically viable reserves or that we will not abandon our initial investments. Additionally, we cannot assure you that unproved reserves or undeveloped acreage that we acquire will be profitably developed, that new wells drilled on our properties will be productive or that we will recover all or any portion of our investments in our properties and reserves.
Our business depends on third-party transportation and processing facilities and other assets that are owned by third parties.
The marketability of our oil and natural gas depends in part on the availability, proximity, capacity and cost of pipeline and gathering systems, processing facilities, oil trucking and barging fleets and rail transportation assets as well as storage facilities owned by third parties. The lack of available capacity on these systems and facilities, whether as a result of proration, growth in demand outpacing growth in capacity, physical damage, scheduled maintenance or other reasons could result in a substantial increase in costs, declines in realized commodity prices, the shut-in of producing wells or the delay or discontinuance of development plans for our properties. In addition, our wells may be drilled in locations that are serviced to a limited extent, if at all, by gathering and transportation pipelines, which may or may not have sufficient capacity to transport production from all of the wells in the area. As a result, we rely on third-party oil trucking to transport a significant portion of our production to third-party transportation pipelines, rail loading facilities and other market access points. In addition, concerns about the safety and security of oil and gas transportation by pipeline may result in public opposition to pipeline development or continued operation and increased regulation of pipelines by the Pipeline and Hazardous Materials Safety Administration, and therefore less capacity to transport our products by pipeline. Any significant curtailment in gathering system or pipeline capacity, or the unavailability of sufficient third-party trucking or rail capacity, could adversely affect our business, results of operations and financial condition. Our contracts for downstream transportation service include those that may be adjusted on a month-to-month basis, impacting underlying economics of our production. Our downstream contract transportation counterparties include entities that are far larger than we are and have greater market share in their markets than is the case for us in our markets.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.
Approximately 92% of our estimated net proved reserves volumes were classified as proved undeveloped as of September 30, 2021. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.
Weather conditions, which could become more frequent or severe due to climate change, could adversely affect our ability to conduct drilling, completion and production activities in the areas where we operate.
Our exploration and development activities and equipment can be adversely affected by severe weather such as well freeze-offs, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. Our planning for normal climatic variation, insurance programs, and emergency recovery plans may inadequately mitigate the effects of such weather conditions, and not all such effects can be predicted, eliminated, or insured against. In addition, demand for oil and gas are, to a degree, dependent on weather and climate, which impact the price we receive for the commodities we produce. These constraints could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.
We may incur losses as a result of title defects in the properties in which we invest.
The existence of a material title deficiency can render a lease worthless. In the course of acquiring the rights to develop natural gas, we typically execute a lease agreement with payment to the lessor subject to title verification. In many cases, we incur the expense of retaining lawyers to verify the rightful owners of the gas interests prior to payment of such lease bonus to the lessor. There is no certainty, however, that a lessor has valid title to their lease’s gas interests. In those cases, such leases are generally voided and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. Prior to the drilling of a natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Accordingly, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss. Additionally, hydrocarbons or other fluids in one reservoir may migrate to another stratum or reservoir, resulting in disputes regarding ownership, the entitlement to produce, and responsibility for consequences of such migration of the fluids.
We conduct business in a highly competitive industry.
The oil and natural gas industry is highly competitive. The key areas in respect of which we face competition include: acquisition of assets offered for sale by other companies; access to capital (debt and equity) for financing and operational purposes; purchasing, leasing, hiring, chartering or other procuring of equipment that may be scarce; and employment of qualified and experienced skilled management and oil and natural gas professionals. Competition in our markets is intense and depends, among other things, on the number of competitors in the market, their financial resources, their degree of geological, geophysical, engineering and management expertise and capabilities, their pricing policies, their ability to develop properties on time and on budget, their ability to select, acquire and develop reserves and their ability to foster and maintain relationships with the relevant authorities. Our competitors also include those entities with greater technical, physical and financial resources. In some markets, our products compete with other sources of energy, or other fuels (e.g., hydroelectricity) that may from time to time become more abundant or experience decreased prices. Finally, companies and certain private equity firms not previously investing in oil and natural gas may choose to acquire reserves to establish a firm supply or simply as an investment. Any such companies will also increase market competition which may directly affect us. If we are unsuccessful in competing against other companies, our business, results of operations, financial condition or prospects could be materially adversely affected.
Decommissioning costs are unknown and may be substantial. Unplanned costs could divert resources from other projects.
We may become responsible for costs associated with plugging, abandoning and reclaiming wells, pipelines and other facilities that we use for production of oil and natural gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We accrue a liability for decommissioning costs associated with our wells, but have not established any cash reserve account for these potential costs in respect of any of our properties. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.
Fuel conservation measures, technological advances and negative shift in market perception towards the oil and natural gas industry could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices, and the increased competitiveness of alternative energy sources could reduce demand for oil and natural gas. Additionally, the increased competitiveness of alternative energy sources (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells and biofuels) could reduce demand for oil and natural gas and, therefore, our revenues.
Additionally, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Furthermore, certain other stakeholders have pressured commercial and investment banks to stop funding oil and gas projects. With the continued volatility in oil and natural gas prices, and the possibility that interest rates will rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially shale producers. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results. Some states attorneys general have accused large legacy E&P companies of purposefully obscuring consequences of combusting hydrocarbon.
The impact of the changing demand for oil and natural gas services and products, together with a change in investor sentiment, may have a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, if we are unable to achieve the desired level of capital efficiency or free cash flow within the timeframe expected by the market, our share price may be adversely affected.
Major utilities, sometimes at the instigation of states or investors, have announced plans to radically reduce emissions, or goals to achieve “net-zero” carbon emissions by deadlines as early as 2035.
Diminution of available markets (for instance by bans on the consumption of natural gas as a fuel for power plants) or prohibitions on use of natural gas in new construction as early as 2027 also may affect our markets, profitability and cash flow.
Our operations are concentrated in the Permian and Delaware Basins, making us vulnerable to risks associated with operating in a limited geographic area.
All of our producing properties are geographically concentrated in the Permian and Delaware Basins. As a result, we may be disproportionately exposed to various factors, including, among others: (i) the impact of regional supply and demand factors, (ii) delays or interruptions of production from wells in such areas caused by governmental regulation, (iii) processing or transportation capacity constraints, (iv) market limitations, (v) availability of equipment and personnel, (vi) water shortages or other drought related conditions or (vii) interruption of the processing or transportation natural gas. This concentration in a limited geographic area also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife and unexpected events that may occur in the regions such as natural disasters, seismic events, industrial accidents or labor difficulties. Any one of these factors has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expirations. Any of the risks described above could have a material adverse effect on our business, financial condition, results of operations and cash flow.
Increased attention to environmental, social and governance (“ESG”) matters may impact our business.
Increasing attention to climate change, increasing societal expectations on companies to address climate change, increasing investor and societal expectations regarding voluntary ESG disclosures, and potential increasing consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our access to capital markets. Increasing attention to climate change, for example, may result in demand shifts for natural gas and oil products and additional governmental investigations and private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our share price and our access to and costs of capital, or negative tax or other cost consequences.
Under some analyses, the world already produces more fossil fuel from existing sources than can be consumed over remaining resources service lives, if incremental global warming is to be kept under 1.5 degrees Celsius. Financing may be increasingly challenging, as pension funds (e.g., for major municipalities such as Boston, MA) and financial institutions divest fossil fuel investments.
The COVID-19 pandemic has had, and may continue to have, a material adverse effect on our financial condition and results of operations.
We face risks related to public health crises, including the COVID-19 pandemic. The effects of the COVID-19 pandemic, including travel bans, prohibitions on group events and gatherings, shutdowns of certain businesses, curfews, shelter-in-place orders and recommendations to practice social distancing in addition to other actions taken by both businesses and governments, resulted in a significant and swift reduction in international and U.S. economic activity. The collapse in the demand for oil caused by this unprecedented global health and economic crisis contributed to the significant decrease in crude oil prices in 2020 in general and resulted in shut down of our wellbores which had and could in the future continue to have a material adverse impact on our financial condition and results of operations.
Since the beginning of 2021, the distribution of COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded. However, we continue to monitor the effects of the pandemic on our operations. As a result of the ongoing COVID-19 pandemic, our operations, and those of our operating partners, have and may continue to experience delays or disruptions and temporary suspensions of operations and increased volatility. In addition, our results of operations and financial condition have been and may continue to be adversely affected by the ongoing COVID-19 pandemic.
The extent to which our operating and financial results are affected by COVID-19 will depend on various factors and consequences beyond our control, such as the emergence of more contagious and harmful variants of the COVID-19 virus, the duration and scope of the pandemic, additional actions by businesses and governments in response to the pandemic, and the speed and effectiveness of responses to combat the virus. COVID-19, and the volatile regional and global economic conditions stemming from the pandemic, could also aggravate the other risk factors that we identify herein. While the effects of the COVID-19 pandemic have lessened recently in the United States, we cannot predict the duration or future effects of the pandemic, or more contagious and harmful variants of the COVID-19 virus, and such effects may materially adversely affect our results of operations and financial condition in a manner that is not currently known to us or that we do not currently consider to present significant risks to our operations.
The loss of any member of our management team, upon whose knowledge, relationships with industry participants, leadership and technical expertise we rely could diminish our ability to conduct our operations and harm our ability to execute our business plan.
Our success depends heavily upon the continued contributions of those members of our management team whose knowledge, relationships with industry participants, leadership and technical expertise would be difficult to replace. In particular, our ability to successfully acquire additional properties, to increase our reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements depends on developing and maintaining close working relationships with industry participants. In addition, our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment is dependent on our management team’s knowledge and expertise in the industry. To continue to develop our business, we rely on our management team’s knowledge and expertise in the industry. The members of our management team may terminate their employment with our Company at any time. If we were to lose members of our management team, we may not be able to replace the knowledge or relationships that they possess and our ability to execute our business plan could be materially harmed.
We are substantially dependent on a limited number of customers.
For the years ended September 30, 2021 and 2020, we had one and one significant purchaser, respectively, that accounted for approximately 49% and 45%, respectively, of our total oil, natural gas and NGL revenues. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. Additionally, there are no assurances that we will be able to expand our customer base. If we are unable to attract and maintain an adequate customer base to generate revenues, we will have to suspend or cease operations.
Our business could be negatively affected by security threats, including cybersecurity threats and other disruptions.
As an oil and gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability.
The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for operators related to developing and operating our properties.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly water and sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, our operators rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells. If our operators are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. Shortages of drilling rigs, equipment, raw materials, supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our operators’ exploration and development operations, which in turn could have a material adverse effect on our financial condition, results of operations and free cash flow.
If we are unable to acquire adequate supplies of water for our future drilling and operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired.
We will be using a substantial amount of water in future drilling programs and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as (i) hydraulic fracturing, including, but not limited to, the use of fresh water in such operations, or (ii) disposal of waste, including, but not limited to, the disposal of produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas. Opponents of hydraulic fracturing contend that either the drilling process or the sub-surface injection of fluids, such as water and drilling fluids, as part of accessing hydrocarbons, or disposing of used injection fluids, creates or magnifies seismic disturbances, and should such contentions be given credence with regard to our Company, our operations could experience more regulation, higher costs or greater delays in accessing hydrocarbon resources, or claims of parties asserting damage arising from seismic activity. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, and all of which could have an adverse effect on our business, financial condition, results of operations and cash flows. While we intend to conduct our operations with the level of care necessary to avoid such claims, if the structural integrity of non-producing subsurface strata are impaired by hydraulic fracturing, we could face claims for damages (e.g., claims that we are producing from other geologic strata to which we do not have production rights).
Risks Related to Legal and Regulatory Matters
Our business is highly regulated and governmental authorities can delay or deny permits and approvals or change legal requirements governing our operations, including well stimulation, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and delay our implementation of, or cause us to change, our business strategy.
Our operations are subject to complex and stringent federal, state, local and other laws and regulations relating to environmental protection and the exploration and development of our properties, as well as the production, transportation, marketing and sale of our products. 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. Changing law or regulations may impact market demand for our product. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up and other remediation activities resulting from operations, subject the lessee to liability for pollution and other damages, limit or constrain operations in affected areas, and require suspension or cessation of operations in affected areas. Our efforts to limit our exposure to such liability and cost may prove inadequate and result in significant adverse effects to our results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require us to make significant capital expenditures. Such capital expenditures could adversely impact our free cash flows and our financial condition.
Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.
From time to time, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for natural gas and oil properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although these provisions were largely unchanged in the most recent federal tax legislation, certain of these changes were considered for inclusion in the proposed “Build Back Better Act” and Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. Moreover, other more general features of any additional tax reform legislation, including changes to cost recovery rules, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted in future legislation and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.
Our business involves the selling and shipping by rail of crude oil, which involves risks of derailment, accidents and liabilities associated with cleanup and damages, as well as potential regulatory changes that may adversely impact our business, financial condition or results of operations.
A portion of our crude oil production is transported to market centers by rail. Derailments in North America of trains transporting crude oil have caused various regulatory agencies and industry organizations, as well as federal, state and municipal governments, to focus attention on transportation by rail of flammable liquids. Any changes to existing laws and regulations, or promulgation of new laws and regulations, including any voluntary measures by the rail industry, that result in new requirements for the design, construction or operation of tank cars used to transport crude oil could increase our costs of doing business and limit our ability to transport and sell our crude oil at favorable prices at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, any derailment of crude oil involving crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities.
Federal and state legislative and regulatory initiatives could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Any federal or state legislative or regulatory changes with respect to hydraulic fracturing could cause us to incur substantial compliance costs or result in operational delays, and the consequences of any failure to comply could have a material adverse effect on our financial condition and results of operations.
In addition, in response to concerns relating to recent seismic events near underground disposal wells used for the disposal by injection of flowback and produced water or certain other oilfield fluids resulting from oil and natural gas activities (so-called “induced seismicity”), regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. States may, from time to time, develop and implement plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. These developments could result in additional regulation and restrictions on the use of injection wells by our operators to dispose of flowback and produced water and certain other oilfield fluids. Increased regulation and attention given to induced seismicity also could lead to greater opposition to, and litigation concerning, oil and natural gas activities utilizing injection wells for waste disposal. Until such pending or threatened legislation or regulations are finalized and implemented, it is not possible to estimate their impact on our business.
Any of the above risks could impair our ability to manage our business and have a material adverse effect on our operations, cash flows and financial position.
The adoption of climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas we produce.
Shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change and requiring agencies to review environmental actions taken by the Trump administration, as well as a memorandum to departments and agencies to refrain from proposing or issuing rules until a departmental or agency head appointed or designated by the Biden administration has reviewed and approved the rule. In November 2021, the Biden Administration released ‘The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-carbon dioxide greenhouse gas (“GHG”) emissions, such as methane and nitrous oxide. These executive orders and policy priorities may result in the development of additional regulations or changes to existing regulations, certain of which could negatively impact our financial position, results of operations and cash flows. In addition, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will take to achieve its GHG emissions targets. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. In addition, several states and geographic regions in the United States have also adopted legislation and regulations regarding climate change-related matters, and additional legislation or regulation by these states and regions, U.S. federal agencies, including the Environmental Protection Agency (“EPA”), and/or international agreements to which the United States may become a party could result in increased compliance costs for us and our customers. Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, administrative, civil or criminal fines or penalties or injunctions limiting our operations in affected areas. Moreover, multiple environmental laws provide for citizen suits which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. We consider the responsibility and costs of environmental protection and safety and health compliance fundamental, manageable parts of our business. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.
Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure and/or well construction requirements on hydraulic fracturing operations. We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and potential bans. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.
Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and potentially reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations.
We may be involved in legal proceedings that could result in substantial liabilities.
Similar to many oil and natural gas companies, we may be involved in various legal and other proceedings from time to time, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have a material adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, resolution of one or more such proceedings could result in liability, loss of contractual or other rights, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.
Legislation or regulatory initiatives intended to address seismic activity could restrict our operators’ drilling and production activities, which could have a material adverse effect on our business.
State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. For example, in 2015, the United States Geological Study identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction.
In addition, a number of lawsuits have been filed alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, in October 2014, the Texas Railroad Commission published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Texas Railroad Commission has used this authority to deny permits for waste disposal wells. In some instances, regulators may also order that disposal wells be shut in.
The adoption and implementation of any new laws or regulations that restrict our operators’ ability to use hydraulic fracturing or dispose of produced water gathered from drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring them to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.
Continuing political and social discussion of the issue of climate change has resulted in legislative, regulatory and other initiatives to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers at both the U.S. federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases through inventories, limitations and/or taxes on GHG emissions. The EPA has issued regulations for the control of methane emissions, which also include leak detection and repair requirements, for the oil and gas industry and are likely to create additional regulations regarding such matters. In November 15, 2021, the EPA proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. EPA hopes to finalize the proposed regulations by the end of 2022. Once finalized, the regulations are likely to be subject to legal challenge, and will also need to be incorporated into the states’ implementation plans, which will need to be approved by the EPA in individual rulemakings that could also be subject to legal challenge. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to our operations. Future additional federal GHG regulations of the oil and gas industry remain a significant possibility. Some states have imposed limitations designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state initiatives to date have generally focused on the development of renewable energy standards and/or cap-and-trade and/or carbon tax programs. Renewable energy standards (also referred to as renewable portfolio standards) require electric utilities to provide a specified minimum percentage of electricity from eligible renewable resources, with potential increases to the required percentage over time. The development of a federal renewable energy standard, or the development of additional or more stringent renewable energy standards at the state level, or continuing implementation of increasingly disadvantageous (from our industry’s perspective) renewable energy requirements embedded in existing legislation could reduce the demand for oil and gas, thereby adversely impacting our earnings, cash flows and financial position. A cap-and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. A federal cap and trade program or expanded use of cap and trade programs at the state level could impose direct costs on us through the purchase of allowances and could impose indirect costs by incentivizing consumers to shift away from fossil fuels. In addition, federal or state carbon taxes could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels.
In addition, opponents of fossil fuels claiming concern about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in an increasing number of financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this would make it more difficult and expensive to secure funding for exploration and production activities. Members of the investment community have also begun to screen companies such as ours for sustainability performance, including practices related to GHGs and climate change, before investing in our common shares. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable in order to improve our sustainability performance and to meet the specific requirements to perform services for certain customers.
These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations, which could require us to incur costs to reduce emissions of GHGs associated with our operations. Limitations on GHG emissions could also adversely affect demand for oil and gas, which could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity.
Some of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions we or other operators may take when drilling, completing, or operating wells that we or they own.
Some of our properties are in reservoirs that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations by us or other operators could cause depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells by us or other operators could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.
Risks Related to our Common Shares
The market price of our common shares is volatile and may not accurately reflect the long term value of our Company.
Securities markets have a high level of price and volume volatility, and the market price of securities of many companies has experienced substantial volatility in the past. This volatility may affect the ability of holders of our common shares to sell their securities at an advantageous price. Market price fluctuations in our common shares may be due to our operating results, failing to meet expectations of securities analysts or investors in any period, downward revision in securities analysts’ estimates, adverse changes in general market conditions or economic trends, acquisitions, dispositions, or other material public announcements by us or our competitors, along with a variety of additional factors. These broad market fluctuations may adversely affect the market price of our common shares. Financial markets have historically, at times, experienced significant price and volume fluctuations that have particularly affected the market prices of equity securities of companies and that have often been unrelated to the operating performance, underlying asset values, or prospects of such companies.
Accordingly, the market price of our common shares may decline even if our operating results, underlying asset values, or prospects have not changed. Additionally, these factors as well as other related factors may cause decreases in asset values that are deemed to be other than temporary, which may result in impairment losses. There can be no assurance that continuing fluctuations in the price and volume of our common shares will not occur. If such increased levels of volatility and market turmoil continue, our operations could be adversely impacted and the trading price of our common shares may be materially adversely affected.
There is no assurance that an investment in our common shares will earn any positive return.
There is no assurance that an investment in our common shares will earn any positive return. An investment in our common shares involves a high degree of risk and should be undertaken only by investors whose financial resources are sufficient to enable them to assume such risks and who have no need for immediate liquidity in their investment. An investment in our common shares is appropriate only for investors who have the capacity to absorb a loss of some or all of their investment.
We have never paid cash dividends and have no plans to pay cash dividends in the future.
Holders of our common shares are entitled to receive such dividends as may be declared by our board of directors. To date, we have paid no cash dividends on our capital stock and we do not expect to pay cash dividends in the foreseeable future. We intend to retain future earnings, if any, to provide funds for operations of our business. Therefore, any return investors in our capital stock may have will be in the form of appreciation, if any, in the market value of their common shares.
There is a limited market for our common shares.
Our common shares are listed for trading on the Canadian Securities Exchange and the Frankfurt Stock Exchange and are quoted over-the-counter in the United States on the OTCQB of the OTC Markets Group, Inc. The over-the-counter markets provide less liquidity than U.S. national securities exchanges, such as the New York Stock Exchange or Nasdaq. Accordingly, a market for our common shares may become highly illiquid and holders of our common shares may be unable to sell or otherwise dispose of their common shares at desirable prices or at all.
Outstanding and future issuances of debt securities, which would rank senior to our common shares upon bankruptcy or liquidation, may adversely affect the level of return holders of common shares may be able to receive. In the future, we may increase our capital resources by offering additional debt securities. Upon bankruptcy or liquidation, holders of our debt securities and lenders would receive distributions of our available assets prior to any distributions being made to holders our common shares. As our decision to issue debt securities or borrow money from lenders will depend in part on market conditions, we cannot predict or estimate the amount, timing, or nature of any such future offerings or borrowings. Holders of our common shares must bear the risk that current and future securities including the issuance of debt securities may adversely affect the level of return, if any, that the holders of our common shares may receive.
We may need to raise additional funds to support our business operations or to finance future acquisitions, including through the issuance of equity or debt securities, which could have a material adverse effect on our ability to grow our business, and may dilute your ownership in us.
If we do not generate sufficient cash from operations or do not otherwise have sufficient cash and cash equivalents to support our business operations or to finance future acquisitions, we may need raise addition capital through the issuance of debt or equity securities. We do not have any arrangements for any credit facility, or any other sources of capital. We may not be able to raise cash in future financing on terms acceptable to us, or at all.
Financings, if available, may be on terms that are dilutive to our shareholders, and the prices at which new investors would be willing to purchase our securities may be lower than the current price of our common shares. The holders of new securities may also receive rights, preferences or privileges that are senior to those of existing holders of our common shares. If new sources of financing are required but are insufficient or unavailable, we would be required to modify our plans to the extent of available funding, which could harm our ability to grow our business.
We have issued options, warrants and a convertible debenture and may continue to issue additional securities in the future. The exercise and/or conversion of these securities and the sale of the common shares issuable thereunder may dilute your percentage ownership interest and may also result in downward pressure on the price of our common shares.
As of August 26, 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 (CAD$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 share price may be more volatile.
| ITEM 6. | EXHIBITS |
* Filed herewith.
** Furnished herewith.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PERMEX PETROLEUM CORPORATION | ||
| Date: | By: | /s/ Mehran Ehsan |
| Mehran Ehsan | ||
Chief Executive Officer Signing on behalf of the registrant and as Principal Executive Officer | ||