Trio Petroleum Corp
For the period ended Apr 30, 2025. Filed Jun 10, 2025.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Apr 30, 2025 · Filed Jun 10, 2025
TPET$1.52+1.3%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2025-01-31; filed 2025-03-14.
0001493152-25-010362
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2025-04-30; filed 2025-06-10.
0001641172-25-014516
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 103 previous paragraphs and 123 current paragraphs.
52 unchanged; 31 reworded; 35 added; 18 removed; 2 previous and 5 current paragraphs rearranged.
Tables are not compared: 5 previous and 8 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (35)
Current report
Our Canadian project has the potential through workovers to double production which we immediately began planning following closing. Novacor, whom we acquired the project from, is one of the lowest cost operators with lift costs of $10 per barrel. Our focus remains on acquiring projects that generate immediate cash flow or offer transformative growth potential with strategic investment.
Current report
Initially, California was a significant part of our geographic focus; however, due to rising drilling costs and the negative impact on potential profitability, we have strategically shifted our efforts beyond California to pursue more economically viable opportunities. This transition is reflected in our acquisition of an interest in the Asphalt Ridge Project in Uintah County, Utah, as well as our recent acquisition of additional oil and gas assets in the prolific Lloydminster, Saskatchewan heavy oil region.
Current report
The acquired assets included six oil wells, a water-disposal well, a steam generator, boiler, storage tanks, and various operational infrastructure. While initial production was restarted on February 22, 2024, we have subsequently determined that under previously negotiated terms, natural gas prices and water disposal costs, particularly in California, makes it cost prohibitive for the Company to employ cyclic-steam operations to increase production and will not be economically feasible in the long run. On May 27, 2025, we executed a termination agreement with Trio LLC to end operations at the location and abandon all related leases. Capitalized costs totaling $500,614 have been written off and expensed in the statement of operations for the period ended April 30, 2025.
Current report
On December 29, 2023, the Company and HSO entered into an Amendment to the Asphalt Ridge Option Agreement, under which the Company funded $200,000 in exchange for an immediate 2% working interest in the initial 960 acres. An additional $25,000 was funded in January 2024, increasing the Company’s working interest to 2.25%. While the Company had the option to acquire an additional 17.75% working interest, it has decided not to exercise this option and will instead retain its existing 2.25% working interest in the initial 960 acres.
Current report
Novacor Asset Purchase Agreement
Current report
As of April 4, 2025, we entered into an Asset Purchase Agreement (the “APA”) with Trio Petroleum Canada, Corp., an Alberta, Canada corporation and a wholly owned subsidiary of the Company (“Trio Canada”), and Novacor Exploration Ltd., a corporation incorporated under the Canada Business Corporations Act (“Novacor”), pursuant to which, subject to the terms and conditions set forth in the APA, Trio Canada agreed to acquire certain assets of Novacor relating its oil and gas business, including certain contracts, leases and permits for working interests in petroleum and natural gas and mineral rights located in the Lloydminster, Saskatchewan heavy oil region in Canada (collectively, the “Novacor Assets”), free and clear of any liens other than certain specified liabilities of Novacor that are being assumed (collectively, the “Liabilities” and such acquisition of the Novacor Assets and assumption of the Liabilities together, the “Novacor Acquisition”) for a total purchase price of (i) US$650,000, in cash, US$65,000 of which was previously provided as a deposit to Novacor, and (ii) the issuance to Novacor of 526,536 shares of common stock of common stock (the “Novacor Shares”). The Novacor Acquisition was consummated in two closings, which was completed on May 22, 2025. All five of our currently active wells are in the newly acquired Novacor property
Current report
P.R. Spring Letter of Intent and Option
Current report
On May 15, 2025, the Company entered into a non-binding Letter of Intent (LOI) with Heavy Sweet Oil LLC (“HSO”) for the potential acquisition of 2,000 acres of oil and gas properties at P.R. Spring, Uintah Basin, Utah (“P.R. Spring”), which is adjacent to Asphalt Ridge. The LOI contemplates our issuance of 1,492,272 restricted shares of common stock and the payment of $850,000 at closing, subject to execution of definitive agreements. Upon signing the LOI, we made a non-refundable $150,000 payment to HSO in consideration for the option. The LOI requires evidence of a minimum sustained production rate of 40 barrels per day for a continuous 30-day period from two wells at Asphalt Ridge by May 15, 2026, or the LOI will expire unless extended by us. We are not under any obligation to enter into definitive agreements in connection with an acquisition.
Current report
Factors and Trends Affecting Our Business and Results of Operations
Current report
We are mindful of global economic trends and their potential influence on commodity prices. Recent fluctuations in global oil prices, political considerations and tariffs can impact cash flow and ultimately profitability. Mitigating factors include our relatively low lift costs and a continued commitment to cost management and efficient production techniques. Our ability to continue to grow our business will in large part depend on continued access to receptive capital markets.
Current report
Revenues, net decreased for the three months ended April 30, 2025 by approximately $50,000 as compared to the prior period; revenues from the prior period were from the sale of approximately 2,100 barrels of oil from our McCool Ranch field, which operations were terminated in May 2025. Current revenues are the sale of approximately 550 barrels of oil from our recently acquired assets in the Lloydminster, Saskatchewan region.
Current report
General and administrative expenses decreased for the three months ended April 30, 2025 by approximately $0.7 million as compared to the prior period due to (i) a decrease in advertising and marketing fees of approximately $235,000, (ii) decreased legal fees of approximately $165,000 and (iii) decreased salaries and wages of approximately $245,000, respectively.
Current report
For the three months ended April 30, 2025, other expenses, net decreased by approximately $1.4 million when compared to the prior year period. This decline was primarily driven by (i) an approximate $1.0 million reduction in non-cash interest expense resulting from lower debt levels in the current period (non-cash interest expense is recognized as debt discounts on financings are amortized), as well as (ii) an approximate $1.1 million loss on a note conversion recorded in the prior period, which stemmed from principal payments made via conversion shares under the October 2023 Securities Purchase Agreement. These reductions were partially offset by a $0.6 million loss incurred in the current period due to the abandonment of oil and gas properties.
Current report
Revenues, net
Current report
Revenues, net decreased for the six months ended April 30, 2025 by approximately $0.1 million as compared to the prior period; revenues from the six months ended April 30, 2024 were from the sale of approximately 2,100 barrels of oil from our McCool Ranch field, versus the sale of only (i) approximately 200 barrels of oil from our McCool Ranch location and (ii) approximately 550 barrels of oil produced from our recently acquired oil and gas assets in the Lloydminster, Saskatchewan region for the six months ended April 30, 2025.
Current report
Exploration expenses
Current report
General and administrative expenses
Current report
Stock-based compensation expense
Current report
We record stock-based compensation expenses for costs associated with options and restricted shares granted in connection with the Plan, as well as for shares issued as payment for services. For the six months ended April 30, 2025, stock-based compensation expense decreased by approximately $0.3 million compared to the prior period. This decrease was primarily due to the final vesting of certain restricted shares in the previous quarter, which resulted in a lower expense allocation for the current six-month period.
Current report
Accretion expenses
Current report
Other expenses, net
Current report
For the six months ended April 30, 2025, other expenses, net decreased by approximately $1.3 million when compared to the prior year period. This decline was primarily driven by (i) an approximate $0.8 million reduction in non-cash interest expense resulting from lower debt levels in the current period (non-cash interest expense is recognized as debt discounts on financings are amortized), as well as (ii) an approximate $1.1 million loss on a note conversion recorded in the prior period, which stemmed from principal payments made via conversion shares under the October 2023 Securities Purchase Agreement. These reductions were partially offset by a $0.6 million loss incurred in the current period due to the abandonment of oil and gas properties.
Current report
Capital Resources
Current report
Since our inception, we have funded our operations with the proceeds from equity and debt financing. We have experienced liquidity issues due to, among other reasons, our limited ability to raise adequate capital on acceptable terms. We have historically relied upon the issuance of equity and promissory notes that are convertible into shares of our common stock to fund our operations and have devoted significant efforts to reduce that exposure. Unless we are able to raise additional capital through equity and/or debt financing, we believe our existing cash and cash flow from operations will be sufficient to meet our working capital and capital expenditure needs for not more than six months from the date of this report. Future capital requirements will depend on many factors, including the time period in which we are able to ramp up the operation of wells and the acquisition of additional properties. To the extent that existing capital and revenue growth are not sufficient to fund future activities, we will need to raise capital through additional equity or debt financings. Additional funds may not be available on terms favorable to us or at all. Failure to raise additional capital, if needed, could have a material adverse effect on our financial position, results of operations and cash flows.
Current report
Proved Property Leases
Current report
In April 2025, the Company acquired oil and gas lease rights for four leases related to the proved properties located in Saskatchewan, Canada (see Note 5); the sum total of all four leases is 320 net acres and all are held by production.
Current report
As of April 30, 2025, we had five wells that are producing, all of which are located in the newly acquired Saskatchewan property, plus two workovers. We expect to add the reserve value of such fields to our reserve report after a further period of observation and review of the oil production; once this has been determined, we will estimate the necessary depreciation, depletion and amortization (“DD&A”) for such wells.
Current report
Proved oil and natural gas properties include developed and undeveloped reserves that have been confirmed through drilling and production activities. These properties are subject to DD&A, which is calculated using the unit-of-production method based on total proved reserves.
Current report
As of April 30, 2025, we have proved reserves in the newly acquired Saskatchewan properties and expect to add the reserves values of such fields to our reserve report; once this has been done, we will estimate the necessary DD&A for such wells.
Current report
Fair Value Measurements
Current report
The carrying values of financial instruments comprising cash and cash equivalents, payables, and notes payable-related party approximate fair values due to the short-term maturities of these instruments. The notes payable- related party is considered a level 3 measurement. As defined in ASC 820,Fair Value Measurements and Disclosures, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. ASC 820 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). This fair value measurement framework applies to both initial and subsequent measurement.
Current report
There are no assets or liabilities measured at fair value on a recurring basis. Assets and liabilities accounted for at fair value on a non-recurring basis in accordance with the fair value hierarchy include the initial allocation of the asset acquisition purchase price, including asset retirement obligations, the fair value of oil and natural gas properties and the assessment of impairment.
Current report
The fair value measurements and allocation of assets acquired are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future commodity prices; (iii) operating and development costs; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that the Company’s management believes will impact realizable prices. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation.
Current report
The fair value of additions to the asset retirement obligation liabilities is measured using valuation techniques consistent with the income approach, which converts future cash flows to a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well for all oil and natural gas wells and for all disposal wells; (ii) estimated remaining life per well; (iii) future inflation factors; and (iv) the Company’s average credit-adjusted risk-free rate. These assumptions represent Level 3 inputs.
Current report
If the carrying amount of its proved oil and natural gas properties, which are assessed for impairment under ASC 360 –Property, Plant and Equipment, exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The fair value of its oil and natural gas properties is determined using valuation techniques consistent with the income and market approach. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with the expected cash flow projected. These assumptions represent Level 3 inputs.
Removed paragraphs (18)
Previous report
California is a significant part of our geographic focus and we recently acquired a 22% working interest in the McCool Ranch Oil Field (the “McCool Ranch Oil Field”, “McCool Ranch Field” or “McCool Ranch”) in Monterey County, California. However, our interests extend beyond California and we recently acquired an interest in the Asphalt Ridge Project in Uintah County, Utah; we may acquire additional assets both inside and outside of California and Utah.
Previous report
McCool Ranch operations have been successfully restarted, including the restarting of oil production at the HH-1, 35X and 58X wells. The HH-1 well has a short horizontal completion in the Lombardi Oil Sand, whereas the 35X and 58X wells are both vertical wells with similar oil columns in the Lombardi Oil Sand and with similar subsurface borehole completions. The HH-1 well at McCool Ranch upon restart was initially producing cold (ie., without steam) about 47 barrels of oil per day before settling down to 10 to 15 bopd combined with the 35X well. Both the HH-1 and 35X wells are currently idled along with the 58X well. The Companyis assessing whetherto restart cyclic steam operations.
Previous report
The aforementioned initial three wells at McCool Ranch were each restarted and produced “cold” (i.e. without steam injection), which allows for lower operating costs, with expectation that each would be produced cold as long as profitable. The Company is assessing whether to transition each well from cold to cyclic-steam production, also known as “huff and puff,” which is expected to significantly increase production. The wells at McCool Ranch historically have responded favorably when cyclic-steam operations have been applied.
Previous report
The Company is assessing the viability of restarting the last two wells in the restart program, the HH-3 and HH-4 wells. The HH-3 and HH-4 wells will have horizontal completions similar to but longer than that of the HH-1 well. All water produced from these wells will be disposed in the on-site water disposal well.
Previous report
The HH-1 well was initially produced cold for about 380 days in 2012-2013, during which time peak production was about 156 barrels of oil per day (“BOPD”), average production was about 35 BOPD and cumulative production was about 13,147 barrels of oil (“BO”). The 58X well was initially produced cold for about 230 days in 2011-2013, during which time peak production was about 41 BOPD, average production was about 13 BOPD and cumulative production was about 2,918 BO.
Previous report
KLS Petroleum Consulting LLC (“KLSP”), a third-party, independent engineering firm, recommends that McCool Ranch be developed with horizontal wells, each landed in the Lombardi Oil Sand with a 1,000-foot lateral. Management estimates that TPET’s property can probably accommodate approximately 22 additional horizontal wells and TPET accordingly may commence a drilling program in 2025. TPET expects to add the reserve value of the McCool Ranch Field to the Company’s reserve report after a further period of observation and review of the oil production that was restarted on February 22, 2024.
Previous report
The Asphalt Ridge Project, according to J. Wallace Gwynn of Energy News, is estimated to be the largest measured tar sand resource in the United States and is unique given its low wax and negligible sulfur content, which is expected to make the oil produced very desirable for many industries, including shipping.
Previous report
Asphalt Ridge is a prominent, northwest-southeast trending topographic feature (i.e., a dipping slope called a hog’s back or cuesta) that crops-out along the northeast flank of the Uintah Basin. The outcrop is comprised largely of Tertiary and Cretaceous age sandstones that are locally highly saturated with heavy oil and/or tar. Deposits and reserves located in the Uintah Basin are described in a report published in October 1985 by the United States Department of Energy’s Laramie Energy Technology Center (the “LETC”) titledIn Situ Recovery of Oil from Utah Tar Sand: A Summary of Tar Sand Research at the Laramie Energy Technology Center, by L.C. Marchant and J.D. Westhoff (the “LETC Report”), covering work done by the LETC from 1971 to 1982, which was concentrated on major U.S. tar and sand deposits found in Utah. In the LETC Report, it provides that the location of individual deposits and extent of reserves have been identified by H.R. Ritzma, who was formerly with the Utah Geological and Mineralogical Survey, to contain an estimated 20 billion barrels of bitumen (oil) in the Utah tar sands, an estimated 10.8 billion barrels of which are contained in the Uintah Basin deposits, principally Asphalt Ridge (the site of the Asphalt Ridge Development Project), Hill Creek, Sunnyside and P.R. Spring. The project leasehold comprises over 30,000 acres and trends northwest-southeast, along the trend of Asphalt Ridge, over a distance of about 20 miles.
Previous report
The area has been underdeveloped for decades due, in large part, to lease ownership issues and the definition of heavy oil falling under mining regulations in the State of Utah. These factors created conflict between surface rights and subsurface mineral rights and were obstacles to developing the asset using proven advanced cyclic-steam production techniques. Necessary permits have now been secured that should allow drilling to commence by our operating partner. HSO hopes to continue to work with the State of Utah to supplement prior receipt of permits with other state incentives, including working with the State on an arrangement requiring only an 8% state royalty in connection with this project.
Previous report
An early development phase contemplates the development of 240 acres with an estimated 119 wells in the Northwest Asphalt Ridge Area. The plan is to develop the 240 acres using advanced cyclic-steam production techniques, including initial CO2 injection. This phase contemplates seventeen 7-spot hexagonal well patterns on 2 ½ acre spacing (a 7-spot has a central steam/CO2 injection well that is surrounded by six producing oil wells). Upgrades have been made to existing roads and well pads as part of this early development phase.
Previous report
Two oil-saturated Cretaceous sandstones are targeted for development at Asphalt Ridge: the Rimrock Sandstone and the underlying Asphalt Ridge Sandstone. We expect to add the reserve value, if any, of the Asphalt Ridge Project to the Company’s reserve report after a brief period of observation and review of the oil development operations that commenced in the third calendar quarter of 2024.
Previous report
During the quarterly period ended April 30, 2024, we announced the commencement of drilling activities at Asphalt Ridge. The first well, HSO 8-4 (API# 4304757202), was spud on May 10, 2024 and drilled to a total depth of 1,020 feet. The well found 100 feet of Rimrock Sandstone tar-sand pay zone with good oil saturation and good porosity and thirty feet of the Rimrock was cored. A small, representative piece of Rimrock core was placed in water and brought to boiling point, and within a few minutes the sand disaggregated and the bitumen became liquid, mobile-oil, floating on top of the water – this simple laboratory test indicates that the bitumen becomes mobile-oil at relatively low temperatures and supports our contention that oil extraction using subsurface thermal-recovery methods may be very successful. A second well, the HSO 2-4 (API# 430475201), was spud on May 19, 2024 and drilled to a total depth of 1,390 feet. The well drilled through both the Rimrock tar-sand, which had a thickness of 135 feet, and the Asphalt Ridge tar-sand, which had a thickness of 59 feet. Oil production has commenced using downhole heaters, whereas the operator plans to transition to production using advanced cyclic-steam and steam-drive methods.
Previous report
Optioned Assets - McCool Ranch Oil Field
Previous report
In October 2023, we entered into an agreement (“McCool Ranch Purchase Agreement”) with Trio LLC for the purchase of a 21.918315% working interest in the McCool Ranch Oil Field located in Monterey County near our flagship South Salinas Project; we initially recorded a payment of $100,000 upon the execution of the McCool Ranch Purchase Agreement, at which time Trio LLC began refurbishment operations with respect to the San Ardo WD-1 water disposal well (the “WD-1”) to determine if it was capable of reasonably serving the produced water needs for the assets. With refurbishment successfully accomplished, we will pay an additional $400,000 per the McCool Ranch Purchase Agreement; to date, operations have been successfully restarted at three wells, and we expect to restart the last two wells in the restart program during the calendar quarter ending September 30, 2024. As of January 31, 2025, we have paid approximately $344,000 during the year for restarting production operations on the assets and have a liability recorded of approximately $56,000 to Trio LLC as of January 31, 2025.
Previous report
Optioned Assets – Asphalt Ridge Leasehold Acquisition & Development Option Agreement
Previous report
Revenues, net increased for the three months ended January 31, 2025 by approximately $0.1 million as compared to the prior period, which had no revenue; we sold and shipped approximately 180 barrels of oil produced from the HH-1 and the 35X wells.
Previous report
For the three months ended January 31, 2025, other expenses, net increased by approximately $0.2 million when compared to the prior year period. The increase is attributable to an increase in non-cash interest expense of $0.2 million, which is recognized as debt discounts on financings are amortized; there were less financings in the prior period.
Previous report
The Company’s cash change was an increase of approximately $1.6 million as of January 31, 2025. Management believes that the cash on hand and working capital are sufficient to meet its current anticipated cash requirements for anticipated capital expenditures and operating expenses for the next twelve months.
Reworded paragraphs (31)
Previous wording
You should read the following discussion and analysis of financial condition and operating results together with our financial statements and the related notes and other financial information included elsewhere in this quarterly report on Form 10-Q, as well as our audited financial statements and related notes as disclosed in our Form 10-K/A for the year ended October 31, 2024 (“our Form 10-K/A”). This discussion contains forward-looking statements that involve risks and uncertainties. As a result of many factors, such as those in this Quarterly Report on Form 10-Q, as well as the risk factors set forth in the section titled “Risk Factors” included in our Form 10-K/A, our actual results may differ materially from those anticipated in these forward-looking statements. For convenience of presentation some of the numbers have been rounded in the text below.
Current wording
You should read the following discussion and analysis of financial condition and operating results together with our condensed consolidated financial statements and the related notes and other financial information included elsewhere in this quarterly report on Form 10-Q, as well as our audited financial statements and related notes as disclosed in our Form 10-K/A for the year ended October 31, 2024, filed with the SEC on April 15, 2025 (“our Form 10-K/A”). This discussion contains forward-looking statements that involve risks and uncertainties. As a result of many factors, such as those in this Quarterly Report on Form 10-Q, as well as the risk factors set forth in the section titled “Risk Factors” included in our Form 10-K/A, our actual results may differ materially from those anticipated in these forward-looking statements. For convenience of presentation some of the numbers have been rounded in the text below.
Previous wording
We are a California-based oil and gas exploration and development company headquartered in Bakersfield, California, with our principal executive offices located at 5401 Business Park South, Suite 115, Bakersfield, California 93309, with operations in Monterey County, California, and Uintah County, Utah.
Current wording
We are a California-based oil and gas exploration and development company headquartered in Malibu, California, with our principal executive offices located at 23823 Malibu Road, Suite 304, Malibu, California 90265, with operations in Monterey County, California, Uintah County, Utah and Lloydminster, Saskatchewan.
Previous wording
We have had revenue-generating operations since the McCool Ranch Oil Field was restarted on February 22, 2024, and recognized our first revenues in our fiscal quarter ended April 30, 2024, and received the proceeds from these operations in June 2024.
Current wording
We have had revenue-generating operations since the McCool Ranch Oil Field was restarted on February 22, 2024, and recognized our first revenues in our fiscal quarter ended April 30, 2024, and received the proceeds from these operations in June 2024. We have recently generated revenues during the period ended April 30, 2025 from our newly acquired properties in Saskatchewan, Canada.
Previous wording
We were formed to initially acquire an approximate 82.75% working interest (which was subsequently increased to an approximate 85.775% working interest) from Trio Petroleum LLC (“Trio LLC”) in the large, approximately 9,300-acre South Salinas Project that is located in Monterey County, California, and subsequently partner with certain members of Trio LLC’s management team to develop and operate those assets. We hold an approximate 68.62% interest after the application of royalties (“net revenue interest”) in the South Salinas Project. Trio LLC holds an approximate 3.8% working interest in the South Salinas Project. We and Trio LLC are separate and distinct companies.
Current wording
We were formed to initially acquire an approximate 82.75% working interest (which was subsequently increased to an approximate 85.775% working interest) from Trio LLC (“Trio LLC”) in the large, approximately 9,300-acre South Salinas Project that is located in Monterey County, California, and subsequently partner with certain members of Trio LLC’s management team to develop and operate those assets. We hold an approximate 68.62% interest after the application of royalties (“net revenue interest”) in the South Salinas Project. Trio LLC holds an approximate 3.8% working interest in the South Salinas Project. We and Trio LLC are separate and distinct companies.
Previous wording
Efforts to obtain from Monterey County conditional use permits and a full field development permit for the South Salinas Project are progressing. Efforts to obtain from the California Geologic Energy Management Division (“CalGEM”) and from the California Water Boards a permit for a water disposal project at the South Salinas Project are also progressing. In the meantime, the Company recently determined that existing permits allow production testing to continue at the HV-3A discovery well at Presidents Field and, consequently, testing operations were restarted at this well on March 22, 2024. Oil production from this well has occurred with a generally favorable oil-water ratio and the Company is assessing steps to attempt to increase the well’s gross production rate, for example by adding up to 650 feet of additional perforations in the oil zone and/or acidizing the well for borehole cleanup. First oil sales from the HV-3A well occurred in the third calendar quarter of 2024 but is currently idled.
Current wording
Efforts to obtain from Monterey County conditional use permits and a full field development permit for the South Salinas Project are progressing. Efforts to obtain from the California Geologic Energy Management Division (“CalGEM”) and from the California Water Boards a permit for a water disposal project at the South Salinas Project are also progressing. In the meantime, the Company recently determined that existing permits allow production testing to continue at the HV-3A discovery well at Presidents Field and, consequently, testing operations were restarted at this well on March 22, 2024. Oil production from this well has occurred and the Company is assessing steps to attempt to increase the well’s gross production rate, for example by adding up to 650 feet of additional perforations in the oil zone and/or acidizing the well for borehole cleanup. First oil sales from the HV-3A well occurred in the third calendar quarter of 2024 but is currently idled as we further discussions with local oil and gas companies to joint venture the project.
Previous wording
On October 16, 2023, we entered into a Purchase and Sale Agreement with Trio LLC (the “McCool Ranch Purchase Agreement”) pertaining to the McCool Ranch Oil Field. Pursuant to this agreement, effective October 1, 2023, we acquired an approximate 22% working interest in and to certain oil and gas assets at the McCool Ranch Field, which is located in Monterey, County, California, just seven miles from our flagship South Salinas Project. The assets are situated in what is known as the “Hangman Hollow Area” of the McCool Ranch Field. The acquired property is a relatively new oil field (discovered in 2011) developed with six oil wells, one water-disposal well, a steam generator, boiler, three 5,000 barrel tanks, a 250-barrel test tank, a water softener, two freshwater tanks, two soft water tanks, in-field steam pipelines, oil pipelines and other facilities. The property is fully and properly permitted for oil and gas production, cyclic-steam injection and water disposal. We are acquiring the working interest at McCool Ranch primarily through work commitment expenditures, which are being allocated to restart production at the field and establish cash flow for us, with upside potential given the numerous undrilled infill and development well locations. Oil production was restarted on February 22, 2024.
Current wording
On October 16, 2023, we entered into a Purchase and Sale Agreement with Trio LLC (the “McCool Ranch Purchase Agreement”) pertaining to the McCool Ranch Oil Field. Pursuant to this agreement, effective October 1, 2023, we entered into an agreement to acquire an approximate 22% working interest in and to certain oil and gas assets at the McCool Ranch Field, located in Monterey County, California, near our flagship South Salinas Project.
Previous wording
On November 10, 2023, TPET entered into a Leasehold Acquisition and Development Option Agreement (the “Asphalt Ridge Option Agreement”) with Heavy Sweet Oil LLC (“HSO”). Pursuant to the Asphalt Ridge Option Agreement, the Company acquired an option to purchase up to a 20% working interest in certain leases at a long-recognized, major oil accumulation in northeastern Utah, in Uintah County, southwest of the city of Vernal, including an initial 960 acres and a subsequent 1,920 acres, as well as a right-of-refusal option on approximately 30,000 acres. HSO holds the right to such leases below 500 feet depth from surface and the Company acquired the option to participate in HSO’s initial 960 acre and subsequent 1,920 acre drilling and production programs (the “HSO Program”) on such Asphalt Ridge Leases. TPET also holds the right of first refusal to participate with up to a 20% working interest on the greater approximate 30,000 acre leasehold at terms offered to other third-parties. On December 29, 2023, the Company and HSO entered into an Amendment to Leasehold Acquisition and Development Agreement (the “Amendment to the Asphalt Ridge Option Agreement”), pursuant to which the Company and HSO amended the Asphalt Ridge Option Agreement to provide that, within three (3) business days of the effective date of the Amendment to the Asphalt Ridge Option Agreement, the Company would fund $200,000 of the $2,000,000 total purchase price in advance of HSO satisfying the closing conditions set forth in the Asphalt Ridge Option Agreement, in exchange for the Company receiving an immediate 2% interest in the initial 960 acres, which advanced funds would be used solely for the building of roads and related infrastructure in furtherance of the development plan. In January 2024, the Company funded an additional $25,000 resulting in a 2.25% working interest in the initial 960 acres.
Current wording
On November 10, 2023, TPET entered into a Leasehold Acquisition and Development Option Agreement (the “Asphalt Ridge Option Agreement”) with Heavy Sweet Oil LLC (“HSO”). Pursuant to the Asphalt Ridge Option Agreement, the Company acquired an option to purchase up to a 20% working interest in certain leases at a long-recognized, major oil accumulation in northeastern Utah, including an initial 960 acres and a subsequent 1,920 acres, as well as a right-of-refusal option on approximately 30,000 acres.
Previous wording
We have only begun to generate revenues in the current fiscal year and have incurred significant losses since inception. As of January 31, 2025, we have an accumulated deficit of $21,689,204 and working capital of $547,056, and for the year ended January 31, 2025, a net loss of $1,615,525 and cash used in operating activities of $920,485. To date, we have been funding operations through proceeds from the issuance of common stock, financing through certain investors, the consummation of our IPO in April 2023, and convertible note financing under two tranches in October 2023 and December 2023, pursuant to which we raised total gross proceeds of $2,371,500. Additionally, we received funds in the amount of $125,000 from an unsecured promissory note from our CEO, gross proceeds of $184,500 from a promissory note with an investor in March 2024, gross proceeds of $720,000 from convertible debt financing with two investors in April 2024, gross proceeds of $720,000 from convertible debt financing with two investors in June 2024, as well as additional financing secured after the end of the period in August 2024 for gross proceeds in the aggregate amount of $359,000 from two unsecured promissory notes, as well as proceeds of approximately $4,650,000 in connection with an “at-the-market” agreement entered into in September 2024.
Current wording
We have only begun to generate revenues in the prior fiscal year and have incurred significant losses since inception. As of April 30, 2025, we have an accumulated deficit of $23,252,956 and a working capital deficit of $531,983, and for the three and six months ended April 30, 2025, net losses of $1,563,752 and $3,179,277, respectively, and cash used in operating activities of $1,660,469. To date, we have been funding operations through proceeds from the issuance of common stock, financing through certain investors, the consummation of our initial public offering (“IPO”) in April 2023, and convertible note financing under two tranches in October 2023 and December 2023, pursuant to which the Company raised total gross proceeds of $2,371,500. Additionally, in 2024 the Company received funds in the amount of $125,000 from an unsecured promissory note from its former CEO, gross proceeds of $543,500 from promissory notes with investors, gross proceeds of $1,440,000 from convertible debt financing with investors and net proceeds of approximately $4,650,000 in connection with an “at-the-market” agreement entered into in September 2024. In April 2025, the Company received gross proceeds in the amount of $606,000 from a convertible debt financing provided by one investor.
Previous wording
There is substantial doubt regarding our ability to continue as a going concern as a result of our accumulated deficit and no source of revenue sufficient to cover our costs of operations as well as our dependence on private equity and financing.
Current wording
There is substantial doubt regarding our ability to continue as a going concern as a result of our accumulated deficit. Our current source of revenue is insufficient to cover our operating costs and we are dependent on private equity and external financing to sustain operations.
Previous wording
The accompanying condensed financial statements have been prepared assuming we will continue as a going concern. As we have only begun to generate revenues, we need to raise a significant amount of capital to pay for our development, exploration, drilling and operating costs. While we raised capital in April 2023 with our IPO, in October 2023, December 2023, April 2024 and June 2024 with convertible debt financing, in March 2024 and August 2024 with promissory notes and in September 2024 with an ATM agreement, we expect to require additional funding in the future and there is no assurance that we will be able to raise additional needed capital or that such capital will be available under favorable terms or at all. We are subject to all the substantial risks inherent in the development of a new business enterprise within an extremely competitive industry. Due to the absence of a long-standing operating history and the emerging nature of the markets in which we compete, we anticipate operating losses until we can successfully implement our business strategy, which includes all associated revenue streams. We may never achieve profitable operations or generate significant revenues.
Current wording
The accompanying condensed consolidated financial statements have been prepared assuming we will continue as a going concern. As we have only begun to generate revenues, we need to raise a significant amount of capital to pay for our development, exploration, drilling and operating costs. While we raised capital in April 2023 in our IPO, in October 2023, December 2023, April 2024, June 2024 and April 2025 with convertible debt financing, in March 2024 and August 2024 with promissory notes, September 2024 with an ATM agreement, we expect to require additional funding in the future and there is no assurance that we will be able to raise additional needed capital or that such capital will be available under favorable terms or at all. We are subject to all the substantial risks inherent in the development of a new business enterprise within an extremely competitive industry. Due to the absence of a long-standing operating history and the emerging nature of the markets in which we compete, we anticipate operating losses until we can successfully implement our business strategy, which includes all associated revenue streams. We may never achieve profitable operations or generate significant revenues.
Previous wording
We will require additional capital funding in order to drill additional planned wells at the South Salinas, McCool Ranch and Asphalt Ridge assets and to pay for additional development costs and other payment obligations and operating costs until our planned revenue streams are fully implemented and begin to offset our operating costs, if ever.
Current wording
We will require additional capital funding in order to drill additional planned wells at the South Salinas and Asphalt Ridge assets and to pay for additional development costs and other payment obligations and operating costs until our planned revenue streams are fully implemented and begin to offset our operating costs, if ever.
Previous wording
The accompanying condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. Accordingly, the financial statements do not include any adjustments relating to the recoverability of assets and classification of liabilities that might be necessary should we be unable to continue as a going concern. The financial statements included in this report also include a going concern footnote (see Note 3).
Current wording
The accompanying condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. Accordingly, the condensed consolidated financial statements do not include any adjustments relating to the recoverability of assets and classification of liabilities that might be necessary should we be unable to continue as a going concern. The condensed consolidated financial statements included in this report also include a going concern footnote (see Note 3).
Previous wording
We are an “emerging growth company,” as defined in Section 2(a) of the Securities Act, as modified by the JOBS Act, and it may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404(b) of the Sarbanes-Oxley Act of 2002, reduced disclosure obligations regarding executive compensation in periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. Further, Section 102(b)(1) of the JOBS Act exempts emerging growth companies from being required to comply with new or revised financial accounting standards until private companies (that is, those that have not had a Securities Act registration statement declared effective or do not have a class of securities registered under the Exchange Act) are required to comply with the new or revised financial accounting standards. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies but any such election to opt out is irrevocable. We have elected not to opt out of such extended transition period which means that when a standard is issued or revised and it has different application dates for public or private companies, we, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of our financial statements with another public company which is neither an emerging growth company nor an emerging growth company which has opted out of using the extended transition period difficult or impossible because of the potential differences in accounting standards used.
Current wording
We are an “emerging growth company,” as defined in Section 2(a) of the Securities Act, as modified by the JOBS Act, and it may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404(b) of the Sarbanes-Oxley Act of 2002, reduced disclosure obligations regarding executive compensation in periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. Further, Section 102(b)(1) of the JOBS Act exempts emerging growth companies from being required to comply with new or revised financial accounting standards until private companies (that is, those that have not had a Securities Act registration statement declared effective or do not have a class of securities registered under the Exchange Act) are required to comply with the new or revised financial accounting standards. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies but any such election to opt out is irrevocable. We have elected not to opt out of such extended transition period which means that when a standard is issued or revised and it has different application dates for public or private companies, we, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of our condensed consolidated financial statements with another public company which is neither an emerging growth company nor an emerging growth company which has opted out of using the extended transition period difficult or impossible because of the potential differences in accounting standards used.
Previous wording
We record stock-based compensation expenses for costs associated with options and restricted shares granted in connection with the Plan, as well as for shares issued as payment for services. Stock-based compensation expense increased by approximately $0.1 million for the year ended January 31, 2025 due to the amortization of 260,000 options issued in the current twelve month period; such had not yet been granted during the same period in the prior year.
Current wording
We record stock-based compensation expenses for costs associated with options and restricted shares granted in connection with the Plan, as well as for shares issued as payment for services. Stock-based compensation expense decreased by approximately $0.4 million for the three months ended April 30, 2025 due to the amortization of approximately 30,000 more options in the prior three month period than in the current period.
Previous wording
General and administrative expenses decreased for the three months ended January 31, 2025 by approximately $0.3 million as compared to the prior period due to decreases in salary expenses and legal fees of approximately $175,000 and $80,000, respectively.
Current wording
General and administrative expenses decreased for the six months ended April 30, 2025 by approximately $1.0 million as compared to the prior period due to decreases in salary expenses, advertising and marketing fees, filing fees and legal fees of approximately $330,000, $235,000, $160,000 and $200,000, respectively.
Previous wording
Our working capital as of January 31, 2025, in comparison to our working capital deficiency as of October 31, 2024, can be summarized as follows:
Current wording
Our working capital deficiency as of April 30, 2025, in comparison to our working capital deficiency as of October 31, 2024, can be summarized as follows:
Previous wording
Current assets increased because of i) an increase to the cash account of approximately $1.7 million due to cash proceeds from the sale of shares related to the ATM agreement. Current liabilities decreased because of i) a decrease in promissory notes of approximately $0.4 million, ii) a decrease in notes payable-related parties of $0.1 million and iii) a decrease in other current liabilities of approximately $0.4 million.
Current wording
Current assets increased because of i) an increase to the cash account of approximately $3.4 million due to cash proceeds from the sale of shares related to the ATM agreement. Current liabilities decreased because of (i) a decrease in promissory notes of approximately $0.7 million, (ii) a decrease in notes payable-related parties of $0.2 million and (iii) a decrease in other current liabilities of approximately $0.3 million, offset by increases of approximately $0.6 million and $0.3 million in convertible note debt and deferred consideration payable, respectively.
Previous wording
Our cash flows for the three months ended January 31, 2025, in comparison to our cash flows for the three months ended January 31, 2024, can be summarized as follows:
Current wording
Our cash flows for the six months ended April 30, 2025, in comparison to our cash flows for the six months ended April 30, 2024, can be summarized as follows:
Previous wording
For the three months ended January 31, 2025 and 2024, cash used in operating activities was $920,485 and $774,431, respectively. The cash used in operations for the three months ended January 31, 2025 was primarily attributable to our net loss of $1,615,525, adjusted for non-cash expenses in the aggregate amount of $887,818, as well as $192,778 of net cash used to fund changes in the levels of operating assets and liabilities. The cash used in operations for the three months ended January 31, 2024 was primarily attributable to our net loss of $1,702,048, adjusted for non-cash expenses in the aggregate amount of $968,993, as well as $41,376 of net cash used to fund changes in the levels of operating assets and liabilities.
Current wording
For the six months ended April 30, 2025 and 2024, cash (used in)/provided by operating activities was ($1,660,469) and $682,525, respectively. The cash used in operations for the six months ended April 30, 2025 was primarily attributable to our net loss of $3,179,277, adjusted for non-cash expenses in the aggregate amount of $1,725,452, as well as $206,644 of net cash used to fund changes in the levels of operating assets and liabilities. The cash provided by operations for the six months ended April 30, 2024 was primarily attributable to our net loss of $5,747,983, adjusted for non-cash expenses in the aggregate amount of $6,086,949, as well as $343,559 of net cash provided to fund changes in the levels of operating assets and liabilities.
Previous wording
For the three months ended January 31, 2025 and 2024, cash used in investing activities was $160,779 and $522,767, respectively. The cash used during the three months ended January 31, 2025 is attributable to approximately $0.1 million related to costs for capital expenditures, which were capitalized and reflected in the balance of the oil and gas property as of January 31, 2025, and $0.1 million in amounts due to operators. The cash used during the three months ended January 31, 2024 was attributable to approximately $0.3 million related to drilling exploratory wells and approximately $0.6 million related to acquisition costs, both of which were capitalized and reflected in the balance of the oil and gas property as of January 31, 2024. These amounts were offset by approximately $400,000 in amounts due to operators and related parties for costs for the South Salinas Project and the McCool Ranch Option.
Current wording
For the six months ended April 30, 2025 and 2024, cash used in investing activities was $453,616 and $1,018,704, respectively. The cash used in investing activities during the six months ended April 30, 2025 is attributable to approximately $0.4 million for assets acquired at the Lloydminster, Saskatchewan properties. The cash used for the six months ended April 30, 2024 is attributable to approximately $1.1 million related to costs for capital expenditures, which were capitalized and are reflected in the balance of the oil and gas property as of April 30, 2024. These amounts were offset by approximately $50,000 in amounts due to operators for costs for the South Salinas Project and the McCool Ranch Option.
Previous wording
For the three months ended January 31, 2025 and 2024, cash provided by financing activities was $2,756,520 and $84,022, respectively. Cash provided by financing activities during the three months ended January 31, 2025 was primarily attributable to approximately $3.5 million in net proceeds from the issuance of common shares in connection with an ATM agreement, offset by payments for related party debt and promissory notes of approximately $0.2 million and $0.5 million, respectively. Cash provided by financing activities during the three months ended January 31, 2024 was primarily attributable to approximately $0.5 million in net proceeds from the issuance of convertible debt, offset by payments for the convertible debt in the amount of approximately $0.4 million.
Current wording
For the six months ended April 30, 2025 and 2024, cash provided by/(used in) financing activities was $3,250,350 and ($1,005,098), respectively. Cash provided by financing activities during the six months ended April 30, 2025 was primarily attributable to (i) proceeds from the issuance of common shares in connection with an ATM agreement, (ii) proceeds from the issuance of convertible debt of approximately $0.6 million, offset by repayments of related party debt and promissory notes of approximately $0.2 million and $0.6 million, respectively. Cash provided by financing activities during the six months ended April 30, 2024 was primarily attributable to approximately $0.6 million in net proceeds from the issuance of convertible debt and approximately $1.0 million from the issuance of promissory notes and related party notes, offset by payments for the convertible debt in the amount of approximately $2.6 million and debt issuance costs of $0.2 million.
Previous wording
During February and March of 2023, we entered into additional leases related to the unproved properties of the South Salinas Project with two groups of lessors. The first group of leases covers 360 acres and has a term of 20 years; we are required to make rental payments of $25/acre per year. We are currently in compliance with this requirement and have paid in advance the rental payment for the period February 2025 through February 2026. The second group of leases covers 307.75 acres and has a term of 20 years; we are required to make rental payments of $30/acre per year. We are currently in compliance with this requirement and have paid in advance the rental payment for the period from March 2025 through March 2026.
Current wording
During February and March of 2023, we entered into additional leases related to the unproved properties of the South Salinas Project with two groups of lessors. The first group of leases covers 360 acres and has a term of 20 years; we are required to make rental payments of $25/acre per year. The second group of leases covers 307.75 acres and has a term of 20 years; we are required to make rental payments of $30/acre per year. During the current reporting period, we made the strategic decision to abandon the additional oil and gas leases. As a result, all associated costs related to exploration and development activities, including any capitalized costs for support equipment and facilities, have been expensed in accordance with applicable accounting standards. This decision was based on a comprehensive evaluation of the economic viability and future potential of the leases, considering market conditions, regulatory factors, and operational constraints.
Previous wording
We hold interests in various leases related to the unproved properties of the McCool Ranch Oil Field. These leases occur in two parcels, “Parcel 1” and “Parcel 2”. Parcel 1 comprises ten leases and approximately 480 acres, which are held by delay rental payments that are paid-up and current. Parcel 2 comprises one lease and approximately 320 acres, which is held by production. The total leasehold comprises approximately 800 gross and net acres.
Current wording
We hold interests in various leases related to the unproved properties of the McCool Ranch Oil Field. These leases occur in two parcels, “Parcel 1” and “Parcel 2”. Parcel 1 comprises ten leases and approximately 480 acres, which are held by delay rental payments that are paid-up and current. Parcel 2 comprises one lease and approximately 320 acres, which is held by production. The total leasehold comprises approximately 800 gross and net acres. As of April 30, 2025, we made the decision to abandon all McCool Ranch leases. Accordingly, these leases have been written off and have been expensed on the statement of operations as of April 30, 2025. No further rental payments or development activities will be pursued.
Previous wording
On December 29, 2023, we entered into an amendment to the ARLO Agreement, whereby we funded $200,000 of the $500,000 payable by us to HSO at the Initial Closing, in advance of HSO satisfying certain required items for a 2% interest in the leases; such funds are to be used by HSO solely for the building of roads and related infrastructure in furtherance of the development of the leases. As of January 31, 2025, we have paid a total of $225,000 to HSO in costs related to infrastructure and has obtained a 2.25% interest in the leases; such costs are capitalized costs and are reflected in the balance of the oil and gas property as of January 31, 2025.
Current wording
On December 29, 2023, we entered into an amendment to the ARLO Agreement, whereby we funded $200,000 of the $500,000 payable by us to HSO at the Initial Closing, in advance of HSO satisfying certain required items for a 2% interest in the leases; such funds are to be used by HSO solely for the building of roads and related infrastructure in furtherance of the development of the leases. As of April 30, 2025, we have paid a total of $225,000 to HSO in costs related to infrastructure and have obtained a 2.25% interest in the leases; such costs are capitalized costs and are reflected in the balance of the oil and gas property as of April 30, 2025.
Previous wording
We have until April 10, 2025 to pay HSO an additional $1,775,000 to exercise an option for the remaining 17.75% working interest in the initial 960 acres of the Asphalt Ridge Leases; if this option is not exercised on or before such date, we will forfeit any further right to acquire this additional 17.75% working interest in the initial 960 acres. As of January 31, 2025, we have paid a total of $225,000 to HSO in costs related to infrastructure and have a 2.25% interest in the leases; such costs are capitalized costs and are reflected in the balance of the oil and gas property as of January 31, 2025.
Current wording
Per the most recent amendment to the ARLO Agreement signed in April 2025, we had until May 10, 2025 to pay HSO an additional $1,775,000 to exercise an option for the remaining 17.75% working interest in the initial 960 acres of the Asphalt Ridge Leases. The option expired after the reporting period on May 10, 2025 due to our failure to exercise it before the expiration date. As a result, we forfeited any further right to acquire the additional 17.75% working interest but will retain our existing 2.25% interest in the leases.
Previous wording
On July 11, 2022, the Company’s Board of Directors approved compensation for each of the non-employee directors of the Company, which would be effective upon the consummation of the IPO. Such compensation is structured as follows: an annual retainer of $50,000 cash plus an additional $10,000 for each Board committee upon which the Director serves, each paid quarterly in arrears. Payment for this approved compensation commenced upon successful completion of the Company’s IPO in April 2023; for the three months ended January 31, 2025 and 2024, the Company has recognized $59,167 and $56,685, respectively, in directors’ fees.
Current wording
On July 11, 2022, our Board of Directors approved compensation for each of the non-employee directors of the Company, which would be effective upon the consummation of the IPO. Such compensation is structured as follows: an annual retainer of $50,000 cash plus an additional $10,000 for each Board committee upon which the Director serves, each paid quarterly in arrears. Payment for this approved compensation commenced upon successful completion of the Company’s IPO in April 2023, and for the three and six months ended April 30, 2025, we recognized $102,508 and $161,675, respectively, in directors’ fees. For the three and six months ended April 30, 2024, we recognized $54,000 and $110,685, respectively, in directors’ fees.
Previous wording
On October 4, 2023 and December 29, 2023, the Company entered into placement agent agreements with Spartan Capital Securities, LLC (“Spartan”), whereby Spartan has served as the exclusive placement agent in connection with the closing of private placements. The agreements provide the agent with i) a cash fee 7.5% of the aggregate proceeds raised in the sale and ii) warrants to purchase a number of common shares equal to 5% of the number of common shares initially issuable upon conversion of each note tranche; warrants to purchase 4,167 and 2,750 common shares with exercise prices of $26.40 and $11.00 for the first and second tranches, respectively, were issued to Spartan as of January 31, 2024. Such warrants may be exercised beginning 6 months after issuance until four and one-half years thereafter.
Current wording
On October 4, 2023 and December 29, 2023, we entered into placement agent agreements with Spartan Capital Securities, LLC (“Spartan”), whereby Spartan has served as the exclusive placement agent in connection with the closing of private placements. The agreements provide the agent with i) a cash fee 7.5% of the aggregate proceeds raised in the sale and ii) warrants to purchase a number of common shares equal to 5% of the number of common shares initially issuable upon conversion of each note tranche; warrants to purchase 4,167 and 2,750 common shares with exercise prices of $26.40 and $11.00 for the first and second tranches, respectively, were issued to Spartan as of January 31, 2024. Such warrants may be exercised beginning 6 months after issuance until four and one-half years thereafter.
Previous wording
We prepare our financial statements in conformity with GAAP, which requires management to make certain estimates and assumptions and apply judgments. We base our estimates and judgments on historical experience, current trends and other factors that management believes to be important at the time the condensed financial statements are prepared, and actual results could differ from our estimates and such differences could be material. Due to the need to make estimates about the effect of matters that are inherently uncertain, materially different amounts could be reported under different conditions or using different assumptions. On a regular basis, we review our critical accounting policies and how they are applied in the preparation of our condensed financial statements, as well as the sufficiency of the disclosures pertaining to our accounting policies in the footnotes accompanying our financial statements. Described below are the most significant policies we apply in preparing our condensed financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See “Note 2 - Summary of Significant Accounting Policies” to our financial statements.
Current wording
We prepare our condensed consolidated financial statements in conformity with GAAP, which requires management to make certain estimates and assumptions and apply judgments. We base our estimates and judgments on historical experience, current trends and other factors that management believes to be important at the time the condensed consolidated financial statements are prepared, and actual results could differ from our estimates and such differences could be material. Due to the need to make estimates about the effect of matters that are inherently uncertain, materially different amounts could be reported under different conditions or using different assumptions. On a regular basis, we review our critical accounting policies and how they are applied in the preparation of our condensed consolidated financial statements, as well as the sufficiency of the disclosures pertaining to our accounting policies in the footnotes accompanying our condensed consolidated financial statements. Described below are the most significant policies we apply in preparing our condensed consolidated financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See “Note 2 - Summary of Significant Accounting Policies” to our condensed consolidated financial statements.
Previous wording
Costs to acquire mineral interests in crude oil and/or natural gas properties, drill and equip exploratory wells that find proved reserves and drill and equip development wells are capitalized. Acquisition costs of unproved leaseholds are assessed for impairment during the holding period and transferred to proven crude oil and/or natural gas properties to the extent associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment, based on our current exploration plans, and a valuation allowance is provided if impairment is indicated. Capitalized costs from successful exploration and development activities associated with producing crude oil and/or natural gas leases, along with capitalized costs for support equipment and facilities, are amortized to expense using the unit-of-production method based on proved crude oil and/or natural gas reserves on a field-by-field basis, as estimated by qualified petroleum engineers. We currently have four wells that are producing (one well in President’s Field in the South Salinas Project and three wells at the McCool Ranch Oil Field) and are evaluating the impact of production on the reserve determination for those wells and fields. We expect to add the reserve value of such fields to our reserve report after a further period of observation and review of oil production.
Current wording
Costs to acquire mineral interests in crude oil and/or natural gas properties, drill and equip exploratory wells that find proved reserves and drill and equip development wells are capitalized. Acquisition costs of unproved leaseholds are assessed for impairment during the holding period and transferred to proven crude oil and/or natural gas properties to the extent associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment, based on our current exploration plans, and a valuation allowance is provided if impairment is indicated. Capitalized costs from successful exploration and development activities associated with producing crude oil and/or natural gas leases, along with capitalized costs for support equipment and facilities, are amortized to expense using the unit-of-production method based on proved crude oil and/or natural gas reserves on a field-by-field basis, as estimated by qualified petroleum engineers.
Previous wording
Unproved oil and natural gas properties
Current wording
Proved and unproved oil and natural gas properties
Previous wording
Unproved oil and natural gas properties are not subject to amortization and are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. We currently have four wells that are producing (one well in President’s Field in the South Salinas Project and three wells at the McCool Ranch Oil Field) and are evaluating the impact of production on the reserve determination for those wells and fields. We expect to add the reserve value of such fields to our reserve report after a further period of observation and review of the oil production. As of January 31, 2025 and October 31, 2024, all of our oil and gas properties were classified as unproved properties and were not subject to depreciation, depletion and amortization.
Current wording
Unproved oil and natural gas properties are not subject to amortization and are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. As of April 30, 2025 and October 31, 2024, such oil and gas properties were classified as unproved properties and were not subject to depreciation, depletion and amortization.
Rearranged current paragraphs (5)
Current report — wording carried from elsewhere
Six Months Ended April 30, 2025 compared to the Six Months Ended April 30, 2024 (unaudited)
Current report — wording carried from elsewhere
Our financial results for the six months ended April 30, 2025 and 2024 are summarized as follows:
Current report — wording carried from elsewhere
Under the successful efforts method of accounting for crude oil and natural gas properties, exploration expenses consist primarily of exploratory, geological and geophysical costs, delay rentals and exploratory overhead, and are expensed as incurred. Exploration expenses decreased by approximately $0.1 million as compared to the prior year period due to a decrease in exploratory, geological, and geophysical costs incurred during the period.
Current report — wording carried from elsewhere
General and administrative expenses consist primarily of personnel expenses, including salaries, benefits and stock-based compensation expense for employees and consultants in executive, finance and accounting, legal, operations support, information technology and human resource functions. General and administrative expenses also include corporate facility costs including rent, utilities, depreciation, amortization and maintenance, as well as legal fees related to intellectual property and corporate matters and fees for accounting and consulting services.
Current report — wording carried from elsewhere
We have an Asset Retirement Obligation (“ARO”) recorded that is associated with its oil and natural gas properties in the SSP; the fair value of the ARO was recorded as a liability and is accreted over time until the date the ARO is to be paid. For the six months ended April 30, 2025, accretion expenses remained consistent with that of the prior year period.
Rearranged previous paragraphs (2)
Previous report — wording carried elsewhere
On November 10, 2023, we entered into a leasehold acquisition and development option agreement (“ARLO Agreement”) with Heavy Sweet Oil, LLC (“HSO”) for a term of nine months, which gives the Company the exclusive right to acquire up to a 20% interest in a 960 acre drilling and production program in the Asphalt Ridge leases for $2,000,000, which may be invested in tranches by us, with an initial tranche closing for an amount no less than $500,000 and paid within seven days subsequent to HSO providing certain required items to the Company.
Previous report — wording carried elsewhere
On December 29, 2023, we entered into an amendment to the ARLO Agreement, whereby we funded $200,000 of the $500,000 payable by us to HSO at the Initial Closing, in advance of HSO satisfying certain required items for a 2% interest in the leases; such funds are to be used by HSO solely for the building of roads and related infrastructure in furtherance of the development of the leases. During the quarterly period ended April 30, 2024, we announced the commencement of drilling activities at Asphalt Ridge and two wells (the HSO 8-4 and the HSO 2-4) were spud during May 2024.