Trio Petroleum Corp

Previous wording

Efforts to obtain conditional use permits and a full field development permit for the South Salinas Project from Monterey County are progressing; in the meantime, we 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. The well has been producing with a generally favorable oil-water ratio, and we believe that production at the HV-3A well can be significantly increased over current and previous levels by adding up to 650 feet of additional perforations in the currently producing oil zone, opening deeper behind-pipe oil zones some of which are already selectively perforated, acidizing the well for borehole cleanup, and other methods and operations under consideration. We expect to takes such steps towards increased production in the third or fourth calendar quarter of 2024, with first oil sales from the HV-3A well in the third calendar quarter of 2024.

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 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.

Previous wording

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. Upon restart, the HH-1 well at McCool Ranch was initially producing about 47 barrels of oil per day (“BOPD”) and it is currently producing about 20 BOPD. The 35X well produced some oil but it and the 58X well are temporarily idle and awaiting heat treatment, which we expect to accomplish during the calendar quarter ending September 30, 2024. The oil production at the HH-1 well is currently “cold” (i.e., without steam).

Current wording

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 wording

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. Our expectation was and is that each well will probably transition at some point from cold production to cyclic-steam operations, 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.

Current wording

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 wording

We expect to restart the last two wells in the restart program (the HH-3 and HH-4 wells) in the third calendar quarter of 2024. The HH-3 and HH-4 wells will have horizontal completion similar to that of the HH-1 well; all water produced from these wells will be disposed in the on-site water disposal well.

Current wording

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 wording

The HH-1 well was initially produced cold for about 380 days in 2012-2013, during which time peak production was approximately 156 BOPD, average production was approximately 35 BOPD and cumulative production was 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 approximately 41 BOPD, average production was approximately 13 BOPD and cumulative production was 2,918 BO.

Current wording

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 wording

KLS Petroleum Consulting LLC (“KLSP”), a third-party, independent engineering firm, recommends that McCool Ranch be developed with horizontal wells; management estimates that our property can probably accommodate approximately 22 additional such horizontal wells and we may commence a drilling program in the third or fourth calendar quarter of 2024. We expect to add the reserve value of the McCool Ranch Field to our reserve report after a brief period of observation and review of the oil production that was restarted on February 22, 2024.

Current wording

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 wording

On November 10, 2023, we 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, we 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, totaling 960 acres. HSO holds the right to such leases below 500 ft depth from surface and we acquired the option to participate in HSO’s initial 960-acre drilling and production program (the “HSO Program”) on such Asphalt Ridge Leases. We also hold 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, we and HSO entered into an Amendment to Leasehold Acquisition and Development Agreement (the “Amendment to the Asphalt Ridge Option Agreement”), pursuant to which we 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, we 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 receiving an immediate 2% interest in the Asphalt Ridge Leases, which advanced funds would be used solely for the building of roads and related infrastructure in furtherance of the development plan. In January 2024, we funded an additional $25,000 resulting in a 2.25% working interest in the Asphalt Ridge Leases.

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, 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.

Previous wording

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 Uinta Basin. The outcrop is comprised largely of Tertiary and Cretaceous age sandstones that are locally highly saturated with heavy oil and/or tar. The oil-saturated sandstones extend into the shallow subsurface of the Uinta Basin to the southwest, which is the site of the Asphalt Ridge Development Project, and where the sandstones are estimated in various independent studies to contain billions of barrels of oil-in-place. 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.

Current wording

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 wording

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. A downhole-heater has been installed in the 2-4 well and we expect production to begin in the third calendar quarter of 2024. A third well is planned to be drilled in the third calendar quarter of 2024.

Current wording

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 wording

We have only begun to generate revenues in the current year and have incurred significant losses since inception. As of July 31, 2024, we have an accumulated deficit of $18,373,436 and a working capital deficit of $2,970,428, and for the three and nine months ended July 31, 2024, net losses of $2,178,571 and $7,926,554, respectively. 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.

Current 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.

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. See “Risk Factors—Risks Relating to Our Business— We have a history of operating losses, our management has concluded that factors raise substantial doubt about our ability to continue as a going concern and our auditor has included an explanatory paragraph relating to our ability to continue as a going concern in its audit report for the years ended October 31, 2023 and 2022, and for the period from July 19, 2021 (inception) through October 31, 2021,” in our Form 10-K/A.

Current 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.

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, and in March 2024 and August 2024 with promissory notes, 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 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.

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 condensed 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 financial statements included in this report also include a going concern footnote.

Current 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).

Previous wording

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 were obligated to 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 July 31, 2024, we have paid approximately $270,000 during the year for restarting production operations on the assets and have a liability recorded of approximately $130,000 to Trio LLC as of July 31, 2024.

Current wording

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 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. 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; a third well is planned to be drilled in the third calendar quarter of 2024.

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. 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.

Previous wording

Revenues, net increased for the three months ended July 31, 2024 by approximately $0.1 million as compared to the prior period, which had no revenue; we sold and shipped approximately 1,000 barrels of oil, primarily produced from the HH-1 well.

Current wording

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 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 $0.3 million for the nine months ended July 31, 2024 due to the amortization of 1,425,000 options issued in September 2023; 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 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.

Previous wording

We have an Asset Retirement Obligation (“ARO”) recorded that is associated with our 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 three months ended July 31, 2024, accretion expenses remained consistent with that of the prior year period.

Current wording

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 three months ended January 31, 2025, accretion expenses remained consistent with that of the prior year period.

Previous wording

For the nine months ended July 31, 2024, Other expenses, net increased by approximately $1.1 million compared to the prior year period. The increase is due to increased non-cash interest expense of $1.1 million, which is recognized as debt discounts on financings are amortized; there were less financings in the prior period.

Current wording

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 wording

Our working capital deficiency as of July 31, 2024, in comparison to our working capital deficiency as of October 31, 2023, can be summarized as follows:

Current 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:

Previous wording

Current assets decreased because of i) a decrease to the cash account of approximately $1.3 million due to increased payroll expenses and additional cash outlays for capital expenditures for the oil and gas properties, offset by an increase in prepaid assets of approximately $0.2 million. Current liabilities increased because of i) an increase in accounts payable of approximately $0.8 million, as well as increases in other current liabilities and notes payable – related parties of approximately $0.6 million and $0.3 million, respectively.

Current 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.

Previous wording

Our cash flows for the nine months ended July 31, 2024, in comparison to our cash flows for the nine months ended July 31, 2023, can be summarized as follows:

Current 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:

Previous wording

For the nine months ended July 31, 2024 and 2023, cash provided by/(used in) operating activities was $118,642 and ($2,542,360), respectively. The cash provided by operations for the nine months ended July 31, 2024 was primarily attributable to our net loss of $7,926,554, adjusted for non-cash expenses in the aggregate amount of $6,853,494, as well as $1,191,702 of net cash provided to fund changes in the levels of operating assets and liabilities. Our cash used in operations for the nine months ended July 31, 2023 was primarily attributable to our net loss of $5,224,839, adjusted for non-cash expenses in the aggregate amount of $2,481,724, as well as $200,755 of net cash provided to fund changes in the levels of operating assets and liabilities.

Current 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.

Previous wording

For the nine months ended July 31, 2024 and 2023, cash used in investing activities was $1,138,561 and $1,804,050, respectively. The cash used during the current period 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 July 31, 2024. Cash used from investing activities for the nine months ended July 31, 2023 was attributable to approximately $3.0 million related to drilling exploratory wells and approximately $200,000 related to acquisition costs, both of which were capitalized and reflected in the balance of the oil and gas property as of July 31, 2023. These amounts were offset by approximately $1.4 million in amounts used from the Advance to Operators account, which was designated for costs for the HV-1 well.

Current 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.

Previous wording

For the nine months ended July 31, 2024 and 2023, cash (used in)/provided by financing activities was ($248,898) and $5,778,790, respectively. Cash provided by financing activities during the nine months ended July 31, 2024 was primarily attributable to approximately $2.5 million from the issuance of promissory notes, related party notes and convertible notes payable, offset by payments for the convertible debt in the amount of approximately $2.6 million and debt issuance costs of $0.2 million. Cash provided by financing activities during the nine months ended July 31, 2023 was primarily attributable to $6.4 million in gross proceeds from the issuance of common stock and $1.8 million in proceeds from the exercise of warrants, offset by the payment of offering costs of approximately $1.0 million and the payment of notes payables of approximately $1.5 million.

Current 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.

Previous wording

Our cash change was a decrease of approximately $1.3 million as of July 31, 2024. 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.

Current wording

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.

Previous 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 our IPO in April 2023; for the three and nine months ended July 31, 2024, we have recognized $55,000 and $165,000, respectively, in directors’ fees, and for the three and nine months ended July 31, 2023, we have recognized $78,132 and $78,132, respectively, in directors’ fees.

Current 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.

Previous wording

On October 4, 2023 and December 29, 2023, we entered into additional placement agent agreements with Spartan, whereby Spartan would serve as the exclusive placement agent in connection with the closing of private placements. The agreements provided 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 83,333 and 55,000 common shares with exercise prices of $1.32 and $0.55 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, 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.

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.

Current 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.

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 the 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. 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.