Trio Petroleum Corp

Overview

TPET is a California-based oil and gas exploration and development company headquartered in Bakersfield, California, with its principal executive offices located at 5401 Business Park South, Suite 115, Bakersfield, California 93309, and with operations in Monterey County, California, and Uintah County, Utah. The Company was incorporated on July 19, 2021, under the laws of Delaware to acquire, fund, and operate oil and gas exploration, development and production projects, initially focusing on one major asset in California, the South Salinas Project (“South Salinas Project”).

We have had revenue-generating operations since the McCool Ranch Oil Field was restarted on February 22, 2024, and as of the quarter ended April 30, 2024, we recorded approximately $75,000 in net revenues from our McCool Ranch Oil Field.

TPET was formed to initially acquire from Trio Petroleum LLC (“Trio LLC”) an approximate 82.75% working interest, which was subsequently increased to an approximate 85.775% working interest, 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. TPET holds 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. TPET and Trio LLC are separate and distinct companies.

California is a significant part of TPET’s 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. TPET’s interests extend beyond California, however, 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.

Trio LLC is a licensed Operator in California and currently operates the South Salinas Project and the McCool Ranch Oil Field on behalf of TPET and other working interest owners. Trio LLC operates these assets pursuant to joint operating agreements (“JOAs”) between and among Trio LLC and the non-operating, third-party, working interest owners. The non-operating parties have agreed under the JOAs to have the Operator explore and develop these assets for the production of oil and gas as provided thereunder. Trio LLC, as Operator, generally conducts and has significant control of operations, subject to the limitations and constraints of the JOAs, and acts in the capacity of an independent contractor. Operator is obligated to conduct its activities under the JOAs as a reasonable prudent operator, in good workmanlike manner, with due diligence and dispatch, in accordance with good oilfield practices, and in compliance with applicable laws and regulations.

Recent Business Developments

Changes to Company Management

Changes were made in June 2024, to our management team including the following: 1) Robin Ross, one of the original founders of the Company, became our new Chairman and a Director; 2) Stanford Eschner, our former Executive Chairman, became our Vice Chairman, and; 3) Frank Ingriselli stepped down from his position as Vice Chairman and also from his position as a member of the Board of Directors. Additionally, in July 2024, Michael Peterson resigned as Chief Executive Officer (“CEO”) of the Company and Robin Ross became our new CEO as of that date.

Changes to Independent Registered Public Accounting Firm

On May 6, 2024, the Company dismissed BF Borgers CPA PC as the Company’s independent registered public accounting firm. Effective May 8, 2024, the Company retained Bush & Associates CPA LLC as its independent registered public accounting firm.

South Salinas Project

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 expects, in the first calendar quarter of 2025, to takes 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.

McCool Ranch Oil Field

On October 16, 2023, TPET 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, steam generator, boiler, three 5,000 barrel tanks, 250 barrel test tank, 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 through primarily work commitment expenditures that 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.

McCool Ranch successfully restarted field operations, including the restarting of oil production at the 58X and HH-1 wells. These two wells were restarted on February 22, 2024, and the HH-1 well at McCool Ranch has been producing about 47 barrels of oil per day since it was put back on cold production. The 58X well at McCool Ranch was also put back on production but was temporarily idled in order to perform a heat treatment that the Company expects to be accomplished by the first calendar quarter of 2025.

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 about 47 barrels of oil per day. The HH-1 and 35X wells collectively has been producing about 10 to 15 bopd. The 58X well is temporarily idle. Oil production at the HH-1 and 35X wells has been “cold” (i.e., without steam). Both wells have been temporarily idled pending further assessment to place on steam during the first calendar quarter of 2025.

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 expects 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.

The Company is assessing the viability of restarting the last two wells in the restart program, the HH-3 and HH-4 wells, in the first calendar quarter of 2025. 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.

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.

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 such horizontal wells. 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.

Asphalt Ridge Option Agreement

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, totaling 960 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 drilling and production program (the “HSO Program”) on such Asphalt Ridge Leases. TPET also holds the right of first refusal to participate with up to 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 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, the Company funded an additional $25,000 resulting in a 2.25% working interest in the Asphalt Ridge Leases.

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.

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.

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.

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.

Two oil-saturated Cretaceous sandstones are targeted for development at Asphalt Ridge: the Rimrock Sandstone and the underlying Asphalt Ridge Sandstone. TPET expects 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 second quarter of 2024.

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. 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.

The Company has until February 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. If this option is not exercised on or before the deadline or any extension thereof, the option will expire and the Company will forfeit any further right to acquire this additional 17.75% working interest in the initial 960 acres.

Carbon Capture and Storage Project as part of Company’s South Salinas Project

TPET is committed to attempting to reduce its own carbon footprint and, where possible, that of others. For this reason, TPET is taking initial steps to launch a Carbon Capture and Storage (CCS) project as part of the South Salinas Project. The South Salinas Project covers a vast area and is uniquely situated at a deep depocenter where there are thick geologic zones (e.g., Vaqueros Sand, up to approximately 500’ thick), about two miles deep, which could potentially accommodate and permanently store vast volumes of CO2. Four existing deep wells in the South Salinas Project (i.e., the HV 1-35, BM 2-2, BM 1-2-RD1 and HV 3-6 wells) are excellent candidates for use as CO2 injection wells. A CCS project in the future may help reduce TPET’s carbon footprint by sequestering and permanently storing CO2 deep underground at one or more deep wells, away from drinking water sources. Furthermore, three of the aforementioned deep wells are directly located on three idle oil and gas pipelines that could be used to import CO2 to the Company’s CCS Project. TPET has opened discussions with third parties who wish to reduce their own greenhouse gas emissions and who may be interested in participating in our CCS project. TPET believes it feasible to develop the major oil and gas resources of the South Salinas Project and to concurrently establish a substantial CCS project and potentially a CO2 storage hub and/or Direct Air Capture (DAC) hub.

Entry into a Letter of Intent to Acquire Novacor Exploration Ltd. Oil and Gas Assets in Saskatchewan, Canada

On December 18, 2024, TPET entered into a non-binding Letter of Intent (“LOI”) for the acquisition of a 100% working interest in certain petroleum and natural gas assets held by Novacor Exploration Ltd. (“Novacor”), which are located in the prolific Lloydminster, Saskatchewan heavy oil region (the “Proposed Novacor Acquisition”). The stated purchase price of the Proposed Novacor Acquisition is CD$2 million (approximately US$1.4 million based on exchange rates on the date of the LOI) payable US$650,000 in cash and the remainder in shares of common stock of Trio, which TPET would agree to use its commercially reasonable efforts to register for resale in a registration statement filed with the United States Securities and Exchange Commission. Upon execution of the LOI, the Company paid Novacor a good faith deposit of $65,000, which will be applied to the cash portion of the purchase price at closing. Other than obligations of confidentiality and exclusivity contained in the LOI, no other terms are binding until definitive acquisition documents are signed by the parties. The definitive acquisition documents would likely contain customary representations and warranties of the parties and certain conditions to closing, including approval of the Proposed Novacor Acquisition by the board of directors of each of Novacor and TPET, and a condition that TPET raises sufficient financing to consummate the Proposed Novacor Acquisition. Unless extended by the mutual agreement of the parties, the LOI will terminate on the earlier of (i) the mutual agreement of Novacor and TPET, (ii) the execution of definitive acquisition documents or (iii) on February 15, 2025.

South Salinas Project

Oil Rights and Ownership

TPET has an approximate 85.775% working interest in the South Salinas Project. We have a mineral-leasehold of approximately 9,300 gross mineral acres and 7,946 net mineral -acres in one largely contiguous land package from primarily one Lessor, Bradley Minerals. The surface lands at the approximate 9,300 mineral acres are primarily part of the private Porter Ranch. There are six existing idle wells and one active well in the South Salinas Project, and permits are approved by Monterey County for the drilling and testing of two additional wells (i.e., the HV-2 and HV-4 wells).

Description of South Salinas Property and Current Operations

We initiated operations as TPET with the acquisition from Trio LLC of an 82.75% working interest in the South Salinas Project under the terms of a Purchase and Sale Agreement (the “South Salinas Purchase Agreement”) dated September 14, 2021. Our working interest was later increased by 3.026471% and we currently hold an approximate 85.775% working interest and an approximate 68.62% net revenue interest (after all royalties) in the South Salinas Project. The working interest we own includes leases, wells, inventory and 3D seismic data.

We believe the South Salinas Project has the potential to be significant, with an estimated 40.2 million barrels of oil (“MMBO”) plus 42.4 billion cubic feet of gas (“BCFG”), or 47.3 million barrels of oil equivalent (“BOE”), in Probable (P2) Undeveloped reserves and an approximate 100.7 MMBO and 168.5 BCFG, or 128.8 million BOE, in Possible (P3) Undeveloped reserves. Note that the conversion rate used is 6.0 Mcf per 1 BOE. Note that the conversion rate used is 6.0 Mcf per 1 BOE.

Trio LLC and its management team are part owners of the Company and will continue as Operator of the South Salinas Project on behalf of the Company and of the other working interest partners.

There are two contiguous areas of notable oil/gas accumulations in the South Salinas Project, being the Humpback Area (“Humpback Oil Field”) that occurs in the northern part of the project, and the Presidents Area (“Presidents Oil Field”) that occurs in the southern part of the project. Discovery wells have been drilled and completed at both Humpback Oil Field and Presidents Oil Field. The HV-3A well is the first well drilled at the Presidents Oil Field and is its discovery well. About five wells have been drilled at the Humpback Oil Field and of these we consider the BM 2-2 well as its discovery well.

The primary oil and gas objectives in the South Salinas Project are classic fractured Monterey Formation reservoirs (i.e., zones with abundant brittle/fractured intervals of chert, dolomite, limestone and porcelanite) and the Vaqueros Sand. Fractured Monterey Formation is one of the most important and prolific oil/gas reservoirs in California. The primary oil and gas reservoirs occur at approximately 4,000-8,000’ depth. The oil is mid- to high-gravity (18-40° API). The oil and gas targets are in structural traps - this is not a resource play. The structural traps are imaged in 30 square miles of 3D seismic data that is owned by the Company. Importantly, the 3D seismic was acquired after the drilling of all wells in the area except for our HV-3A and HV-1 wells. The 3D seismic provides critical information about how prior wells were not properly located and, more importantly, how the South Salinas Project potentially may be successfully exploited going forward.

The Monterey Formation oil and gas zones have been tested at various wells at the South Salinas Project. The Vaqueros Sand has not yet been tested but the Company believes that it is potentially productive behind-pipe in the BM 2-2 well. TPET intends to perforate and test the Vaqueros Sand in the BM 2-2 well as soon as the necessary permits are in-hand.

We own approximately 30 square miles of three dimensional seismic data (“3D seismic”) at the project. An integrated interpretation of the 3D seismic data and of well data indicates that Presidents Oil Field is a large anticlinal feature covering an area of approximately 1,300 acres, with a major structural, anticlinal high at the location of the HV-3A discovery well, and with two separate, four-way closed anticlines at the northwest, down-plunge-end of the feature. The structural feature at Presidents Oil Field is best characterized as a positive flower structure resulting from transpressional deformation along strike slip faults including the major Rinconada Fault. The Company has determined that production testing may resume at the HV-3A discovery well at Presidents Field. Testing on pump at this well resumed on March 22, 2024.

One of our initial objectives was to drill the HV-1 confirmation well at the President Oil Field. This objective has been accomplished. The following is a discussion of the HV-1 well and its significance:

All of the Company’s acreage and reserves in the South Salinas Project are considered undeveloped. The HV-3A and BM 2-2 wells, and possibly other project wells, are and/or may possibly be capable of oil and/or gas production but additional investments at these wells are necessary prior to establishing commercial oil/gas production and, therefore, reserves and acreage are considered undeveloped. Thus, the total gross undeveloped acreage is approximately 9,300 acres and the total net undeveloped acreage (i.e., net to the Company) is approximately 7,927 acres (i.e., 9,300 acres x 0.8575 = 7,927 acres). The total gross developed acreage is zero acres and the total net developed acreage (i.e., net to the Company) is also zero acres.

As noted elsewhere, on the Company’s leases there are six existing idle wells (i.e., the BM 1-2-RD1, BM 2-2, BM 2-6, HV-1, HV 3-6 and HV 1-35 wells) and one active well (i.e., HV-3A well). Of these seven wells perhaps only the HV-3A and BM 2-2 wells should be considered to probably and/or possibly be capable of economic oil/gas production with their current mechanical completions, whereas it cannot be ruled-out that economic oil/gas production could be established at the other five wells. Thus, on the Company’s leases there may be considered to be two (2) gross productive wells (i.e., the HV-3A and BM 2-2 wells) and 1.715 net productive wells (i.e., 85.75% WI times 2 gross wells = 1.715 net productive wells).

The Porter Ranch is an active working property that supports farming operations, livestock grazing, and the exploitation of oil and gas reserves, as well as the preservation of open space that preserves natural habitat. There is partly overlapping ownership in Bradley Minerals (the Lessor) and in Porter Ranch (the surface owner) and the interests and objectives of the two entities are closely aligned. In some projects there are conflicts between surface and mineral owners, for example with the surface owner discouraging and the mineral owner encouraging development. Importantly, in this project the mineral and surface owners have aligned interests/objectives, and this is beneficial to the South Salinas Project. Total royalty burden at the South Salinas Project is approximately 20%, all of which is held by lessors. TPET and Trio LLC and their associates hold no royalty interests in the South Salinas Project.

Infrastructure at the South Salinas Project includes seven existing wells, six expansive well pads, and three idle Aera Energy oil and gas pipelines. The expansive well pads are important because they can accommodate significant project development without additional disturbance of the surface – the Company believes that this may help expedite the approval of necessary additional permits.

South Salinas Project Property and Future Operations

The Company has drilling permits from Monterey County for two additional wells at the South Salinas Project, being the HV-2 well and the HV-4 well. The Company may drill one or both of these wells in 2025. The Company is evaluating whether to directionally drill both of these wells into the Presidents Oil Field, or to drill one into the Presidents Oil Field and one into the Humpback Oil Field. The production performance of the HV-3A well, which was restarted on March 22, 2024, will bear on the drilling plans for HV-2 and HV-4.

The Company anticipates that it may be desirable in the future to obtain access or ownership of the Aera Energy pipelines (possibly jointly owned with Chevron) to move oil and gas to markets and possibly to move produced water off-site, as well as potentially being used in a Carbon Capture and Storage (CCS) Project. Aera Energy (“Aera”) and Chevron have significant operations a few miles north at the San Ardo Oil Field. Aera’s holdings in California were recently acquired by the companies IKAV, an international asset management group headquartered in Germany, and CPP Investments, a professional investment management organization that manages investments of contributors and beneficiaries of the Canada Pension Plan. In 2024, it was announced that California Resources Corp (“CRC”) and Aera are merging. The Company believes that there are potential synergies between our South Salinas Project and the San Ardo Oil Field that is operated by Aera and Chevron, and possibly soon by CRC. CRC is already an approximate 8% working-interest owner in the South Salinas Project.

There is an application for an UIC water disposal operation at the South Salinas Project that is under review by CalGEM and being modified and updated by Trio LLC. Approval of this water disposal project by CalGEM and Water Boards will be an important part of establishing an economic oil and gas operations.

All of the existing seven wells in the South Salinas Project are currently inactive and temporarily shut-in, except for the active HV-3A well that was restarted on March 22, 2024. When the appropriate permits are in-hand, which will perhaps be in 2025, and when the required funding is in-place, the Company will assess its plans to return the BM 2-2 well to oil and gas production, to reenter and sidetrack three of the wells (the HV 1-35, BM 2-6 and HV 3-6 wells) to optimal locations that are indicated in the 3D seismic data and to then put them on production, and to utilize one well (the BM 1-2-RD1 well) as a water disposal well. TPET is evaluating options (e.g., deepening, sidetracking, recompleting, etc.) at the new HV-1 well, as discussed above. TPET may drill one or both of the HV-2 and HV-4 wells in 2025. The HV-1, HV-2, HV-3A and HV-4 wells may each be produced for its own 18-month period, under the Company’s current exploration/testing permits. TPET is working diligently toward the goal of obtaining permits for full field development, including long-term production and water disposal. These permits are critical for the proper development of our South Salinas Project asset.

TPET is committed to attempting to reduce its own carbon footprint and, where possible, that of others. For this reason, TPET is taking initial steps to launch a Carbon Capture and Storage (CCS) project as part of the South Salinas Project. The South Salinas Project appears ideal for a CCS project. The South Salinas Project covers a vast area and is uniquely situated at a deep depocenter where there are thick geologic zones (e.g., Vaqueros Sand, up to approximately 500’ thick), about two miles deep, which could accommodate and permanently store vast volumes of CO2. Four existing deep wells in the South Salinas Project (i.e., the HV 1-35, BM 2-2, BM 1-2-RD1 and HV 3-6 wells) are candidates for use as CO2 injection wells. A CCS project in the future may help reduce TPET’s carbon footprint by sequestering and permanently storing CO2 deep underground at one or more deep wells, away from drinking water sources. Furthermore, three of the aforementioned deep wells are directly located on three idle oil and gas pipelines that could be used to import CO2 to the Company’s CCS Project. TPET has opened discussions with third parties who wish to reduce their own greenhouse gas emissions and who may be interested in participating in our CCS project. TPET believes it feasible to develop the major oil and gas resources of the South Salinas Project and to concurrently establish a substantial CCS project and potentially a CO2 storage hub and/or Direct Air Capture (DAC) hub. See “Item I. Business - Recent Developments” for further information on the CCS project.

Evaluation of Reserves and Net Revenue

Our evaluation and review of oil and gas reserves and future net revenue attributable to the Company’s interests in the South Salinas Project are based on independent analyses prepared by KLS Petroleum Consulting LLC (“KLSP”), Denver, Colorado. The Company in previous filings with the SEC provided two reserve reports by KLSP, one being entitled “Reserves Attributable to Trio Petroleum Corp South Salinas Area for Development Plan Phases 1 and 2,” (“Prior Reserve Report 1”) and the other entitled “S. Salinas Area, Full Development Reserves Supplement to SEC Report Dated 1-28-2022,” (“Prior Reserve Report 2”) both of which had an effective date of October 31, 2021. KLSP has provided an updated reserve report, with an effective date of April 30, 2024, which is entitled “Reserve Attributable to Trio Petroleum Corp. South Salinas Area for Phased and Full Development” (the “Current Reserve Report”), which is included as an exhibit filed with this Annual Report on Form 10-K (“Annual Report”).

KLSP is an independent, third-party, petroleum engineering firm that meets industry-standards for qualifications, independence, objectivity and confidentiality. The primary technical person, Kenneth L. Schuessler, responsible for preparing the Reserve Report is a registered professional petroleum engineer with decades of experience in the petroleum industry and in analyses of reserves. Mr. Schuessler has significant experience in the petroleum industry and has held important positions with Bergeson Associates, Malkewitz-Hueni Associates, SI International, System Technology Associates and MHA Petroleum Consultants. Importantly, Mr. Schuessler has significant experience in the evaluation and exploitation of Monterey Formation fractured-reservoirs at the giant Elk Hills and Coles Levee Fields in the San Joaquin Basin in California. Mr. Schuessler’s knowledge of the Monterey Formation is highly-relevant to the evaluation of our South Salinas Project at which the fractured Monterey Formation is of critical importance.

KLSP states that the reserves in the “Prior Reserve Report 1” referenced as Exhibit 99.1 to the Annual Report, the “Prior Reserve Report 2” referenced as Exhibit 99.2 to the Annual Report and the “Current Reserve Report” referenced as Exhibit 99.3 to the Annual Report and their determination are consistent with definitions found in Rule 4-10 of SEC Regulation S-X (17CFR part 210), and Subpart 1200 of Regulation SK. The net reserves, costs and revenues are those attributable to the Company. Future net revenue and discounted present value are on a before federal income tax (BFIT) basis.

KLSP is an independent third-party that does not own an interest in any of our properties. Mr. Schuessler is not a permanent employee of our company but we continue to employ the services of KLSP on an as-needed basis.

Our internal staff including our geoscience, drilling, facilities, regulatory, compliance, land, legal and accounting professionals communicated as needed with KLSP to ensure the integrity, accuracy and timeliness of data furnished to KLSP, to review and discuss the properties, methods and assumptions used by KLSP in KLSP’s preparation of the reserve estimates, and to review and discuss KLSP’s conclusions. As discussed immediately above, KLSP is a highly-qualified, independent, petroleum-engineering consulting firm. Mr. Terence B. Eschner, the Company’s former President and a registered professional geologist, who is very knowledgeable about the South Salinas Project, was the Company’s primary contact with KLSP regarding the reserve analyses that were conducted by KLSP. Mr. T. Eschner played a key role providing the Company’s internal controls on the reserve estimation effort that was carried-out by KLSP, while not interfering with KLSP’s analyses so as to ensure that KLSP’s analyses would truly be that of an independent third-party. The Company recognizes that estimating volumes of economically recoverable oil and natural gas reserves is somewhat subjective and that the accuracy of any reserve estimate is partly a function of the quality and accuracy of the available data and interpretations: for this reason and others the Company strove to provide the best available data and interpretations to KLSP. Reserve estimates typically require revision as new information becomes available and/or due to change in conditions and/or due to unforeseen circumstances. Reserve estimates commonly differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, some or all of which may prove to be incorrect.

The technologies utilized by KLSP in their reserve estimation efforts are discussed in detail in the Reserve Report. These technologies included the evaluation and incorporation of data from analog oilfields. Analogs are widely used in reserves estimating, particularly in the early development stages when direct measurement information (production history) is limited. As described in the Society of Petroleum Engineers’ Petroleum Resource Management System (PRMS Section 4.1.1) “The methodology is based on the assumption that the analogous reservoir is comparable to the subject reservoir in regard to reservoir description, fluid properties, and most likely recovery mechanism(s) applied to the project that control the ultimate recovery of petroleum. By selecting appropriate analogs, where performance data of comparable development plans are available, a similar production profile may be forecast. Analogs are frequently applied in aiding in the assessment of economic producibility, production decline characteristics, drainage area, and recovery factor.” The technologies utilized by KLSP also included constructing several numerical models that evaluated the expected oil and gas production under an appropriate range of reservoir characteristics, and which allowed probabilistic estimates of reserves. These models required reservoir properties and, therefore, OOIP as input. The Probabilistic method defined a distribution representing the full range of possible values for input parameters. This included dependencies between parameters that are also defined and applied. These distributions were randomly sampled using Monte Carlo simulation to compute a full distribution of potential in-place and recoverable quantities of oil, gas, and water. Input distributions were included for porosity, permeability, water saturation and net productive thickness. In addition, pore volume compressibility was described with a distribution because its range of uncertainty can impact reservoir pressure and therefore future productivity. S&P Global’s Harmony Enterprise software was used to construct the numerical models for the various reservoir units, being Monterey Yellow, Monterey Blue and Vaqueros Sand reservoir units. A ‘type well’ or calibration model was constructed for each reservoir using the average conditions and reservoir properties cited above. In addition, using the probabilistic distributions of porosity, net thickness, water saturation, permeability and pore volume compressibility, the reservoir model was run 500 times, each time the model selecting via Monte Carlo sampling the input parameters according to the ranges and distributions defined. Each simulation run resulted in a particular value of oil and gas recovery. The cumulative probabilities of the resulting forecasts of ultimate oil and gas recovery were used to identify the reported reserve values.

We have consulted with KLSP and it has provided us estimates of net reserves and/or cash flows as of the end of April 30, 2024, as: 1) there are new technical data as a result of drilling the HV-1 well in 2023; 2) the Company’s WI has increased from approximately 82.75% to approximately 85.775%; 3) new leases have been acquired providing additional well locations; 4) drilling and development schedules have changed; and 5) oil prices have changed. More specifically, the completion results of the HV-1 well appear to indicate that the productive area of the Yellow Zone at the President’s Area may be somewhat smaller than mapped in 2021. On the other hand, the Company has acquired additional leases in the Project area that increase the net well locations targeting the Blue Zone and Vaqueros Sand. The reserves associated with these additional net wells partially offset any possible reduction in reserves due to a smaller Yellow Zone productive area. All of the aforementioned factors are taken into consideration in the estimates of reserves and cash flows as of end of April 30, 2024, as documented in the Current Reserve Report included as Exhibit 99.3 to this Annual Report.

Disclosure of Reserve Volumes and Reserve Values as of the End of April 30, 2024

KLSP in the aforementioned reserve analyses recognizes the occurrence at the South Salinas Project of both Probable (P2) Undeveloped reserves and of Possible (P3) Undeveloped reserves (see: “Glossary of Terms Used to Characterize Reserves & Projects” in Table 22 in the Reserve Report). SEC criteria stipulate that reserves cannot be classified as P1 Proved (i.e., PDP or Proved Developed Producing, PDNP or Proved Developed Not Producing, PUD or Proved Undeveloped) if said reserves are not fully permitted for long-term production. Permits for full field development and long-term production are being sought by the Company, but have not yet been approved for the South Salinas Project and, therefore, KLSP does not recognize Proved reserves at the South Salinas Project.

KLSP provided estimates of net oil and gas reserves and future net revenues, attributable to the Company, for Phase 1, Phase 2 and Phase 3 (Full Development) for the entire South Salinas Project, as shown in the below Table. Future net revenue and discounted present value are on a before federal income tax (BFIT) basis. Both undiscounted and discounted net cash flow to the Company are shown. The discounted dollar amounts shown in the below Table are discounted at 10% and, therefore, are net present value (“NPV”) 10 amounts, whereas KLSP also provided estimated NPV15, 20, 30, 45 and 60. Reserve volumes are expressed in stock tank barrels (STB) of oil and thousands of standard cubic feet of gas (MCF).

There are uncertainties in reserve forecasts and in associated estimates of future cash flows due to uncertainties in various matters that are elaborated above (see: We face substantial uncertainties in estimating the characteristics of our assets, so you should not place undue reliance on any of our measures.). The Company’s estimates of Probable (P2) Undeveloped reserves, Possible (P3) Undeveloped reserves and their respective estimated future cash flows are discussed more-fully above (see Evaluation of Reserves and Net Revenue) and are described in detail in the Current Reserve Report. The Company’s reserve estimates are based on field analogs, numerical models and probabilistic modeling. Copied below are two paragraphs from the Current Reserve Report that further explain the Company’s estimated reserves:

“Because decline curve analysis could not be used to forecast reserves, and since the development of type curves was problematic due to the early historical time frame in which the analog fields were developed, probabilistic methods were employed. The interpretations of open hole logs, core, and test information were used to describe ranges and distributions of key reservoir parameters. These were then input to numerical simulation models that used Monte Carlo sampling and hundreds of runs to derive forecasts of production and ultimate recovery representing P90 (1P), P50 (2P) and P10 (3P) reserve estimates. As indicated in the nomenclature of TABLE 22, these estimates are also known as Proved, Proved+Probable, and Proved+Probable+Possible, respectively. The designation ‘P50’ means there is a 50 percent probability that the actual production will exceed the value reported as the P50 reserves. The P50 value, also considered the Best or Most Likely estimate, is derived from a cumulative frequency distribution of forecast reserves from the Monte Carlo simulations. If Proved reserves have been assigned, Probable reserves are then represented by the difference between the P50 and P90 probabilistic estimates. However, as explained below, Proved reserves have not been assigned in this report because project approval has not been secured by all necessary government entities. Therefore, since there are no Proved or P90 volumes, the Probable reserves disclosed herein, derived from the P50 probabilistic forecasts, are incremental volumes and presented as Probable (P2) reserves. The P10 reserve estimate has a 10 percent probability of exceeding the estimated recovery and is also known as the High estimate. Possible reserves are represented by the difference between the P10 and P50 estimates. Possible reserves are typically larger than Probable reserves. This is the result of the key reservoir parameter distributions reflecting their variation in nature, and when the most favorable parameters are sampled together the resulting calculation provides the highest, but least likely, values of estimated recoveries.”

“Probable reserves are assigned in certain areas where, as described above, reserves could be considered Proved if all regulatory approvals and permits were in place. Probable reserves are also assigned in areas where well control and interpretations of available data provide sufficient geologic evidence of reservoir continuity at structural positions above lowest known hydrocarbons (LKH), and where engineering evidence indicates the reservoir will have the requisite porosity, permeability and oil saturation to produce commercial quantities of oil and gas. The assignment of Possible reserves does not incorporate a larger reservoir area, but rather Possible reserves are assigned to the same wells having Probable reserves because the probabilistic methods employed indicate there may be a greater percentage recovery of hydrocarbons than is appropriate for the ‘Most Likely’ reserve estimates.”

The estimates of Probable (P2) Undeveloped reserves and Possible (P3) Undeveloped reserves and their respective estimated future cash flows have different risk and/or uncertainty profiles and should not be summed arithmetically with each other. For example, estimates of permeability, oil saturation, reservoir thickness and estimated ultimate recovery (EUR) are higher for the P3 reserve estimates than for the P2 reserve estimates (see for example Figure 25 and Table 2 in the Current Reserve Report).

The Probable (P2) and Possible (P3) reserves in the below Table are considered to be undeveloped as of the report’s effective date of April 30, 2024. The HV-3A and BM 2-2 wells are capable of oil and/or gas production but additional investments at both of these wells are anticipated in Phase 1 prior to establishing commercial oil/gas production and, therefore, the reserves at both of these wells are considered undeveloped.

The effective date of the reserves and net cash flows in the Table below is April 30, 2024. If the Company’s working-interest in the South Salinas Project, and/or the size of the Company’s leasehold position at the South Salinas Project, were in the future to increase or decrease, then the reserve estimates would increase or decrease accordingly (note: the Company’s %WI and leasehold position may increase but are not expected to decrease). Similarly, changes in the future of estimates of oil and/or gas that can be economically recovered, in the market values of oil and/or gas, in estimates of reservoir properties such as thickness, oil saturation, porosity, etc., and various other possible changes in the future, would accordingly result in revised reserve estimates and/or revised estimates of net cash flow. No significant discovery or other favorable or adverse event has occurred since April 30, 2024, that would cause a substantial change in estimated reserves and/or cash flow, as of that date.

The KLSP report providing the reserves and net cash flows in the Table below describes a Project constituting the full development of South Salinas. The Project is composed of three phases reflecting the progression of capital deployment with successful efforts and the anticipated time frame associated with regulatory approvals.

Phase 1 uses already-permitted wells and existing wells that can be quicky re-entered upon approval of the Conditional Use Permit (CUP) by Monterey County. Phase 1 confirms the productivity of the Monterey Blue Zone over the larger area, and it establishes cash flow to partially support on-going development. Within Phase 1, the HV-3A will be worked-over to enhance production from its existing completion in the Yellow Zone. The HV-2 and HV-4 will be drilled and completed in the Blue Zone of the Presidents Area. The existing HV-1 is re-entered and deepened through the Blue Zone, and three other existing wells (BM 2-2, HV 1-35-RD1, HV 3-6-RD1) will be re-entered and sidetracked through the Blue Zone in the Humpback Area. Although targeting a completion in the Blue Zone, it is likely that each of these re-entered wells will be drilled to the Vaqueros, immediately below the Blue, with the intention of gathering data and testing the Vaqueros to confirm it prospectivity as a horizontal well development. Phase 1 is being assessed and under consideration to begin in the first half of 2025 with the HV-3A workover and, with receipt of the Conditional Use Permit from Monterey County on or about April 2025, conclude with the sidetrack drilling of the HV 3-6-RD1 later in the year (which well is then scheduled for subsequent production). Phase 1 will deploy an estimated $25.8 million for drilling, completion and associated facility costs including converting the existing BM 1-2 well for water disposal. This capital, as well as that of Phases 2 and 3, include end-of-life plug and abandonment and surface cleanup costs per CALGEM guidelines and regulations.

Phase 2 of the South Salinas Project consists of a 12 well program. The first well is a sidetrack of an existing well (HV 2-6-RD1) through the Blue Zone in September 2025, followed by the drilling of a new well each month thereafter through August 2026. Phase 2 begins with receipt of the remaining (Full) Development Permits from Monterey County. Phase 2 also assumes that by September 2025 Trio should be experiencing the timely approval of drilling permits from CALGEM. Of the 12 Phase 2 wells, four wells will target the Yellow Zone, seven are planned for the Blue Zone, and one well is a horizontal well in the Vaqueros Zone. The capital requirement for Phase 2 well work and facilities expansion is estimated to be $43.2 million.

Phase 3, also referred to as the Full Development Phase, is expected to begin October 2026 with the utilization of three rigs drilling continuously for about four years. Two of the rigs will be used to drill 101 Blue Zone wells, while the third rig will be used to drill 20 Yellow Zone wells and 16 horizontal Vaqueros wells. Phase 3 will require an estimated $467 million of capital. When combined with Phases 1 and 2 the South Salinas Project is then expected to generate positive cash flow by 2029. When considered alone Phases 1 and 2 are forecast to generate positive cash flows in 2026 and 2027, respectively. These expectations assume the realization of the Probable (P2) reserves that are based on the ‘most likely’ forecasts of production. The KLSP report also provides the incremental volumes and cash flows associated with the realization of Possible (P3) reserves and are provided in the Table below. The BOE’s cited in the Table use a conversion factor of 6 Mcf of gas per BOE.

The combined Phases 1-3 (Total South Salinas Project) are estimated to recover 40.2 million stock tank barrels of oil (MMSTB) and 42.4 billion standard cubic feet of gas (BCF). This represents 47.3 million BOE of Probable (P2) Undeveloped reserves. The estimated incremental reserves associated with Possible (P3) reserves are 100.7 MMSTB of oil and 168.5 BCF of gas, or 128.7 million BOE (part “F” of the Table below). The combined Phases 1-3 estimated net cash flow to the Company, discounted at 10%, is $474.5 million for the Probable (P2) Undeveloped reserves. Realization of the forecasts associated with Possible reserves provides an additional $2.5 billion for Trio’s interest in the South Salinas Project (again, as shown in part “F” of the Table below).

Table 1: Estimated Undeveloped Reserves and Cash Flow

ESTIMATED UNDEVELOPED RESERVES AND CASH FLOW

Reasonable Expectations of Reserve Analyses

This Annual Report provides a summary of risks and detailed discussions of risks relating to our business. The Company recognizes these risks as being real and substantial. Nevertheless, the Company has reasonable expectations that the Company’s South Salinas Project will prove to have reserves approximately as estimated, that the Company will have adequate funding to develop the reserves, and that there will exist the legal right to develop the Company’s reserves in the South Salinas Project, including the rights to full-field development, to long-term production and to deliver natural gas to market via pipeline, recognizing as discussed elsewhere hereunder that there may be project delays and/or obstacles related to obtaining necessary permits from regulatory agencies. Furthermore and more specifically, the Company has a reasonable expectation that the primary governmental regulatory agencies that are currently and/or that will be involved in the permitting processes, which agencies will primarily be CalGEM, State Water Boards and Monterey County, will determine to approve the Company’s applications for permits for various reasons that are discussed below. See “Item 1A. Risk Factors -Risks Relating to Our Business -We may face delays and/or obstacles in project development due to difficulties in obtaining necessary permits from federal, state, county and/or local agencies, which may materially affect our business;” “Item 1A. Risk Factors -Risks Relating to Our Business - We face substantial uncertainties in estimating the characteristics of our assets, so you should not place undue reliance on any of our measures;” “Item 1A. Risk Factors -Risks Relating to Our Business - The drilling of wells is speculative, often involving significant costs that may be more than our estimates, and drilling may not result in any discoveries or additions to our future production or future reserves, or it may result in disproving or diminishing our current reserves.; “Item 1A. Risk Factors -Risks Relating to Our Business - Seismic studies do not guarantee that oil or gas is present or, if present, will produce in economic quantities; and “Item 1A. Risk Factors -Risks Relating to Our Business - We are subject to numerous risks inherent to the exploration and production of oil and natural gas.”

The Company currently is preparing a full-field development plan that is expected to include the following key elements:

The Company during Phase 1 or shortly thereafter expects to engage a third-party expert consulting company (“Environmental Consultant”) to prepare a Full Environmental Impact Report (Full EIR) on the Company’s full-field development plan. It is customary in Monterey County in these matters for the Environmental Consultant to be chosen by and/or agreed to by the County, for the Environmental Consultant to report directly to the County’s technical staff, and to avoid any real or perceived conflicts of interest for County to directly compensate the Environmental Consultant from funds paid to County by the Operator. The Company has a reasonable expectation that the Full EIR will determine that the full-development project will have “a less than significant environmental impact” with a “mitigated negative declaration”, meaning that the Project will be deemed environmentally acceptable with specific, delineated mitigation-measures being taken to protect and prevent, as far as possible, damage to life, health, property, natural resources, climate and other similar matters (e.g., water and air quality, scenic views or “viewshed”, etc.). The Company has a reasonable expectation that it will be able to obtain a Full EIR with a mitigated negative declaration for the full-field development project that should help expedite approval of necessary permits.

The surface lands at the Project are privately owned by the Porter Ranch and the subsurface mineral rights are privately owned by Lessor Bradley Minerals Company. The Porter Ranch is a multi-use working-ranch with operations that include the Company’s oil and gas operations as well as extensive agricultural and livestock operations. The Porter Ranch (surface owners) and the Bradley Minerals Company (mineral owners) are fully-aligned in their desire to develop the oil and gas resources at the Project. The Company has a reasonable expectation that the surface and mineral owners will be fully-aligned and fully-supportive of the Company’s full-field development plan and that this undivided support should help expedite approval of necessary permits.

CalGEM has statutory mandates to ensure both energy production and environmental protection. The Company has a reasonable expectation that CalGEM will have a favorable view of the Company’s full-development plan for the South Salinas Project and that CalGEM accordingly will determine that the Company’s applications for necessary permits should be approved. The Company furthermore has a reasonable expectation that State Water Boards will, similarly to CalGEM, have a favorable view of the Company’s full-development plan for the South Salinas Project and that Water Boards accordingly will determine that the Company’s applications for necessary permits should be approved.

The Company has a reasonable expectation that the County Commissioners and more importantly the County Supervisors (the Supervisors are a higher authority than the Commissioners) of Monterey County will determine that the Company’s applications for necessary permits should be approved. This reasonable expectation is based, in part, on the expected benefits of the Project to the County and to the State of California that include the following statistics and claims from Californians for Energy Independence:

The Company has a reasonable expectation that the primary governmental regulatory agencies (i.e., CalGEM, State Water Boards and Monterey County) that are and/or that will be involved in the permitting process will endeavor to avoid any unconstitutional takings of private property that might result from denying permits for the South Salinas Project. The Company has a reasonable expectation that governmental regulatory agencies will wish to avoid any unconstitutional takings of private property and that this should help expedite approval of necessary permits.

Trio LLC, which is Operator of the South Salinas Project, has significant experience in Monterey County in obtaining necessary permits (e.g., drilling permits for exploration and development wells, permits for Underground Injection Control water-disposal projects, permits for constructing facilities, permits for constructing pipelines and power lines, etc.) from governmental regulatory agencies (e.g., CalGEM, Monterey County, and other local agencies). More specifically, Trio LLC, as Operator, developed both the Lynch Canyon Oil Field and the Hangman Hollow Area of the McCool Ranch Oil Field, both of which oilfields are located in Monterey County approximately seven miles north of the Company’s South Salinas Project. The Company has a reasonable expectation that, given its own expertise and the expertise and local experience of Trio LLC as an Operator, that the necessary permits may be obtained from governmental regulatory agencies and thus that there will exist the legal right to develop the Company’s reserves in the South Salinas Project.

The Company has a reasonable expectation that it will be able to negotiate an agreement with Aera Energy to utilize their existing idle gas pipeline and one or more of their two idle oil pipelines that exist at the Company’s South Salinas Project. The pipelines extend from the Company’s South Salinas Project to the San Ardo Oil Field that is located approximately three miles to the north. San Ardo is a giant oilfield with cumulative oil recovery to-date of approximately 500 million barrels of oil - it is ranked among the largest 100 oilfields in the United States by the Energy Information Administration of the U.S. Department of Energy and is commonly cited as being among the largest ten oilfields in California. San Ardo uses significant natural gas for operations including to run steam-generators to generate steam for steam-injection into wells as part of thermal oil-recovery operations (i.e., to produce the heavy oil that occurs at the field). An additional supply of natural gas would be beneficial at San Ardo and the high-gravity oil that occurs in the Company’s South Salinas Project could be beneficially blended with the heavy oil at San Ardo (source: personal communication between Trio personnel and Aera Energy personnel: September, 2022). It is feasible that opening the three mile section of the pipelines will be agreeable to the Company and to Aera Energy to the financial benefit of all parties. If this arrangement cannot be realized, and if funding and the oil and gas reserves in the Project are sufficient, the Company and the Operator Trio LLC will seek permits for new oil and/or gas pipelines, perhaps along the right-of-way of the existing pipelines to minimize new surface disturbance. The Company has a reasonable expectation that it will be able to establish the transport of oil and/or gas, and especially gas, to market via pipelines, whether through the existing Aera Energy pipelines or new pipelines.

The Company has a reasonable expectation that the Company’s South Salinas Project will prove to have reserves approximately as estimated. The Company has this reasonable expectation because it believes that:

The Company has a reasonable expectation that it will have adequate funding to develop the reserves at the South Salinas Project. This reasonable expectation of adequate funding is based on anticipated proceeds from additional capital raises and anticipated operating revenues:

For all of the reasons discussed above in this section, the Company has a reasonable expectation that the Company’s South Salinas Project will prove to have reserves approximately as estimated, that the Company will have adequate funding to develop the reserves, and that there will exist the legal right to develop the Company’s reserves in the Project.

Employees

As of December 31, 2024, we had one employee, who is located in Canada.

Subsidiaries

The Company has no subsidiaries.