EDGAR 10-K Filing

Company CIK: 1898766
Filing Year: 2025
Filename: 1898766_10-K_2025_0001493152-25-002760.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS.
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:
● The HV-1 well is located about two miles northwest of the HV-3A discovery well and for this reason it is considered a “confirmation well” intended to help confirm the size of lateral extent of the field. The HV-1 surface hole location (“SHL”) is located in about the center of T24S-R10E-Section 14. The well was directionally drilled approximately 2,600 feet toward the southeast and its bottom hole location (“BHL”) is located in T24S-R10E-Section 13.
● The HV-1 well spud on about May 5, 2023, and was completed at its total depth (“TD”) of about 6,641 feet (measured depth) on about May 15, 2023.
● The HV-1 confirmation well is located on the larger of the aforementioned two down-plunge, four-way closed anticlines.
● There were primarily three reservoir objectives in the HV-1 well, being the Yellow Zone (aka Yellow Chert), the underlying Brown Zone (aka Brown Chert) and the underlying Mid-Monterey Clay, all of which are stratigraphic subunits of the Miocene-age Monterey Formation. The Yellow and Brown zones are both attributed oil and gas reserves at Presidents in the Company’s reserve report as filed with the SEC. The Mid-Monterey Clay is nowhere assigned reserves in the Company’s reserve report, although it did have significant oil/gas shows in the HV-3A discovery well and periodically may have contributed to the flow of oil and gas to surface at said well.
● The 3D seismic data indicate that the Yellow and Brown zones have four-way closure (i.e., anticlinal rollover in one of the subsidiary, down-plunge anticlines) at the location of the HV-1 well, whereas at this location the Mid-Monterey Clay may have fault closure (within the positive flower structure) but lacks rollover. The directional drilling plan for the HV-1 well was designed such that the well would penetrate the Yellow and Brown zones near the tops of their anticlinal closures and to continue downward into the Mid-Monterey Clay where anticlinal closure apparently does not occur.
● The Yellow Zone, Brown Zone and Mid-Monterey Clay were encountered in the HV-1 well largely as predicted including with respect to depth, thickness, lithology, wireline-log characteristics and oil and gas shows including free oil in cuttings and in the mud pit. The Company believes that the HV-1 well has confirmed that there is a major oil and gas accumulation in the Presidents Oil Field, as the Company announced in a press release on May 16, 2023.
● Confirmation of a major oil and gas accumulation by itself does not confirm whether economic oil/gas production can be established. The HV-1 has undergone production testing to evaluate commerciality. Production testing at the HV-1 well was initially carried-out from the bottom up (i.e., by testing the deeper Mid-Monterey Clay zone first and working upward to the shallower Brown and Yellow zones), and the Brown and Mid-Monterey Clay zones were subsequently retested. The Mid-Monterey Clay, Brown Zone and Yellow Zone all underwent production testing. Oil and gas were recovered but commercial production was not established.
● Operations may continue, for example deepening, sidetracking or additional testing, at the HV-1 well but it is currently idle.
● The HV-1 well is the newest well in the South Salinas Project and is the only exploratory well drilled in the last three fiscal years at the project.
● The Company considers it premature to deem HV-1 either a dry development well or a net productive well. Additional operations, including possibly deepening or sidetracking, and additional testing, are feasible at HV-1. Thus, there has been no net productive well or dry development well drilled in the last three fiscal years at the South Salinas Project. Prior to the drilling of the HV-1 well, the newest well at the Project was the HV-3A discovery well that was drilled in 2018.
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 $2.5 billion for Trio’s interest in the South Salinas Project (again, as shown in part “F” of the Table below).
Table 1: Estimated Undeveloped Reserves and Cash Flow
ESTIMATED UNDEVELOPED RESERVES AND CASH FLOW
A. Phase 1 Undeveloped Reserve Categories Net Trio
Undeveloped
Oil Reserves
(Stock Tank
Barrels)
Net Trio
Undeveloped
Gas Reserves
(1000 CF,
or MCF)
Net Trio
Undeveloped
Reserves
(Barrels Oil
Equivalent)
Trio
Undiscounted
Net Cash
Flow ($)
Trio Net
Cash Flow
Discounted
at 10% ($)
Probable (P2) Undeveloped of Phase 1 2,017,620.0 2,133,250.0 2,373,161.7 $ 107,374,250.00 $ 33,698,230.00
Possible (P3) Undeveloped of Phase 1 3,841,380.0 7,449,100.0 5,082,896.7 $ 307,886,460.00 $ 139,189,600.00
B. Phase 2 Undeveloped Reserve Categories Net Trio
Undeveloped
Oil Reserves
(Stock Tank
Barrels)
Net Trio
Undeveloped
Gas Reserves
(1000 CF,
or MCF)
Net Trio
Undeveloped
Reserves
(Barrels Oil
Equivalent)
Trio
Undiscounted
Net Cash
Flow ($)
Trio Net
Cash Flow
Discounted
at 10% ($)
Probable (P2) Undeveloped of Phase 2 3,227,940.0 3,392,940.0 3,793,430.0 $ 168,622,080.00 $ 45,938,680.00
Possible (P3) Undeveloped of Phase 2 6,759,630.0 11,735,140.0 8,715,486.7 $ 527,635,330.00 $ 210,766,130.00
C. Phase 3 (Full Development) Undeveloped Reserve Categories Net Trio
Undeveloped
Oil Reserves
(Stock Tank
Barrels)
Net Trio
Undeveloped
Gas Reserves
(1000 CF,
or MCF)
Net Trio
Undeveloped
Reserves
(Barrels Oil
Equivalent)
Trio
Undiscounted
Net Cash
Flow ($)
Trio Net
Cash Flow
Discounted
at 10% ($)
Probable (P2) Undeveloped of Phase 3 34,940,100.0 36,918,030.0 41,093,105.0 1,837,183,060.0 394,874,030.0
Possible (P3) Undeveloped of Phase 3 90,057,820.0 149,348,300.0 114,949,203.3 7,054,575,390.0 2,185,998,350.0
D. (P2) Undeveloped Reserves for Phases 1, 2 & 3 Net Trio
Undeveloped
Oil Reserves
(Stock Tank
Barrels)
Net Trio
Undeveloped
Gas Reserves
(1000 CF,
or MCF)
Net Trio
Undeveloped
Reserves
(Barrels Oil
Equivalent)
Trio
Undiscounted
Net Cash
Flow ($)
Trio Net
Cash Flow
Discounted
at 10% ($)
Probable (P2) Undeveloped of Phase 1 2,017,620.0 2,133,250.0 2,373,161.7 $ 107,374,250.00 $ 33,698,230.00
Probable (P2) Undeveloped of Phase 2 3,227,940.0 3,392,940.0 3,793,430.0 $ 168,622,080.00 $ 45,938,680.00
Probable (P2) Undeveloped of Phase 3 34,940,100.0 36,918,030.0 41,093,105.0 $ 1,837,183,060.00 $ 394,874,030.00
Total Probable (P2) Undeveloped of Phases 1, 2 & 3 40,185,660.0 42,444,220.0 47,259,696.7 $ 2,113,179,390.00 $ 474,510,940.00
E. (P3) Undeveloped Reserves for Phases 1, 2 & 3 Net Trio
Undeveloped
Oil Reserves
(Stock Tank
Barrels)
Net Trio
Undeveloped
Gas Reserves
(1000 CF,
or MCF)
Net Trio
Undeveloped
Reserves
(Barrels Oil
Equivalent)
Trio
Undiscounted
Net Cash
Flow ($)
Trio Net
Cash Flow
Discounted
at 10% ($)
Possible (P3) Undeveloped of Phase 1 3,841,380.0 7,449,100.0 5,082,896.7 $ 307,886,460.00 $ 139,189,600.00
Possible (P3) Undeveloped of Phase 2 6,759,630.0 11,735,140.0 8,715,486.7 $ 527,635,330.00 $ 210,766,130.00
Possible (P3) Undeveloped of Phase 3 90,057,820.0 149,348,300.0 114,949,203.3 $ 7,054,575,390.00 $ 2,185,998,350.00
Total Possible (P3) Undeveloped of Phases 1, 2 & 3 100,658,830.0 168,532,540.0 128,747,586.7 $ 7,890,097,180.00 $ 2,535,954,080.00
F. Undeveloped Reserve Categories for Phases 1, 2 & 3 Net Trio
Undeveloped
Oil Reserves
(Stock Tank
Barrels)
Net Trio
Undeveloped
Gas Reserves
(1000 CF,
or MCF)
Net Trio
Undeveloped
Reserves
(Barrels Oil
Equivalent)
Trio
Undiscounted
Net Cash
Flow ($)
Trio Net
Cash Flow
Discounted
at 10% ($)
Total Probable (P2) Undeveloped of Phases 1, 2 & 3 40,185,660.0 42,444,220.0 47,259,696.7 $ 2,113,179,390.00 $ 474,510,940.00
Total Possible (P3) Undeveloped of Phases 1, 2 & 3 100,658,830.0 168,532,540.0 128,747,586.7 $ 7,890,097,180.00 $ 2,535,954,080.00
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:
● Documentation of oil and gas reserves at the Project, including whatever results of the Phase 1 development program are both available and pertinent;
● Documentation of the proposed wells and facilities that would be necessary to underpin full-field development and long-term production;
● Details as to how the Company would minimize surface footprint by directionally drilling from existing well pads and similarly largely using existing pads for facilities, which well pads at that time may include the currently existing six well pads plus the two wells pads that are planned for construction at the HV-2 and HV-4 well sites. Use of these eight well pads for additional wells and facilities will minimize the need for additional surface disturbance in the full-field development plan. The Company’s proposal to use existing well pads to minimize surface footprint should help expedite approval of necessary permits;
● Details as to how the Company would endeavor to minimize surface disturbances associated with pipeline construction by utilizing the existing Aera Energy gas pipeline and one or more of the two existing Aera Energy oil pipelines. The Company’s proposal to use existing pipelines to minimize surface disturbance should help expedite approval of necessary permits;
● Documentation as to how the Company proposes to minimize or eliminate the trucking of oil by utilizing one or more of the two existing Aera Energy oil pipelines. The Company’s proposal to use existing pipelines to minimize truck traffic should help expedite approval of necessary permits;
● Documentation as to how the Company’s operations will be carried-out in an environmentally and socially responsible manner; and
● A Full Environment Impact Report, discussed immediately below.
● A Carbon Capture and Storage Project as part of the South Salinas Project.
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:
● Oil and natural gas production in Monterey County plays a fundamental role in sustaining the energy supply and quality of life of the County’s 440,000 residents;
● Oil and natural gas are vital to ensuring the health and safety of California’s communities;
● the oil and gas industry contributes to Monterey County’s economy by providing a safe and reliable energy supply that fuels cars, heats homes, powers businesses, grows food and produces everyday products. County residents depend on oil and gas to produce and deliver their food and water supply, and for the countless products they use every day (e.g., cell phones, computers, medical devices, eyeglasses, asphalt roads, plastic kayaks, wet suits, tires, car batteries, etc.) and natural gas is an important local energy source for heating and cooking;
● Roughly 75% of the oil and gas used in California is imported from foreign countries, many of which are unstable and/or have poor human rights, labor and/or environmental standards;
● Monterey County and California lead the way in safe, affordable and environmentally responsible oil and gas production with the world’s strictest regulations;
● More than 25 local, state and federal agencies oversee local oil and gas production in Monterey County;
● Monterey County’s oil and gas workforce includes veterans, union members, first generation citizens, single parents and others, many of whom live and raise their families in the County and care deeply about the community;
● Monterey County’s oil and gas industry directly supports approximately 868 full-time jobs with benefits, and nearly 50% of the workforce is ethnically diverse;
● Average annual pay is $107,000 in oil industry: these are good paying jobs and the average wage is more than double the $51,900 average for all private sector jobs in Monterey County;
● The oil industry supports $69 million per year in wage payments to employees in the County;
● The oil industry has a positive impact on the region, providing high paying, full-time jobs, and upward mobility for workers including those with high school and/or technical degrees;
● Property taxes represent the County’s largest source of general revenues, and are used to support schools, public safety, health, social assistance, services to combat homelessness, and other services;
● Property taxes paid to the County from two operators at the San Ardo Oilfield are approximately $44 million per year: these operators are among the highest property-tax taxpayers in the County; and
● The economic output of the oil industry in Monterey County is an estimated $644 million per year.
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 geologic structures that contain oil and gas in the South Salinas Project occur approximately as mapped based on the integrated interpretations of three-dimensional seismic data and data from wells already drilled at the Project, including the BM 2-2 and HV-3A discovery wells and the recently-drilled HV-1 well;
● The estimated oil and gas reserves at the South Salinas Project are well-supported by geologic analogues to other large and prolific oil and gas fields in California; and
● The Reserve Report and Supplemental Reserve Report as prepared by KLSP are reasonable.
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:
● The Company believes that the South Salinas Project has the potential to be both beneficial to society and profitable to shareholders and, for these and other reasons, that the Company may raise funds sufficient to cover project costs including the costs of Phase 1. As discussed elsewhere hereunder, Phase 1 is a development project with expenditures that are appropriately scaled to the capital raise that the Company anticipates may be achieved;
● There are significant anticipated costs in the South Salinas Project primarily in years 2022-2027 due, in large part, to the estimated costs of drilling and completing oil and gas wells and building Project infrastructure. It is anticipated that these costs will be partly covered by capital raises and/or financing and, furthermore, that these costs may be partly and possibly entirely covered by revenue from oil and gas sales;
● The Company has a reasonable expectation that additional capital raises will be successfully accomplished, as needed. This reasonable expectation is based on the experience and track record of the Company’s management team which has a demonstrated ability to secure funding for oil and gas exploration, development and production ventures, including that of Robin Ross, our Chief Executive Officer. The Company plans to leverage the relationships and experience of Mr. Ross and other members of its management team in private and public equity fundraising to raise capital for the Company, if and as needed. Furthermore, this reasonable expectation is based on the confidence of Spartan Capital Securities, LLC, the Company’s investment banker, in both the Company and in the Project, and the various methods available for securing capital including financing plans that may be developed in collaboration with our bankers and/or future lenders based on reserves, cash flow and/or other considerations. The Company has a reasonable expectation that, between cash and equity, it will be able to raise whatever capital is necessary to successfully develop the South Salinas Project.
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.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS.
Our future operating results could differ materially from the results described in this Annual Report due to the risks and uncertainties described below. You should consider carefully the following information about risks in evaluating our business. If any of the following risks actually occur, our business, financial condition, results of operations and future growth prospects would likely be materially and adversely affected. Additional risks and uncertainties not presently known to us or that we currently deem immaterial also may impair our business operations in these circumstances, the market price of our securities would likely decline. In addition, we cannot assure investors that our assumptions and expectations will prove to be correct. Important factors could cause our actual results to differ materially from those indicated or implied by forward-looking statements. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results Of Operations - Cautionary Statement Regarding Forward-Looking Information” for a discussion of some of the forward-looking statements that are qualified by these risk factors. Factors that could cause or contribute to such differences include those factors discussed below.
Summary of Risk Factors
Investing in our common stock involves risks. In addition, our business and operations are subject to a number of risks, which you should be aware of prior to making a decision to invest in our common stock. These risks are discussed more-fully in the “Item 1A. Risk Factors” section of this Annual Report beginning on page 16. Below is a summary of these risks.
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, 2024 and 2023.
● 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.
● Due to our contractor model for drilling operations, we will be vulnerable to any inability to engage one or more drilling rigs and associated drilling personnel.
● We have faced and may in the future face conflicts of interest in negotiations with related parties, including in negotiations with Lafayette Energy Corp and/or Trio LLC, entities which certain of our current and former employees, officers and directors serve as employees, officers or directors, for example concerning assets where TPET and one of these entities have interests.
● We are operating in a highly capital-intensive industry, and any sales of produced oil and gas may be insufficient to fund, sustain, or expand revenue-generating operations.
● We face substantial uncertainties in estimating the characteristics of our assets, so you should not place undue reliance on any of our measures.
● 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.
● We have been an exploration stage entity and our future performance is uncertain.
● Seismic studies do not guarantee that oil or gas is present or, if present, will produce in economic quantities.
● The potential lack of availability of, or cost of, drilling rigs, equipment, supplies, personnel, and crude oil field services could adversely affect our ability to execute on a timely basis exploration and development plans within any budget.
● Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms in the future, which may in turn limit our ability to develop our exploration, appraisal, development and production activities.
● A substantial or extended decline in global and/or local oil and/or natural gas prices may adversely affect our business, financial condition and results of operations.
● Unless we replace our petroleum reserves, our reserves and production will decline over time. Our business is dependent on the successful development of our various current petroleum assets and projects and/or on continued successful identification and exploitation of other petroleum assets and prospects, whereas the identified locations in which we drill in the future may not yield oil or natural gas in commercial quantities.
● Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets or delay our future oil and natural gas production.
● We are subject to drilling and other operational environmental hazards.
● The development schedule of oil and natural gas projects, including the availability and cost of drilling rigs, equipment, supplies, personnel and oilfield services, is subject to delays and cost overruns.
● Participants in the oil and gas industry are subject to numerous laws that can affect the cost, manner or feasibility of doing business.
● We and our operations are subject to numerous environmental, health and safety regulations which may result in material liabilities and costs.
● Our operations may be dependent on sources of electricity and/or natural gas that may be unreliable or costly.
● We expect continued and increasing attention to climate change and energy transition issues and associated regulations to constrain and impede the oil/gas industry.
● We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas operations, for which we may not have adequate insurance coverage.
Risks Relating to Our Securities
● If we are not able to comply with the applicable continued listing requirements or standards of the NYSE American, our common stock could be delisted from the NYSE American.
● Our share price may be volatile, and purchasers of our common stock could incur substantial losses.
● We do not intend to pay dividends on our common stock.
Other Risks
● We may be subject to risks in connection with acquisitions and the integration of significant acquisitions may be difficult.
● If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be adversely affected.
● The requirements of being a public company may strain our resources, result in more litigation and divert management’s attention.
● We are subject to the examination of our tax returns and other tax matters by the U.S. Internal Revenue Service, states in which we conduct business, and other tax authorities. If our effective tax rates were to increase, or if the ultimate determination of our taxes owed is for an amount in excess of amounts previously accrued, our financial condition, operating results and cash flows could be materially adversely affected.
● Our amended and restated certificate of incorporation provides that the Court of Chancery of the State of Delaware will be the sole and exclusive forum for substantially all disputes between us and our shareholders, which could limit its stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees.
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, 2024 and 2023.
For the year ended October 31, 2024, we generated revenues of $213,204, reported a net loss of $9,626,797 and cash flows used in operating activities of $3,840,744. For the year ended October 31, 2023, we generated no revenues, reported a net loss of $6,544,426, and cash flows used in operating activities of $4,036,834. As of October 31, 2024, we had an accumulated deficit of $20,073,679. Our management has concluded that our accumulated deficit and no source of revenue sufficient to cover our cost of operation as well as our dependence on private equity and other financings 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, 2024 and 2023.
Our financial statements do not include any adjustments that might result from the outcome of this uncertainty. These adjustments would likely include substantial impairment of the carrying amount of our assets and potential contingent liabilities that may arise if we are unable to fulfill various operational commitments. In addition, the value of our securities would be greatly impaired. Our ability to continue as a going concern is dependent upon generating sufficient cash flow from operations and obtaining additional capital and financing. If our ability to generate cash flow from operations is delayed or reduced and we are unable to raise additional funding from other sources, we may be unable to continue in business. For further discussion about our ability to continue as a going concern and our plan for future liquidity, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Ability to Continue as a Going Concern.”
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.
We are subject to a number of federal, state, county and local laws, regulations and other requirements relating to oil and natural gas operations. The laws and regulations that affect the oil and natural gas industry are under constant review for amendment or expansion. Some of these laws, regulations and requirements result in challenges, delays and/or obstacles in obtaining permits, and some carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business, can affect and even obstruct our operations and, consequently, can affect our profitability.
Various permits for exploratory drilling and production-testing are in-hand for the South Salinas Project, whereas permits for long-term production, conditional use permits, water disposal and other matters have not yet been obtained. There are challenges and uncertainties in obtaining permits, which may result in delays and/or obstacles to developing our oil/gas assets. California and Colorado are two States that are considered to have challenging regulatory environments and Monterey County in California also has this reputation. We may experience delays and/or obstacles to exploiting our assets, and also may be required to make large expenditures to comply with governmental laws and regulations and to obtain permits.
The Company currently has permits from Monterey County for the HV-1, HV-2, HV-3A and HV-4 wells, permitting each of these wells to be tested by producing it for its own 18 month period with the Company selling the produced oil and/or gas, and disposing of produced water from these wells by trucking it offsite to a licensed water-disposal facility and, if necessary, flaring on-site any natural gas that is not used on-site in field operations. The Company is currently seeking a permit from CalGEM and State Water Boards to dispose of produced water at the Project.
The Company is seeking and/or expects to seek from regulatory agencies any and all additional permits as may be necessary, which may include but not be limited to conditional use permits, drilling permits, permits for full-field development, permits for long-term production, permits for additional water disposal wells, permits for transport of oil and gas via pipelines, and such similar permits as are customarily required in oil and gas exploration and development projects. Delays and/or obstacles in obtaining necessary permits may materially affect our business, for example:
● it will not be possible to produce the HV-1, HV-2, HV-3A and HV-4 wells after their individual eighteen-month production-test periods without additional permits;
● project economics will be less favorable if all necessary permits for on-site water disposal are not approved;
● it will not be possible to drill new wells other than the HV-2 and HV-4 wells without new permits;
● it will not be possible to utilize five of the existing Project wells (i.e., the BM 2-2, BM 1-2-RD1, HV 2-6, HV 3-6 and/or HV 1-35) without new permits, including conditional use permits from Monterey County, and other customary permits from local and State agencies;
● it will not be possible to initiate full-field development without new permits; and
● it will not be possible to establish long-term production without new permits.
Due to our contractor model for drilling operations, we will be vulnerable to any inability to engage one or more drilling rigs and associated drilling personnel.
Our operation plan currently depends on using the services of independent drilling contractors such as Ensign Energy that operate their own drilling rigs using their own personnel. Lack of rig availability from independent drilling contractors would hinder our operations. Our assets include operations in California and Ensign, for example, has indicated that it is moving its drilling rigs out of California due to decline of California’s oil and gas industry. Lack of rig availability may be a problem if there is a drilling boom and rigs are reserved by other operators into the foreseeable future, or contrarily if there is a general lack of rigs as may occur if the oil industry is in a slump and rigs are taken out of service. The capacities of standard oil field service companies in general (i.e., in addition to drilling contractors) in California have declined and continue to decline in parallel with the continuing decline of California’s oil and gas industry.
We have faced and may in the future face conflicts of interest in negotiations with related parties, including in negotiations with Lafayette Energy Corp and/or Trio LLC, entities which certain of our current and former employees, officers and directors serve as employees, officers or directors, for example concerning assets where TPET and one of these entities have interests.
TPET and Lafayette Energy Corp (“LEC”) both have equity interests in the Asphalt Ridge Project, Utah. TPET and Trio LLC both have equity interests in the South Salinas Project and the McCool Ranch Oil Field, California.
Gregory L. Overholtzer, our Chief Financial Officer, is also employed by Lafayette Energy Corp (“LEC”) as its Chief Financial Officer. TPET and LEC both have interests in the Asphalt Ridge Asset in Utah. TPET has an option at this asset and potential conflicts of interests may arise. Mr. Overholtzer, through his relationship with LEC, might benefit in the event TPET is unable to exercise its option to acquire this asset.
Stanford Eschner, who we employed as our Vice Chairman until December 31, 2024 and who continues as our Vice Chairman in a non-employee capacity, and Steven Rowlee, who we employed as our Chief Operating Officer until December 31, 2024 and was officially released from his duties by the Board as of January 2, 2025, are also employed by Trio LLC. Stanford Eschner is Trio LLC’s Chairman and Steven Rowlee is its Vice President. Terence B. Eschner, who we employed as our President until December 31, 2024 and was officially released from his duties by the Board as of January 2, 2025, also works as a consultant to Trio LLC through his company Sarlan Resources, Inc. Trio LLC and its management team are part owners of the Company and will continue as Operator of the South Salinas Project and the McCool Ranch Oil Field on behalf of Trio Corp and of the other working interest partners.
In October 2023, the Company acquired an approximate 22% working interest in the McCool Ranch Oil Field from Trio LLC, which the Company announced in a press release on October 18, 2023. The Company is acquiring this interest in the McCool Ranch Oil Field primarily through work commitment expenditures that will be allocated to restart production at the field.
Since Trio LLC is partly owned and controlled by members of our management, acquisitions of Trio LLC’s assets by the Company constitute related party transactions and, therefore, a special committee of our board of directors, currently comprised of Mr. Ross, Mr. Randall and Mr. Hunter (the “Trio Special Committee”) was formed to evaluate and negotiate the terms of such acquisitions. In addition, in accordance with our Related Person Transaction Policy, we will have such transactions reviewed and approved by our Board’s Audit Committee. TPET has engaged KLS Petroleum Consulting LLC (“KLSP”) to conduct comprehensive analyses and to provide valuations of such assets, which analyses have been delivered to the Company and evaluated by the Trio Special Committee.
Since LEC is partly owned and controlled by current and former members of our management, transactions including acquisitions between TPET and LEC relating to the Asphalt Ridge Asset and/or to other assets constitute related party transactions, we have formed a special committee of our board of directors, comprised of Mr. Pernice, Mr. Randall and Mr. Hunter (the “Lafayette Special Committee”) to evaluate and negotiate the terms of any such future transactions. In addition, in accordance with our Related Person Transaction Policy, we will have any such future transactions reviewed and approved by our Board’s Audit Committee. TPET will engage KLS Petroleum Consulting LLC (“KLSP”) or other third-party experts, as deemed necessary by TPET’s management and/or by the Lafayette Special Committee, to conduct comprehensive analyses and to provide valuations of such assets, which analyses will be delivered to the Company and evaluated by the Trio Special Committee.
We may enter into future transactions with LEC and/or Trio LLC. These transactions can give rise to potential conflicts of interest. We believe that the terms and conditions of our transactions have been, and will continue to be at arm’s length and on commercial terms that are normal, considering the characteristics of the goods or services involved. However, there can be no assurance that if such transactions had been concluded between or with third parties, such parties would have negotiated or entered into agreements or carried out such transactions under the same or substantially similar terms and conditions. Notwithstanding the fact that we have created the Trio Special Committee and the Lafayette Special Committee to address these potential conflicts of interest, such potential conflicts of interests could result in the value of our securities being worth less than similarly situated companies without conflicts of interest, or becoming devalued in the future. Additionally, such conflicts of interest could also lead to future stockholder litigation against such conflicted officers and directors and/or the Company, which could force us to expend significant resources defending and could result in material damages being required to be paid by the Company.
We are operating in a highly capital-intensive industry, and any sales of produced oil and gas may be insufficient to fund, sustain, or expand revenue-generating operations.
The oil/gas drilling exploration and production business are capital intensive due to the cost of experienced personnel; equipment and other assets required to drill, produce and store oil; regulatory compliance costs; potential liability exposures and financial impact; and risk of unpredictable volatility in oil market prices and predatory pricing by competitors. Drilling requires an upfront payment of operational costs with no guarantee that actual oil/gas production will cover such expenses. “Dry” holes and/or non-economic results at planned oil/gas wells could deplete available funding raised by the Company and render the Company insolvent. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, market oil prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological, and competitive developments.
Future cash flow from our operations and access to capital are subject to a number of variables, including: (i) the market prices at which our produced oil and gas are sold; (ii) our oil and/or gas reserves; (iii) our ability to acquire, locate and produce new oil/gas reserves; and (iv) the levels of our operating expenses.
We face substantial uncertainties in estimating the characteristics of our assets, so you should not place undue reliance on any of our measures.
In this Annual Report, we provide numerical and other measures of the characteristics, including with regard to size and quality, of our assets. These measures may be incorrect, as the accuracy of these measures are functions of available data, geological, geophysical, petrophysical and engineering interpretation and judgment. Any analogies drawn by us from other wells, discoveries or producing fields may not prove to be accurate indicators of the success of developing reserves from our assets. Furthermore, we may have inaccurately evaluated the accuracy of the data from analog wells or prospects produced by other parties, which we may have used.
There are uncertainties in reserve forecasts and in associated estimates of future cash flows in the South Salinas Project due to uncertainties in various matters including, for example, in the following:
● the areal extent of the oil and/or gas fields and/or prospects;
● the gross and net thicknesses of the geologic zones that comprise the oil and/or gas reservoirs (note: “oil and gas reservoirs” are geologic zones that contain oil and/or gas);
● the porosity, permeability and fluid saturations (i.e., oil, gas and/or water saturation) of the oil and/or gas reservoirs;
● the oil, gas and/or water production rates that will be achieved initially and during extended reservoir performance;
● the volumes of oil and/or gas that can be economically extracted from the oil and/or gas reservoirs;
● the extent of natural fractures that will be encountered in the naturally-fractured Monterey Formation oil and gas reservoirs (e.g., the Monterey Yellow Zone and Monterey Blue Zone that are discussed hereunder and in the Reserve Report and Reserve Supplement Report);
● pore volume compressibility and its impact on reservoir pressure and thus on reservoir performance; and
● the oil- and gas-prices during the life of the Project.
It is possible that few or none of our wells to be drilled in the future will find accumulations of oil/gas in commercial quality or quantity. Any significant variance between actual results and our assumptions could materially affect the quantities of oil attributable to any particular prospect.
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.
Exploring for and developing oil involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services or unanticipated geologic and/or mechanical conditions. Before a well is spud, we may incur significant geological and geophysical (seismic) costs, which are incurred whether a well eventually produces commercial quantities of oil/gas, or is drilled at all. Drilling may be unsuccessful for many reasons, including geologic conditions, weather, cost overruns, equipment shortages and mechanical difficulties. Exploratory wells bear a much greater risk of loss than development wells. Furthermore, the successful drilling of a well does not necessarily result in the commercially viable development of a field. A variety of factors, including regulatory, geologic and/or market-related, can cause a field to become uneconomic or only marginally economic. All of our prospects will require significant additional exploration and development, regulatory approval and commitments of resources prior to commercial development. The successful drilling of a single well may not be indicative of the potential for the development of a commercially viable field. Furthermore, if our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and may be forced to modify our development plans.
We have been an exploration stage entity and our future performance is uncertain.
We have been an exploration stage entity and will continue to be so until we generate revenue. Exploration stage entities face substantial business risks and may suffer significant losses. We have generated substantial net losses and negative cash flows from operating activities since our inception and expect to continue to incur substantial net losses as we continue our exploration and appraisal program. We face challenges and uncertainties in financial planning as a result of the unavailability of historical data and uncertainties regarding the nature, scope and results of our future activities. We will need to develop additional business relationships, establish additional operating procedures, hire additional staff, and take other measures necessary to conduct our intended business activities. We may not be successful in implementing our business strategies or in completing the development of the facilities necessary to conduct our business as planned. In the event that one or more of our drilling programs is not completed, is delayed or terminated, our operating results will be adversely affected and our operations will differ materially from the activities described in this Annual Report. There are uncertainties surrounding our future business operations that must be navigated if we transition from an exploration stage entity and commence generating revenues, some of which may cause a material adverse effect on our results of operations and financial condition.
We are dependent on certain members of our management and technical team.
Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, discovering, evaluating and developing reserves. Our performance and success are dependent, in part, upon key members of our management and technical team, and their loss or departure could be detrimental to our future success. We depend to a significant degree upon our recently appointed Chief Executive Officer, Robin Ross, and our Chief Financial Officer, Gregory L. Overholtzer. Our performance and success are dependent to a large extent on the efforts and continued employment of Mr. Ross and Mr. Overholtzer. We do not believe that Mr. Ross and Mr. Overholtzer could be quickly replaced with personnel of equal experience and capabilities, and their successor(s) may not be as effective. If Mr. Ross and Mr. Overholtzer, or any of our other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected.
In making a decision to invest in our common stock, you must be willing to rely to a significant extent on our management’s discretion and judgment. A significant amount of the interests in our Company held by members of our management were previously vested. While the Company currently has an equity incentive plan in place, there can be no assurance that our management and technical team will remain in place. The loss of any of our management and technical team members, and specifically, Mr. Ross, our recently appointed Chief Executive Officer, could have a material adverse effect on our results of operations and financial condition, as well as on the market price of our common stock. See “Item 10. Directors, Executive Officers and Corporate Management.”
Seismic studies do not guarantee that oil or gas is present or, if present, will produce in economic quantities.
Oil exploration and production companies, like the Company, rely on seismic studies to assist in assessing prospective drilling opportunities on oil and gas properties, as well as on properties that a company may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that oil or gas is present or, if present, will produce in economic or profitable quantities.
The potential lack of availability of, or cost of, drilling rigs, equipment, supplies, personnel, and crude oil field services could adversely affect our ability to execute on a timely basis exploration and development plans within any budget.
We may encounter an increase in the cost of securing needed drilling rigs, equipment, and supplies, which is increasingly a risk in California where the oil and gas industry is contracting, due to regulatory challenges/obstacles, and some service companies are reducing their presence in California or leaving the state entirely. Larger producers may be more likely to secure access to such equipment by offering more lucrative terms. If we are unable to acquire access to such resources or can obtain access only at higher prices, its ability to convert oil reserves into cash flow could be delayed, and the cost of producing from those oil reserves could increase significantly, which would adversely affect results of operations and financial condition. Our current drilling operations are limited, and availability of essential drilling assets may not become a risk factor until such time as we increase drilling operations.
Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms in the future, which may in turn limit our ability to develop our exploration, appraisal, development and production activities.
We expect our capital outlays and operating expenditures to be substantial over the next several years as we expand our operations. Obtaining and/or reprocessing and/or reinterpreting seismic data, as well as exploration, appraisal, development and production activities entail considerable costs, and we expect that we will need to raise substantial additional capital, through future private or public equity offerings, strategic alliances or debt financing.
Our future capital requirements will depend on many factors, including:
● the scope, rate of progress and cost of our exploration, appraisal, development and production activities;
● oil prices;
● our ability to produce oil or natural gas;
● the terms and timing of any drilling and other production-related arrangements that we may enter into;
● the cost and timing of governmental regulatory approvals of permits, and;
● the effects of competition from other companies and/or third-parties operating in the oil and gas industry
Additional capital may not be available on favorable terms, or at all. In addition, if we are successful raising additional capital through the sale of our securities, at such time our existing stockholders would, in all likelihood, be further diluted and new investors may demand rights, preferences or privileges senior to those of existing stockholders. If we raise additional capital through debt financing, the financing may involve covenants that restrict our business activities. If we choose to farm-out our interests, we may lose operating control or influence over such assets.
Assuming we are able to timely commence exploration, appraisal, development and/or production activities, and/or to maintain oil/gas production, and/or to maintain force majeure status, then our rights to our mineral leasehold should extend for certain periods of time and/or for life of production. If we are unable to meet our commitments we may be subject to significant potential forfeiture of all or part of the mineral leasehold. If we are not successful in raising additional capital, we may be unable to continue our future exploration and production activities or successfully exploit our assets, and we may lose the rights to develop said assets.
A substantial or extended decline in global and/or local oil and/or natural gas prices may adversely affect our business, financial condition and results of operations.
The prices that we will receive for our oil and natural gas will significantly affect our revenue, profitability, access to capital and future growth rate. Historically, the oil and natural gas markets have been volatile and will likely continue to be volatile in the future. The prices that we will receive for our future production and the levels of our future production depend on numerous factors. These factors include, but are not limited to, the following:
● changes in supply and demand for oil and natural gas;
● the actions of the Organization of the Petroleum Exporting Countries (“OPEC”);
● speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts;
● global economic conditions;
● political and economic conditions, including embargoes in oil-producing countries or affecting other oil-producing activities, particularly in the Middle East, Africa, Russia and South America;
● the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;
● the level of global oil and natural gas exploration and production activity;
● the level of global oil inventories and oil refining capacities;
● weather conditions and natural disasters;
● technological advances affecting energy consumption;
● governmental regulations and taxation policies;
● proximity and capacity of transportation facilities;
● the price and availability of competitors’ supplies of oil and natural gas; and
● the price and availability of alternative fuels.
Lower oil prices may not only decrease our revenues on a per share basis but also may reduce the amount of oil that we can produce economically. A substantial or extended decline in oil and natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
Unless we replace our petroleum reserves, our reserves and production will decline over time. Our business is dependent on the successful development of our various current petroleum assets and projects and/or on continued successful identification and exploitation of other petroleum assets and prospects, whereas the identified locations in which we drill in the future may not yield oil or natural gas in commercial quantities.
Production from oil properties may decline as reserves are depleted, with the rate of decline depending on reservoir characteristics and other factors. Similarly, our current reserves will decline as the reserves are produced. Our future oil reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing our current reserves and/or economically finding or acquiring additional recoverable reserves. While our team members have had success in identifying and developing commercially exploitable deposits and drilling locations in the past, we may be unable to replicate that success in the future. We may not identify any more commercially exploitable deposits or successfully drill, complete or produce more oil reserves, and the wells which we have drilled and currently plan to drill at our assets may not discover or produce any further oil or gas or may not discover or produce additional commercially viable quantities of oil or gas to enable us to continue to operate profitably. If we are unable to replace our future production, the value of our reserves will decrease, and our business, financial condition and results of operations will be materially adversely affected.
Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets or delay our future oil and natural gas production.
Our ability to market our future oil/gas production will depend substantially on the availability and capacity of processing facilities, tanker trucks, pipelines and other infrastructure. Our failure to obtain such facilities on acceptable terms could materially harm our business. We will rely on access to drilling rigs suitable for our projects. The availability of drilling rigs may be problematic or delayed, and we may not be able to gain timely access to suitable rigs. We may be required to shut-in oil/gas wells because of the absence of markets or because facilities are inadequate or nonexistent. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver the production to market, which could cause a material adverse effect on our financial condition and results of operations.
Additionally, the exploitation and sale of associated and non-associated natural gas and liquids will be subject to timely commercial processing and marketing of these products, which may depend on the contracting, financing, building and operating of infrastructure by third parties.
We are subject to numerous risks inherent to the exploration and production of oil and natural gas.
Oil and natural gas exploration and future production activities involve many risks that a combination of experience, knowledge and interpretation may not be able to overcome. Our future will depend on the success of our exploration and future production activities and on the development of infrastructure that will allow us to take advantage of our discoveries. As a result, our oil and natural gas exploration and future production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable oil and natural gas production. Our decisions to purchase, explore or develop discoveries, prospects or licenses will depend in part on the evaluation of seismic data through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.
Furthermore, the marketability of expected oil and natural gas production from any future discoveries and prospects will also be affected by numerous factors. These factors include, but are not limited to, market fluctuations of prices, proximity, capacity and availability of processing facilities, transportation vehicles and pipelines, equipment availability and government regulations (including, without limitation, regulations relating to prices, taxes, royalties, allowable production, domestic supply requirements, importing and exporting of oil and natural gas, environmental protection and climate change). The effect of these factors, individually or jointly, may result in us not receiving an adequate return on invested capital.
In the event that our currently undeveloped discoveries and prospects are developed and become operational, they may not produce oil and natural gas in commercial quantities or at the costs anticipated, and our projects may cease production, in part or entirely, in certain circumstances. Discoveries may become uneconomical as a result of an increase in operating costs to produce oil and natural gas. Our actual operating costs may differ materially from our current estimates. Moreover, it is possible that other developments, such as increasingly strict environmental, climate change, health and safety laws and regulations and enforcement policies thereunder and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities, delays, an inability to complete the development of our discoveries or the abandonment of such discoveries, which could cause a material adverse effect on our financial condition and results of operations.
We are subject to drilling and other operational environmental hazards.
The oil and natural gas business involves a variety of operating risks, including, but not limited to:
● fires, blowouts, spills, cratering and explosions;
● mechanical and equipment problems, including unforeseen engineering complications;
● uncontrolled flows or leaks of oil, well fluids, natural gas, brine, toxic gas or other pollution;
● gas flaring operations;
● formations with abnormal pressures;
● pollution, other environmental risks, and geological problems; and
● weather conditions and natural disasters.
The development schedule of oil and natural gas projects, including the availability and cost of drilling rigs, equipment, supplies, personnel and oilfield services, is subject to delays and cost overruns.
Historically, some oil and natural gas development projects have experienced delays and capital cost increases and overruns due to, among other factors, the unavailability or high cost of drilling rigs and other essential equipment, supplies, personnel and oilfield services. To the extent we locate commercially viable reserves through our exploration and development activities, the cost to develop our projects will not have been fixed and will remain dependent upon a number of factors, including the completion of detailed cost estimates and final engineering, contracting and procurement costs. Our construction and operation schedules may not proceed as planned and may experience delays or cost overruns. Any delays may increase the costs of the project, requiring additional capital, and such capital may not be available in a timely and cost-effective fashion.
Participants in the oil and gas industry are subject to numerous laws that can affect the cost, manner or feasibility of doing business.
Exploration and production activities in the oil and gas industry are subject to local laws and regulations. We may be required to make large expenditures to comply with governmental laws and regulations, particularly in respect of the following matters:
● permits for drilling, long-term production, water disposal, conditional use and other matters;
● licenses for drilling operations;
● tax increases, including retroactive claims;
● unitization of oil accumulations;
● local content requirements (including the mandatory use of local partners and vendors); and
● environmental requirements and obligations, including remediation or investigation activities.
Under these and other laws and regulations, we could be liable for personal injuries, property damage and other types of damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change, or their interpretations could change, in ways that could substantially increase our costs. These risks may be higher in developing countries in which we may at some point in the future decide to conduct our operations, where there could be a lack of clarity or lack of consistency in the application of these laws and regulations. Any resulting liabilities, penalties, suspensions or terminations could have a material adverse effect on our financial condition and results of operations.
We and our operations are subject to numerous environmental, health and safety regulations which may result in material liabilities and costs.
We and our operations are subject to various international, foreign, federal, state and local environmental, health and safety laws and regulations governing, among other things, the emission and discharge of pollutants into the ground, air or water, the generation, storage, handling, use and transportation of regulated materials and the health and safety of our employees. We are required to obtain environmental permits from governmental authorities for our operations, including drilling permits for our wells. We have not been or may not be at all times in complete compliance with these permits and the environmental laws and regulations to which we are subject, and there is a risk that these laws and regulations could change in the future or become more stringent. If we violate or fail to comply with these laws, regulations or permits, we could be fined or otherwise sanctioned by regulators, including through the revocation of our permits or the suspension or termination of our operations. If we fail to obtain permits in a timely manner or at all (due to opposition from community or environmental interest groups, governmental delays or any other reasons), or if we face additional requirements imposed as a result of changes in or enactment of laws or regulations, such failure to obtain permits or such changes in or enactment of laws could impede or affect our operations, which could have a material adverse effect on our results of operations and financial condition.
We, as an interest owner or as the designated operator of certain of our current and future discoveries and prospects, could be held liable for some or all environmental, health and safety costs and liabilities arising out of our actions and omissions as well as those of our block partners, third-party contractors or other operators. To the extent we do not address these costs and liabilities or if we do not otherwise satisfy our obligations, our operations could be suspended or terminated. We have contracted with and intend to continue to hire third parties to perform services related to our operations. There is a risk that we may contract with third parties with unsatisfactory environmental, health and safety records or that our contractors may be unwilling or unable to cover any losses associated with their acts and omissions. Accordingly, we could be held liable for all costs and liabilities arising out of the acts or omissions of our contractors, which could have a material adverse effect on our results of operations and financial condition.
We maintain insurance at levels that we believe are consistent with industry practices, but we are not fully insured against all risks. Our insurance may not cover any or all environmental claims that might arise from our future operations or at any of our asset areas. If a significant accident or other event occurs and is not covered by insurance, such accident or event could have a material adverse effect on our results of operations and financial condition.
Our operations may be dependent on sources of electricity and/or natural gas that may be unreliable or costly.
Oil and gas operations, including our operations, commonly require significant electricity and/or natural gas as power sources to operate facilities. Some oil and gas operations are power self-sourced, for example producing natural gas to run facilities including to generate electricity. Some oil operations historically were permitted to burn crude oil to power operations but this is commonly not permitted today due to associated greenhouse gas emissions. Our South Salinas Project may produce sufficient natural gas to be power self-sourced and even to deliver gas to market. The McCool Ranch Oil Field produces black oil without associated natural gas, and historically has received natural gas through an existing pipeline that has had excess capacity. The excess capacity available might not be adequate to meet our demand. If establishing and/or maintaining reliable sources of affordable electricity and/or natural gas are problematic or delayed, this could have a material adverse effect on our results of operations and financial condition.
We expect continued and increasing attention to climate change and energy transition issues and associated regulations to constrain and impede the oil/gas industry.
We expect continued and increasing attention to climate change and to the energy transition away from fossil fuels. Various countries and regions have agreed to regulate emissions of greenhouse gases, including methane (a primary component of natural gas) and carbon dioxide (a byproduct of oil and natural gas combustion). The regulation of greenhouse gases and the physical impacts of climate change in the areas in which we, our customers and the end-users of our products operate could adversely impact our operations and the demand for our products.
Environmental, health and safety laws are complex, change frequently and have tended to become increasingly stringent over time. Our costs of complying with current and future climate change, environmental, health and safety laws, the actions or omissions of our block partners and third party contractors and our liabilities arising from releases of, or exposure to, regulated substances may adversely affect our results of operations and financial condition.
We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas operations, for which we may not have adequate insurance coverage.
We intend to maintain insurance against risks in the operation of the business we plan to develop and in amounts in which we believe to be reasonable. Such insurance, however, may contain exclusions and limitations on coverage. For example, we are not insured against political or terrorism risks. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition and results of operations.
We may be subject to risks in connection with acquisitions and the integration of significant acquisitions may be difficult.
We periodically evaluate acquisitions of prospects, properties, mineral leases, licenses, reserves and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of these assets requires an assessment of several factors, including:
● oil and/or gas reserves;
● future oil and natural gas prices and their differentials;
●
development and operating costs; and
● potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject assets that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the assets to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We may not be entitled to contractual indemnification for environmental liabilities and could acquire assets on an “as is” basis. Significant acquisitions and other strategic transactions may involve other risks, including:
● diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;
● the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;
● difficulty associated with coordinating geographically separate organizations; and
● the challenge of attracting and retaining personnel associated with acquired operations.
The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.
If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be adversely affected.
The success of a significant acquisition will depend, in part, on our ability to realize anticipated growth opportunities from combining the acquired assets or operations with those of ours. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, or in oil and gas industry conditions, or by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties, including the assumption of environmental or other liabilities in connection with the acquisition. If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.
The requirements of being a public company may strain our resources, result in more litigation and divert management’s attention.
As a public company, we are subject to the reporting requirements of the Exchange Act, the Sarbanes-Oxley Act, the Dodd-Frank Wall Street Reform and Consumer Protection Act, the listing requirements of the NYSE American and other applicable securities rules and regulations. Complying with these rules and regulations has increased our legal and financial compliance costs, made some activities more difficult, time consuming or costly, and increased demand on our systems and resources, including management. The Exchange Act requires, among other things, that we file annual, quarterly and current reports with respect to our business and operating results. The Sarbanes-Oxley Act requires, among other things, that we maintain effective disclosure controls and procedures and internal control over financial reporting. We are required to disclose changes made in our internal control and procedures on a quarterly basis. In order to maintain and, if required, improve our disclosure controls and procedures and internal control over financial reporting to meet this standard, significant resources and management oversight may be required. As a result, management’s attention may be diverted from other business concerns, which could adversely affect our business and operating results. We may also need to hire additional employees or engage outside consultants to comply with these requirements, which will increase our costs and expenses.
In addition, changing laws, regulations and standards relating to corporate governance and public disclosure are creating uncertainty for public companies, increasing legal and financial compliance costs and making some activities more time consuming. These laws, regulations and standards are subject to varying interpretations, in many cases due to their lack of specificity and, as a result, their application in practice may evolve over time as new guidance is provided by regulatory and governing bodies. This could result in continuing uncertainty regarding compliance matters and higher costs necessitated by ongoing revisions to disclosure and governance practices. We intend to invest resources to comply with evolving laws, regulations and standards, and this investment may result in increased general and administrative expenses and a diversion of management’s time and attention from revenue-generating activities to compliance activities. If our efforts to comply with new laws, regulations and standards differ from the activities intended by regulatory or governing bodies due to ambiguities related to their application and practice, regulatory authorities may initiate legal proceedings against us and our business may be adversely affected.
These new rules and regulations may make it more expensive for us to obtain director and officer liability insurance and, in the future, we may be required to accept reduced coverage or incur substantially higher costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee and compensation committee, and qualified executive officers.
By disclosing information in this Annual Report and in other filings required of a public company, our business and financial condition will become more visible, which we believe may result in threatened or actual litigation, including by competitors and other third parties. If those claims are successful, our business could be seriously harmed. Even if the claims do not result in litigation or are resolved in our favor, the time and resources needed to resolve them could divert our management’s resources and seriously harm our business.
We are subject to the examination of our tax returns and other tax matters by the U.S. Internal Revenue Service, states in which we conduct business, and other tax authorities. If our effective tax rates were to increase, or if the ultimate determination of our taxes owed is for an amount in excess of amounts previously accrued, our financial condition, operating results and cash flows could be materially adversely affected.
U.S. federal, state and local tax laws are being re-examined and evaluated. New laws and interpretations of the law are taken into account for financial statement purposes in the quarter or year that they become applicable. Tax authorities are increasingly scrutinizing the tax positions of companies. If U.S. federal, state or local tax authorities change applicable tax laws, our overall taxes could increase, and our business, financial condition or results of operations may be adversely impacted.
In addition, any significant changes enacted by the current U.S. presidential administration to the Code or specifically to the Tax Cuts and Jobs Act (the “U.S. Tax Act”) enacted in 2017, or to regulatory guidance associated with the U.S. Tax Act, could materially adversely affect our effective tax rate.
Our amended and restated certificate of incorporation provides that the Court of Chancery of the State of Delaware will be the sole and exclusive forum for substantially all disputes between us and our stockholders, which could limit its stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees.
Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will be the sole and exclusive forum for (1) any derivative action or proceeding brought on our behalf, (2) any action asserting a claim of breach of a fiduciary duty or other wrongdoing by any of our directors, officers, employees or agents to us or our stockholders, (3) any action asserting a claim against us arising pursuant to any provision of the Delaware General Corporate Law (“DGCL”) or our amended and restated certificate of incorporation or amended and restated bylaws, (4) any action to interpret, apply, enforce or determine the validity of our amended and restated certificate of incorporation or amended and restated bylaws, or (5) any action asserting a claim governed by the internal affairs doctrine. Under our amended and restated certificate of incorporation, this exclusive form provision will not apply to claims which are vested in the exclusive jurisdiction of a court or forum other than the Court of Chancery of the State of Delaware, or for which the Court of Chancery of the State of Delaware does not have subject matter jurisdiction. For instance, the exclusive forum provision in our amended and restated certificate of incorporation does not apply to actions arising under federal securities laws, including suits brought to enforce any liability or duty created by the Securities Act of 1933 (the “Securities Act”), the Exchange Act of 1934 (the “Exchange Act”), or the rules and regulations thereunder. This provision would not apply to suits brought to enforce a duty or liability created by the Exchange Act. Our amended and restated certificate of incorporation provides that any person or entity holding, purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of and to have consented to this choice of forum provision. It is possible that a court of law could rule that the choice of forum provision contained in our amended and restated certificate of incorporation is inapplicable or unenforceable if it is challenged in a proceeding or otherwise. Therefore, the exclusive forum provision in our amended and restated certificate of incorporation will not relieve us of our duty to comply with the federal securities laws and the rules and regulations thereunder, and stockholders will not be deemed to have waived our compliance with these laws, rules and regulations.
In addition, our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the federal district courts of the United States of America shall, to the fullest extent permitted by law, be the sole and exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act, or the rules and regulations promulgated thereunder. We note, however, that there is uncertainty as to whether a court would enforce this provision and that investors cannot waive compliance with the federal securities laws and the rules and regulations thereunder. Section 22 of the Securities Act creates concurrent jurisdiction for state and federal courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder.
This exclusive forum provision may limit a stockholder’s ability to bring a claim in a judicial forum of its choosing for disputes with us or our directors, officers or other employees, which may discourage lawsuits against us or our directors, officers or other employees. In addition, stockholders who do bring a claim in the state or federal court in the State of Delaware could face additional litigation costs in pursuing any such claim, particularly if they do not reside in or near Delaware. The state or federal court of the State of Delaware may also reach different judgments or results than would other courts, including courts where a stockholder would otherwise choose to bring the action, and such judgments or results may be more favorable to us than to our stockholders. However, the enforceability of similar exclusive forum provisions in other companies’ certificates of incorporation have been challenged in legal proceedings, and it is possible that a court could find this type of provision to be inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings. If a court were to find the exclusive forum provision contained in our amended and restated certificate of incorporation to be inapplicable or unenforceable in an action, we might incur additional costs associated with resolving such action in other jurisdictions.
Our business and results of operations may be materially adversely effected by inflationary pressures.
As of the date of this Annual Report, inflationary pressures have led to increased construction materials and labor costs, specifically associated with steel, cement, and other materials. We believe we will continue to experience such pressures in future quarters, as well as potential delays in our contractors’ ability to requisition such materials. These pressures have led to an overall increase in budgeted construction costs. No assurance can be given that the costs of our projects will not exceed budgets. Any such cost overruns or delays could have a material adverse effect on our business.
Risks Relating to Our Securities
There can be no assurance that an active and liquid trading market for our common stock will continue or that we will be able to continue to comply with the NYSE American’s continued listing standards.
Our common stock began trading on the NYSE American exchange in April 2023, as a result of our consummation of an initial public offering of our shares of common stock. Our common stock is currently listed on the NYSE American under the symbol “TPET.” There can be no assurance an active and liquid trading market in our common stock will continue.
There is no guarantee that we will be able to maintain such listing for any period of time by perpetually satisfying the NYSE American’s continued listing requirements. Our failure to continue to meet these requirements may result in our common stock being delisted from the NYSE American.
If we are not able to comply with the applicable continued listing requirements or standards of the NYSE American, our common stock could be delisted from the NYSE American.
Our common stock is listed on the NYSE American. In order to maintain this listing, we must maintain a certain share price, financial and share distribution targets, including maintaining a minimum amount of stockholders’ equity and a minimum number of public stockholders. In addition to these objective standards, the NYSE American may delist the securities of any issuer (i) if, in its opinion, the issuer’s financial condition and/or operating results appear unsatisfactory; (ii) if it appears that the extent of public distribution or the aggregate market value of the security has become so reduced as to make continued listing on the NYSE American inadvisable; (iii) if the issuer sells or disposes of principal operating assets or ceases to be an operating company; (iv) if an issuer fails to comply with the NYSE American’s listing requirements; (v) if an issuer’s securities sell at what the NYSE American considers a “low selling price” which the exchange generally considers $0.10 per share, the NYSE American may suspend trading of our common stock, until the issuer corrects this via a reverse split of shares after notification by the NYSE American; or (vi) if any other event occurs or any condition exists which makes continued listing on the NYSE American, in its opinion, inadvisable. There are no assurances how the market price of our common stock will be impacted in future periods as a result of the general uncertainties in the capital markets and any specific impact on our Company as a result of the recent volatility in the capital markets.
On February 26, 2024, we received written notice (the “Notice”) from the NYSE American LLC (“NYSE American”) indicating that we were not in compliance with the continued listing standard set forth in Section 1003(f)(v) of the NYSE American Company Guide (“Section 1003(f)(v)”) because the shares of our common stock had been selling for a substantial period of time at a low price per share. The Notice had no immediate effect on the listing or trading of our shares of common stock and our common stock continued to trade on the NYSE American under the symbol “TPET” with the designation of “.BC” to indicate that the Company was not in compliance with the NYSE American’s continued listing standards. Additionally, the Notice did not result in the immediate delisting of our common stock from the NYSE American.
On May 1, 2024, we received notice from the NYSE American (the “Stock Price Compliance Notice”) informing us that we had resolved the continued listing deficiency with respect to the low price of our common stock and regained compliance with the continued listing requirements, because the 30-day average price of our common Stock was $0.25 ($5.00 on a post-reverse split basis) as of April 30, 2024. The Stock Price Compliance Notice also provided that the NYSE American could still commence delisting proceedings and immediately suspend trading of our common stock if it trades at levels viewed to be abnormally low, which is generally viewed as a price at or below $0.10.
On November 5, 2024, the Company received notice from NYSE American that the NYSE American had suspended trading of our shares of common stock, until the effectiveness of the Reverse Stock Split, because our common stock was consistently selling at a low selling price per share in violation of Section 1003(f)(v) of the NYSE American Company Guide. Upon effecting the Reverse Stock Split, our common stock began trading again on the NYSE American on November 15, 2024. If, in the future, the price of our common stock falls out of compliance, again, with the continued listing requirements of the NYSE American, this could result in a de-listing of our common stock from trading on the NYSE American.
In the event that our common stock is delisted from the NYSE American and is not eligible for quotation on another market or exchange, trading of our common stock could be conducted in the over-the-counter market or on an electronic bulletin board established for unlisted securities, such as the Pink Sheets or the OTC Markets. In such event, investors may face material adverse consequences, including, but not limited to, a lack of trading market for the common stock, reduced liquidity and market price of the common stock, decreased analyst coverage of our common stock, and an inability for us to obtain any additional financing to fund our operations that we may need.
If our common stock is delisted, our common stock may be subject to the so-called “penny stock” rules. The SEC has adopted regulations that define a penny stock to be any equity security that has a market price per share of less than $5.00, subject to certain exceptions, such as any securities listed on a national securities exchange. For any transaction involving a penny stock, unless exempt, the rules impose additional sales practice requirements and burdens on broker-dealers (subject to certain exceptions) and could discourage broker-dealers from effecting transactions in our stock, further limiting the liquidity of our shares, and an investor may find it more difficult to acquire or dispose of the common stock on the secondary market.
These factors could have a material adverse effect on the trading price, liquidity, value and marketability of the common stock.
Our share price may be volatile, and purchasers of our common stock could incur substantial losses.
Our share price has been extremely volatile in the past and may continue to be so in the future. Since our IPO, our common stock has traded at prices ranging from $60.00 and $1.12 (on a post-reverse stock split basis). The stock market in general has experienced extreme volatility that has often been unrelated to the operating performance of particular companies. As a result of this volatility, investors may not be able to sell their common stock at or above the price paid for such shares. The market price for our common stock may be influenced by many factors, including, but not limited to:
● the price of oil and natural gas;
● the success of our exploration and development operations, and the marketing of any oil and natural gas we produce;
● regulatory developments in the United States and/or in any foreign countries where we may have operations in the future;
● the recruitment or departure of key personnel;
●
quarterly or annual variations in our financial results or those of companies that are perceived to be similar to us;
● market conditions in the industries in which we compete and issuance of new or changed securities;
● analysts’ reports or recommendations;
● the failure of securities analysts to cover our common stock or changes in financial estimates by analysts;
● the inability to meet the financial estimates of analysts who follow our common stock;
● the issuance of any additional securities of ours;
● investor perception of our company and of the industry in which we compete; and
● general economic, political and market conditions.
Broad market and industry factors may significantly affect the market price of our securities, regardless of our actual operating performance. These fluctuations may be even more pronounced in the trading market for our common stock shortly following this offering. If the market price of shares of our common stock after this offering does not ever exceed the offering price, you may not realize any return on your investment in us and may lose some or all of your investment.
In addition, in the past, following periods of volatility in the overall market and in the market price of a particular company’s securities, securities class action litigation has often been instituted against these companies. This litigation, if instituted against us, could result in substantial costs and a diversion of our management’s attention and resources.
Certain of our executive officers and directors have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.
Certain of our executive officers and directors, who are responsible for managing the direction of our operations, hold positions of responsibility with other entities (including affiliated entities) that are in the oil and natural gas industry. Two of these executive officers, Terence B. Eschner and Steven Rowlee, each of whom has a controlling interest in Trio LLC, no longer serve as executive officers of the Company, as of January 2, 2025. Stanford Eschner, who also owns a controlling interest in Trio LLC, continues to server as Vice Chairman and a director of the Company. Greg Overholtzer, who is an executive officer of LEC. These executive officers and directors may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are, or may become, affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our stockholders should be aware, see Item 13. “Certain Relationships and Related Transactions, and Director Independence.”
For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.
We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosures regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.235 billion of revenues in a fiscal year, have more than $700 million in market value of our common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.
To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common stock to be less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.
We do not intend to pay dividends on our common stock.
We do not plan to declare dividends on shares of our common stock in the foreseeable future. Consequently, the only opportunity to achieve a return on an investment in us will be if the market price of our common stock appreciates, which may not occur, and our shares are sold at a profit. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price that an investor pays for our common stock.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES.
Other than our interest in the South Salinas Project, we do not own any real property.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS.
From time to time, we are involved in various disputes, claims, suits, investigations, and legal proceedings arising in the ordinary course of business. There are currently no pending legal proceedings or claims that we believe will have a material adverse effect on our business, financial condition or operating results. None of our directors, officers or affiliates is involved in a proceeding adverse to our business or has a material interest adverse to our business.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
None.

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASERS OF EQUITY SECURITIES
Market information
Our common stock trades on the NYSE American LLC Market under the symbol “TPET” since April 17, 2023. Prior to that date, there was no public market for our common stock.
Holders of Record
As of January 15, 2025, we had 30 holders of record of our common stock. The actual number of holders of our common stock is greater than this number of record holders and includes stockholders who are beneficial owners, but whose shares are held in street name by brokers or held by other nominees. This number of holders of record also does not include stockholders whose shares may be held in trust by other entities.
Dividends
We have never paid any cash dividends on our common stock. We currently intend to retain all available funds and any future earnings for use in the operation of our business and do not anticipate paying any cash dividends on our common stock in the foreseeable future. Any future determination to declare dividends will be made at the discretion of our board of directors and will depend on our financial condition, operating results, capital requirements, general business conditions and other factors that our board of directors may deem relevant.
Securities Authorized for Issuance Under Equity Incentive Plans
We have adopted and approved the 2022 Equity Incentive Plan (the “2022 Plan”). Under the 2022 Plan, we may grant cash and equity incentive awards to eligible service providers in order to attract, motivate and retain the talent for which we compete. Pursuant to the 2022 Plan, we have reserved 500,000 shares of the shares of common stock for issuance thereunder. The following table sets forth certain information about the securities authorized for issuance under our incentive plans as of October 31, 2024.
Plan Category Number of
securities to
be issued upon
exercise of
outstanding
options, warrants and rights Weighted-
average
exercise price
of
outstanding
options, warrants and rights Number of
granted
restricted
stock
awards
outstanding Number of
securities
remaining
available for
future
issuance
under equity
compensation
plans
Equity compensation plans approved by security holders (1) 197,994 $ 15.09 168,500 272,750
Equity compensation plans not approved by security holders - - - -
197,994 $ 15.09 168,500 272,750
(1) The Company adopted the 2022 Plan originally at the closing of its initial public offering, and the 2022 Plan was amended and restated at the 2024 annual meeting of the stockholders on August 15, 2024. As of the date of this Annual Report, all awards under the 2022 Plan granted by the Board have been disclosed on the Form 8-Ks.
Recent Sales of Unregistered Securities
During the year ended October 31, 2024, all sales of unregistered securities by the Company have been previously reported on a Form 8-K or Form 10-Q.
Use of Proceeds
On April 17, 2023, the U.S. Securities and Exchange Commission declared effective our registration statement on Form S-1 (File No. 333-267380), as amended, filed in connection with our IPO. There has been no material change in the planned use of proceeds from our IPO from that described in the related prospectus dated April 19, 2023, filed with the SEC pursuant to Rule 424(b)(4) under the Securities Act.
At-the Market Offering
During the year ended October 31, 2024, the Company implemented an at-the-market equity offering program (“ATM”), allowing for the periodic sale of shares of common stock to the public through a designated underwriter, based on prevailing market conditions. This program provided the Company with flexibility to raise capital as needed to fund growth initiatives and working capital requirements. During the year ended October 31, 2024, the Company sold 361,708 shares of common stock through the ATM, generating net proceeds of $1,173,679. As of January 15, the ATM has been fully sold, resulting in the sale of a total of 3,312,877 shares of common stock, generating net proceeds of $4,649,329.
Issuer Purchases of Equity Securities
We did not repurchase any of our equity securities during the period covered by this Annual Report.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
The following discussion and analysis of the results of operations and financial condition of Trio Petroleum Corp. as of and for the years ended October 31, 2024 and 2023 should be read in conjunction with our financial statements and the notes to those financial statements that are included elsewhere in this Annual Report. This Management’s Discussion and Analysis of Financial Condition and Results of Operations contains statements that are forward-looking. See “Item 7. Cautionary Statement Regarding Forward-Looking Information” below. Actual results could differ materially because of the factors discussed in “Item 1A. Risk Factors” elsewhere in this Annual Report, and other factors that we may not know.
Throughout this report, the terms “our,” “we,” “us,” “TPET” and the “Company” refer to Trio Petroleum Corp.
Cautionary Note Regarding Forward-looking Statements
This Annual Report contains forward-looking statements that can involve substantial risks and uncertainties. All statements other than statements of historical facts contained in this Annual Report, including statements regarding our future results of operations and financial position, business strategy, prospective products, product approvals, research and development costs, future revenue, timing and likelihood of success, plans and objectives of management for future operations, future results of anticipated products and prospects, plans and objectives of management are forward-looking statements. These statements involve known and unknown risks, uncertainties and other important factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements.
In some cases, you can identify forward-looking statements by terms such as “anticipate,” “believe,” “contemplate,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “should,” “target,” “will,” or “would” or the negative of these terms or other similar expressions, although not all forward-looking statements contain these words. Forward-looking statements contained in this Annual Report include, but are not limited to, statements about:
● our ability to find, acquire or gain access to other discoveries and prospects and to successfully develop our current discoveries and prospects;
● uncertainties inherent in making estimates of our oil and natural gas data;
● the successful implementation of our prospect discovery and development and drilling plans with the South Salinas Project;
● projected and targeted capital expenditures and other costs, commitments and revenues;
● our dependence on our key management personnel and our ability to attract and retain qualified technical personnel;
● the ability to obtain financing and the terms under which such financing may be available;
● the volatility of oil and natural gas prices;
● the availability and cost of developing appropriate infrastructure around and transportation to our discoveries and prospects;
● the availability and cost of drilling rigs, production equipment, supplies, personnel and oilfield services;
● other competitive pressures;
● potential liabilities inherent in oil and natural gas operations, including drilling risks and other operational and environmental hazards;
● current and future government regulation of the oil and gas industry;
● cost of compliance with laws and regulations;
● changes in environmental, health and safety or climate change laws, greenhouse gas regulation or the implementation of those laws and regulations;
● environmental liabilities;
● geological, technical, drilling and processing problems;
● military operations, terrorist acts, wars or embargoes;
● the cost and availability of adequate insurance coverage;
● our vulnerability to severe weather events; and
● other risk factors discussed in the “Risk Factors” section of this Annual Report.
We have based these forward-looking statements largely on our current expectations and projections about our business, the industry in which we operate and financial trends that we believe may affect our business, financial condition, results of operations and prospects, and these forward-looking statements are not guarantees of future performance or development. These forward-looking statements speak only as of the date of this Annual Report and are subject to a number of risks, uncertainties and assumptions described in the section titled “Risk Factors” and elsewhere in this Annual Report. Because forward-looking statements are inherently subject to risks and uncertainties, some of which cannot be predicted or quantified, you should not rely on these forward-looking statements as predictions of future events. The events and circumstances reflected in our forward-looking statements may not be achieved or occur and actual results could differ materially from those projected in the forward-looking statements. Except as required by applicable law, we do not plan to publicly update or revise any forward-looking statements contained herein until after we distribute this Annual Report, whether as a result of any new information, future events or otherwise.
In addition, statements that “we believe” and similar statements reflect our beliefs and opinions on the relevant subject. These statements are based upon information available to us as of the date of this Annual Report, and while we believe such information forms a reasonable basis for such statements, such information may be limited or incomplete, and our statements should not be read to indicate that we have conducted an exhaustive inquiry into, or review of, all potentially available relevant information. These statements are inherently uncertain and you are cautioned not to unduly rely upon these statements.
Overview
We are a California-based oil and gas exploration and development company headquartered in Bakersfield, California, with our principal executive offices located at 5401 Business Park South, Suite 115, Bakersfield, California 93309, with operations in Monterey County, California, and Uintah County, Utah.
We have had revenue-generating operations since the McCool Ranch Oil Field was restarted on February 22, 2024, and recognized our first revenues in our fiscal quarter ended April 30, 2024, and received the proceeds from these operations in June 2024.
We were formed to initially acquire an approximate 82.75% working interest (which was subsequently increased to an approximate 85.775% working interest) from Trio Petroleum LLC (“Trio LLC”) in the large, approximately 9,300-acre South Salinas Project that is located in Monterey County, California, and subsequently partner with certain members of Trio LLC’s management team to develop and operate those assets. We hold an approximate 68.62% interest after the application of royalties (“net revenue interest”) in the South Salinas Project. Trio LLC holds an approximate 3.8% working interest in the South Salinas Project. We and Trio LLC are separate and distinct companies.
California is a significant part of our geographic focus and we recently acquired a 22% working interest in the McCool Ranch Oil Field (the “McCool Ranch Oil Field”, “McCool Ranch Field” or “McCool Ranch”) in Monterey County, California. However, our interests extend beyond California and we recently acquired an interest in the Asphalt Ridge Project in Uintah County, Utah; we may acquire additional assets both inside and outside of California and Utah.
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 December 2024, or 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, we entered into a Purchase and Sale Agreement with Trio LLC (the “McCool Ranch Purchase Agreement”) pertaining to the McCool Ranch Oil Field. Pursuant to this agreement, effective October 1, 2023, we acquired an approximate 22% working interest in and to certain oil and gas assets at the McCool Ranch Field, which is located in Monterey, County, California, just seven miles from our flagship South Salinas Project. The assets are situated in what is known as the “Hangman Hollow Area” of the McCool Ranch Field. The acquired property is a relatively new oil field (discovered in 2011) developed with six oil wells, one water-disposal well, a steam generator, boiler, three 5,000 barrel tanks, a 250-barrel test tank, a water softener, two freshwater tanks, two soft water tanks, in-field steam pipelines, oil pipelines and other facilities. The property is fully and properly permitted for oil and gas production, cyclic-steam injection and water disposal. We are acquiring the working interest at McCool Ranch primarily through work commitment expenditures, which are being allocated to restart production at the field and establish cash flow for us, with upside potential given the numerous undrilled infill and development well locations. Oil production was restarted on February 22, 2024.
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 are currently producing about 10 to 15 bopd. The 58X well is temporarily idle. Oil production at the HH-1 and 35X wells is currently “cold” (i.e., without steam). The Company expects to restart cyclic steam operations in December 2024 or 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 expects to restart the last two wells in the restart program, the HH-3 and HH-4 wells, in December 2024 or 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 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.
Asphalt Ridge Option Agreement and the Lafayette Energy Leasehold Acquisition and Development 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, 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.
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. We expect to add the reserve value, if any, of the Asphalt Ridge Project to the Company’s reserve report after a brief period of observation and review of the oil development operations that commenced in the third calendar quarter of 2024.
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.
Carbon Capture and Storage Project as part of Company’s South Salinas Project
We are committed to attempting to reduce our own carbon footprint and, where possible, that of others. For this reason, we are taking initial steps to launch a Carbon Capture and Storage (“CCS”) project as part of the South Salinas Project, which appears ideal for such a task. 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 excellent candidates for use as CO2 injection wells. A CCS project in the future may help reduce our 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 our CCS Project. We have 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. We believe it is 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.
Going Concern Considerations
We have only begun to generate revenues in the current fiscal year and have incurred significant losses since inception. As of October 31, 2024, we have an accumulated deficit of $20,073,679 and a working capital deficit of $2,025,480, and for the year ended October 31, 2024, a net loss of $9,626,797 and cash used in operation activities of $3,840,744. 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.
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.
The accompanying 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.
We will require additional capital funding in order to drill additional planned wells at the South Salinas, McCool Ranch and Asphalt Ridge assets and to pay for additional development costs and other payment obligations and operating costs until our planned revenue streams are fully implemented and begin to offset our operating costs, if ever.
Since our inception, we have funded our operations with the proceeds from equity and debt financing. We have experienced liquidity issues due to, among other reasons, our limited ability to raise adequate capital on acceptable terms. We have historically relied upon the issuance of equity and promissory notes that are convertible into shares of our common stock to fund our operations and have devoted significant efforts to reduce that exposure. We anticipate that we will need to issue equity to fund our operations for the foreseeable future. If we are unable to achieve operational profitability or are not successful in securing other forms of financing, we will have to evaluate alternative actions to reduce our operating expenses and conserve cash.
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).
Optioned Assets - McCool Ranch Oil Field
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 October 31, 2024, we have paid approximately $284,000 during the year for restarting production operations on the assets and have a liability recorded of approximately $116,000 to Trio LLC as of October 31, 2024.
Optioned Assets - Asphalt Ridge Leasehold Acquisition & Development Option Agreement
On November 10, 2023, we entered into a leasehold acquisition and development option agreement (“ARLO Agreement”) with Heavy Sweet Oil, LLC (“HSO”) for a term of nine months, which gives the Company the exclusive right to acquire up to a 20% interest in a 960 acre drilling and production program in the Asphalt Ridge leases for $2,000,000, which may be invested in tranches by us, with an initial tranche closing for an amount no less than $500,000 and paid within seven days subsequent to HSO providing certain required items to the Company.
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.
We have 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 of the Asphalt Ridge Leases; if this option is not exercised on or before such date, we will forfeit any further right to acquire this additional 17.75% working interest in the initial 960 acres. As of October 31, 2024, we have paid a total of $225,000 to HSO in costs related to infrastructure and have a 2.25% interest in the leases; such costs are capitalized costs and are reflected in the balance of the oil and gas property as of October 31, 2024.
Emerging Growth Company Status
We are an “emerging growth company,” as defined in Section 2(a) of the Securities Act, as modified by the JOBS Act, and it may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404(b) of the Sarbanes-Oxley Act of 2002, reduced disclosure obligations regarding executive compensation in periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. Further, Section 102(b)(1) of the JOBS Act exempts emerging growth companies from being required to comply with new or revised financial accounting standards until private companies (that is, those that have not had a Securities Act registration statement declared effective or do not have a class of securities registered under the Exchange Act) are required to comply with the new or revised financial accounting standards. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies but any such election to opt out is irrevocable. We have elected not to opt out of such extended transition period which means that when a standard is issued or revised and it has different application dates for public or private companies, we, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of our financial statements with another public company which is neither an emerging growth company nor an emerging growth company which has opted out of using the extended transition period difficult or impossible because of the potential differences in accounting standards used.
Results of Operations
For the Year Ended October 31, 2024 compared to the Year Ended October 31, 2023
Our financial results for the years ended October 31, 2024 and 2023 are summarized as follows:
For the Years Ended
October 31,
Change % Change
Revenues, net $ 213,204 $ - $ 213,204 100.0 %
Operating expenses:
Exploration expenses $ 177,416 $ 251,743 $ (74,327 ) (29.5 )%
General and administrative expenses 4,716,057 3,315,782 1,400,275 42.2 %
Stock-based compensation expense 1,534,667 1,044,261 490,406 47.0 %
Accretion expenses 2,778 2,778 - 0.0 %
Total operating expenses 6,430,918 4,614,564 1,816,354 39.4 %
Loss from operations (6,217,714 ) (4,614,564 ) (1,603,150 ) 34.7 %
Other expenses:
Interest expense 2,118,548 791,811 1,326,737 167.6 %
Loss on settlement - 13,051 (13,051 ) (100.0 %)
Loss on note conversion 1,290,535 1,125,000 165,535 14.7 %
Total other expenses 3,409,083 1,929,862 1,479,221 76.6 %
Loss before income taxes (9,626,797 ) (6,544,426 ) (3,082,371 ) 47.1 %
Income tax benefit - - - -
Net loss $ (9,626,797 ) $ (6,544,426 ) $ (3,082,371 ) 47.1 %
Revenues, net
Revenues, net increased for year ended October 31, 2024 by approximately $0.2 million as compared to the prior period, which had no revenue; we sold and shipped approximately 2,900 barrels of oil, primarily produced from the HH-1 well.
Exploration expenses
Under the successful efforts method of accounting for crude oil and natural gas properties, exploration expenses consist primarily of exploratory geological and geophysical costs, delay rentals and exploratory overhead, and are expensed as incurred. Exploration expenses decreased by approximately $0.1 million as compared to the prior year period due to a decrease in exploratory, geological, and geophysical costs incurred during the period.
General and administrative expenses
General and administrative expenses consist primarily of personnel expenses, including salaries, benefits and stock-based compensation expense for employees and consultants in executive, finance and accounting, legal, operations support, information technology and human resource functions. General and administrative expenses also include corporate facility costs including rent, utilities, depreciation, amortization and maintenance, as well as legal fees related to intellectual property and corporate matters and fees for accounting and consulting services.
General and administrative expenses increased for year ended October 31, 2024 by approximately $1.4 million as compared to the prior period due to increases in legal fees of $210,000, increased insurance expenses of $150,000, increased filing fees of $325,000, increased consulting fees of $100,000 and increased salary expenses of approximately $550,000.
Stock-based compensation expense
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 $0.5 million for the year ended October 31, 2024 due to the amortization of 260,000 options issued in the current year period; such had not yet been granted during the same period in the prior year.
Accretion expenses
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 year ended October 31, 2024, accretion expenses remained consistent with that of the prior year period.
Other expenses, net
For the year ended October 31, 2024, other expenses, net increased by approximately $1.5 million when compared to the prior year period. The increase is attributable to an increase in non-cash interest expense of $1.3 million, which is recognized as debt discounts on financings are amortized; there were less financings in the prior period.
Liquidity and Capital Resources
Working Capital/(Deficiency)
Our working capital deficit as of October 31, 2024, in comparison to our working capital deficit as of October 31, 2023, can be summarized as follows:
October 31, 2024 October 31, 2023
Current assets $ 565,219 $ 1,695,341
Current liabilities 2,590,699 1,851,386
Working capital (deficiency) $ (2,025,480 ) $ (156,045 )
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 $0.5 million, as well as an increase in notes payable - related parties of approximately $0.3 million.
Cash Flows
Our cash flows for the year ended October 31, 2024, in comparison to our cash flows for the year ended October 31, 2023, can be summarized as follows:
Years ended October 31,
Net cash used in operating activities $ (3,840,744 ) $ (4,036,834 )
Net cash used in investing activities (1,089,882 ) (2,189,859 )
Net cash provided by financing activities 3,654,647 7,714,969
Net change in cash $ (1,275,979 ) $ 1,488,276
Cash Flows from Operating Activities
For the years ended October 31, 2024 and 2023, cash used in operating activities was $3,840,744 and $4,036,834, respectively. The cash used in operations for the year ended October 31, 2024 was primarily attributable to our net loss of $9,626,797, adjusted for non-cash expenses in the aggregate amount of $5,042,982, as well as $743,071 of net cash provided to fund changes in the levels of operating assets and liabilities. Our cash used in operations for year ended October 31, 2023 was primarily attributable to our net loss of $6,544,426, adjusted for non-cash expenses in the aggregate amount of $2,520,829, as well as $13,237 of net cash used to fund changes in the levels of operating assets and liabilities.
Cash Flows from Investing Activities
For the years ended October 31, 2024 and 2023, cash used in investing activities was $1,089,882 and $2,189,859, respectively. The cash used during the current period is attributable to approximately $1.2 million related to costs for capital expenditures, which were capitalized and are reflected in the balance of the oil and gas property as of October 31, 2024. Cash used from investing activities for the year ended October 31, 2023 was attributable to approximately $3.7 million related to drilling exploratory wells and approximately $0.4 million related to acquisition and reserve analysis costs, both of which were capitalized and are reflected in the balance of the oil and gas property as of October 31, 2023. These amounts were offset by approximately $1.9 million in amounts used from the Advance to Operators account, which is designated for costs for the HV-1 well.
Cash Flows from Financing Activities
For the years ended October 31, 2024 and 2023, cash provided by financing activities was$ 3,654,647 and $7,714,969, respectively. Cash provided by financing activities during the year ended October 31, 2024 was primarily attributable to proceeds of approximately $3.1 million from the issuance of promissory notes, related party notes and convertible notes payable and proceeds of approximately $1.2 million from the issuance of common shares in connection with an ATM agreement, offset by payments for debt in the amount of approximately $0.4 million and debt issuance costs of $0.3 million. Cash provided by financing activities during the year ended October 31, 2023 was primarily attributable to $6.7 million in gross proceeds from the issuance of common stock, $1.8 million in net proceeds from the exercise of warrants and $1.6 million in net proceeds from the convertible note financing, offset by the payment of offering costs of approximately $1.0 million and the payment of notes payables of approximately $1.5 million.
Our cash change was a decrease of approximately $1.3 million as of October 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.
Contractual Obligations and Commitments
Unproved Property Leases
We hold various leases related to the unproved properties of the South Salinas Project; two of the leases are held with the same lessor. The first lease, which covers 8,417 acres, was amended on May 27, 2022 to provide for an extension of then-current force majeure status for an additional, uncontested twelve months, during which we would be released from having to evidence to the lessor the existence of force majeure conditions. As consideration for the granting of the lease extension, we paid the lessor a one-time, non-refundable payment of $252,512; this amount was capitalized and reflected in the balance of the oil and gas property as of October 31, 2022. The extension period commenced on June 19, 2022 and currently, the “force majeure” status has been extinguished by the drilling of the HV-1 well. The ongoing operation and oil production at the HV-3A well maintain the validity of the lease.
The second lease covers 160 acres of the South Salinas Project; it is currently held by delay rental and is renewed every three years. Until drilling commences, we are required to make delay rental payments of $30/acre per year. We are currently in compliance with this requirement and have paid in advance the delay rental payment for the period from October 2023 through October 2024.
We hold interests in various leases related to the unproved properties of the McCool Ranch Oil Field. These leases occur in two parcels, “Parcel 1” and “Parcel 2”. Parcel 1 comprises ten leases and approximately 480 acres, which are held by delay rental payments that are paid-up and current. Parcel 2 comprises one lease and approximately 320 acres, which is held by production. The total leasehold comprises approximately 800 gross and net acres.
During February and March of 2023, we entered into additional leases related to the unproved properties of the South Salinas Project with two groups of lessors. The first group of leases covers 360 acres and has a term of 20 years; we are required to make rental payments of $25/acre per year. We are currently in compliance with this requirement and have paid in advance the rental payment for the period February 2024 through February 2025. The second group of leases covers 307.75 acres and has a term of 20 years; we are required to make rental payments of $30/acre per year. We are currently in compliance with this requirement and have paid in advance the rental payment for the period from March 2024 through March 2025.
On November 10, 2023, we entered into the ARLO Agreement with HSO for a term of nine months which allows us the exclusive right to acquire up to a 20% interest in a 960 acre drilling and production program in the Asphalt Ridge leases for $2,000,000, which may be invested in tranches, with an initial tranche closing for an amount no less than $500,000 and paid within seven days subsequent to HSO providing certain required items to us.
On December 29, 2023, we entered into an amendment to the ARLO Agreement, whereby we funded $200,000 of the $500,000 payable by us to HSO at the Initial Closing, in advance of HSO satisfying certain required items for a 2% interest in the leases; such funds are to be used by HSO solely for the building of roads and related infrastructure in furtherance of the development of the leases. As of October 31, 2024, we have paid a total of $225,000 to HSO in costs related to infrastructure and has obtained a 2.25% interest in the leases; such costs are capitalized costs and are reflected in the balance of the oil and gas property as of October 31, 2024.
Board of Directors Compensation
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 years ended October 31, 2024 and 2023, the Company has recognized $223,170 and $156,154, respectively, in directors’ fees.
Agreements with Advisors
On October 4, 2023 and December 29, 2023, the Company entered into placement agent agreements with Spartan Capital Securities, LLC (“Spartan”), whereby Spartan will serve 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.
Critical Accounting Policies and Estimates
Basis of Presentation
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.
Oil and Gas Assets and Exploration Costs - Successful Efforts
Our projects are in exploration and/or early production stages and we began generating revenue from its operations during the quarterly period ended April 30, 2024. We apply the successful efforts method of accounting for crude oil and natural gas properties. Under this method, exploration costs such as exploratory, geological, and geophysical costs, delay rentals and exploratory overhead are expensed as incurred. If an exploratory property provides evidence to justify potential development of reserves, drilling costs associated with the property are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. At the end of each quarter, management reviews the status of all suspended exploratory property costs considering ongoing exploration activities; in particular, whether we are making sufficient progress in our ongoing exploration and appraisal efforts. If management determines that future appraisal drilling or development activities are unlikely to occur, associated exploratory well costs are expensed.
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.
Unproved oil and natural gas properties
Unproved oil and natural gas properties have unproved lease acquisition costs, which are capitalized until the lease expires or otherwise until we specifically identify a lease that will revert to the lessor, at which time we charge the associated unproved lease acquisition costs to exploration costs.
Unproved oil and natural gas properties are not subject to amortization and are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. We currently have four wells that are producing (one well in President’s Field in the South Salinas Project and three wells at the McCool Ranch Oil Field) and are evaluating the impact of production on the reserve determination for those wells and fields. We expect to add the reserve value of such fields to our reserve report after a further period of observation and review of the oil production. As of October 31, 2024 and 2023, all of our oil and gas properties were classified as unproved properties and were not subject to depreciation, depletion and amortization.
Impairment of Other Long-lived Assets
We review the carrying value of our long-lived assets annually or whenever events or changes in circumstances indicate that the historical cost-carrying value of an asset may no longer be appropriate. We assess the recoverability of the carrying value of the asset by estimating the future net undiscounted cash flows expected to result from the asset, including eventual disposition. If the future net undiscounted cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset’s carrying value and estimated fair value. With regards to oil and gas properties, this assessment applies to proved properties; unproved properties are assessed for impairment either at an individual property basis or a group basis.
Asset Retirement Obligations
ARO consists of future plugging and abandonment expenses on oil and natural gas properties. In connection with the South Salinas Project acquisition described above, we acquired the plugging and abandonment liabilities associated with six temporarily shut-in, idle wells. The fair value of the ARO was recorded as a liability in the period in which the wells were acquired with a corresponding increase in the carrying amount of oil and natural gas properties. We plan to utilize the six wellbores acquired in the South Salinas Project acquisition in future production, development and/or exploration activities. The liability is accreted for the change in its present value each period based on the expected dates that the wellbores will be required to be plugged and abandoned. The capitalized cost of ARO is included in oil and gas properties and is a component of oil and gas property costs for purposes of impairment and, if proved reserves are found, such capitalized costs will be depreciated using the units-of-production method. The asset and liability are adjusted for changes resulting from revisions to the timing or the amount of the original estimate when deemed necessary. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
Recent Accounting Pronouncements
All recently issued but not yet effective accounting pronouncements have been deemed to be not applicable or immaterial to us.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Pursuant to Item 305(e) of Regulation S-K (§ 229.305(e)), the Company is not required to provide the information required by this Item as it is a “smaller reporting company,” as defined by Rule 229.10(f)(1).

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
The information required by this Item is included in this Report as set forth in the “Index to Consolidated Financial Statements” which appears on page of this Annual Report, after the signature pages of this Annual Report, and is incorporated by reference herein.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
On May 3, 2024, the US Securities and Exchange Commission (“Commission”) entered an Order denying BF Borgers CPA PC (“Borgers”) the privilege of appearing or practicing before the Commission as an accountant. As a result, Borgers may not participate in or perform the audit or review of financial information included in Commission filings, issue audit reports included in Commission filings, provide consents with respect to audit reports, or otherwise appear or practice before the Commission. As a result of the foregoing, on May 6, 2024, the Board of Directors terminated Borgers as the Company’s independent registered public accounting firm. Borgers had audited the Company’s financial statements for the two fiscal years ended October 31, 2022 and 2021 since the Company’s engagement of Borgers as its auditor on December 13, 2022.
Borger’s report on the Company’s financial statements for the fiscal years ended October 31, 2023 and 2022 did not contain an adverse opinion or disclaimer of opinion, nor was such report qualified or modified as to uncertainty, audit scope or accounting principle, except for an explanatory paragraph relating to a substantial doubt regarding the Company’s ability to continue as a going concern. During the fiscal years ended October 31, 2023, and 2022 and through May 6, 2024, there were no disagreements with BF Borgers on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure which, if not resolved to Borgers’s satisfaction, would have caused Borgers to make reference to the subject matter of the disagreement in connection with its report.
During the fiscal years ended October 31, 2023, and 2022 and through May 6, 2024, there were no “reportable events” as defined under Item 304(a)(1)(v) of Regulation S-K.
On May 8, 2024, the Company appointed Bush & Associates (“Bush”) as its new independent registered public accounting firm, effective immediately, for the fiscal years ended October 31, 2023, and 2022. This appointment was authorized and approved by the Audit Committee and Board of Directors of the Company.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Disclosure controls are procedures that are designed with the objective of ensuring that information required to be disclosed in our reports filed under the Exchange Act, such as this report, is recorded, processed, summarized, and reported within the time period specified in the SEC’s rules and forms. Disclosure controls are also designed with the objective of ensuring that such information is accumulated and communicated to our management, including the chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure. Our management evaluated, with the participation of our current chief executive officer and chief financial officer (our “Certifying Officer”), the effectiveness of our disclosure controls and procedures as of October 31, 2024, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, our Certifying Officer concluded that, as of October 31, 2024, our disclosure controls and procedures were effective.
We do not expect that our disclosure controls and procedures will prevent all errors and all instances of fraud. Disclosure controls and procedures, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. Further, the design of disclosure controls and procedures must reflect the fact that there are resource constraints, and the benefits must be considered relative to their costs. Because of the inherent limitations in all disclosure controls and procedures, no evaluation of disclosure controls and procedures can provide absolute assurance that we have detected all our control deficiencies and instances of fraud, if any. The design of disclosure controls and procedures also is based partly on certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.
Management’s Report on Internal Controls over Financial Reporting
The management of Trio Petroleum Corp. is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Internal control over financial reporting is a process designed by, or under the supervision of, our principal executive officer and principal financial officer, or persons performing similar functions, and effected by our board of directors to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
We are a “smaller reporting company” as defined in Item 10(f)(1) of Regulation S-K under the Securities Act. For as long as we continue to be a smaller reporting company, we may take advantage of exemptions from various reporting requirements that are applicable to other public companies that are not smaller reporting companies. Additionally, this Report does not contain an attestation report of our registered public accounting firm regarding internal control over financial reporting since the Company, as an “emerging growth company,” as defined in Section 2(a) of the Securities Act, as modified by the Jumpstart Our Business Startups Act of 2012, is not required to provide such report.
The management of Trio Petroleum Corp., including our principal financial officer, conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of October 31, 2024 using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in “Internal Control - Integrated Framework” (2013).
Management concluded that the Company’s internal control over financial reporting was effective as of October 31, 2024, based on those criteria.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION.
(c) Insider Trading Arrangements
During the quarterly period ended October 31, 2024, none of our directors or officers (as defined in Rule 16a-1(f) promulgated under the Exchange Act) adopted or terminated any “Rule 10b5-1 trading arrangement” or any “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The following table sets forth the name and age as of January 15, 2024, and position of the individuals who currently serve as directors and executive officers of the Company. The following also includes certain information regarding the individual experience, qualifications, attributes and skills of our directors and executive officers as well as brief statements of those aspects of our directors’ backgrounds that led us to conclude that they are qualified to serve as directors.
Name Age Position
Executive Officers
Robin Ross Chief Executive Officer and Chairman
Stanford Eschner Vice Chairman and Director
Gregory L. Overholtzer Chief Financial Officer
Non-Employee Directors
William J. Hunter Director
John Randall Director
Thomas J. Pernice Director
James H. Blake Director
Executive Officers
Robin Ross (Chief Executive Officer, Chairman and Director) has served as our Chief Executive Officer since July 2024, and Chairman and Director since June 2024. Mr. Ross previously served as a director of the Company from August 2021 to May 2023, and was a co-founder of the Company in July 2021. Since November 2023, Mr. Ross has served as the Chairman and CEO of Drillwaste Solutions Corp., a Canadian private company. Since October 2019, Mr. Ross has served as the founder of Gold’n Futures Mineral Corp. (CSE: FUTR), a junior resource company. Since 2007, Mr. Ross has served as the president of Vanross Enterprises Inc., a Canadian investment company. From 2008 until the sale of the company in August 2010, Mr. Ross served as a Co-Founder of Canada Potash Corporation, a Canadian resource company with access to over 1.7 million acres, or just over 15%, of the 11 million acres in the Williston Basin in South Central Saskatchewan, Canada. Mr. Ross previously held management positions at Canadian investment dealers for over 18 years. From 1999 until 2001, Mr. Ross served as Branch Manager and Director of Sales at Yorkton Securities, a Canadian biotechnology and investment dealer. From 1987 until 1999, Mr. Ross served as Branch Manager at Midland Walwyn Inc., a Canadian investment dealer.
Stanford Eschner (Vice Chairman and Director) has served as our Vice Chairman since June 2024. Prior to that, he served as our Executive Chairman since inception. Since 1983, Mr. Eschner has served as the Chairman of Trio LLC, the operator of the South Salinas Project. From 1961 until 1983, Mr. Eschner held various positions at Occidental Petroleum (NYSE: OXY), including geologist, Vice President of Domestic Operations and Vice President - Chief Geologist- Worldwide. Before that, Mr. Eschner was a geologist (lieutenant) with the Army Corp of Engineers from 1955 until 1957, and a production geologist with Shell Oil Co.1958 until 1961. Mr. Eschner has a Master of Arts degree in Geology from University of California, Los Angeles.
Gregory L. Overholtzer (Chief Financial Officer) has served as our Chief Financial Officer since February 2022. Since 2019, Mr. Overholtzer has worked as a part-time Chief Financial Officer of Indonesia Energy Corp. (NYSE AMERICAN: INDO). In addition, since November 2019, Mr. Overholtzer has served as a Consulting Director of Ravix Consulting Group. From December 2018 until November 2019, Mr. Overholtzer served as a Field Consultant at Resources Global Professionals. From January 2012 until December 2018, Mr. Overholtzer served as the Chief Financial Officer, Chief Accounting Officer and Controller of Pacific Energy Development (NYSE AMERICAN: PED). Mr. Overholtzer holds a BA in Zoology and an MBA in Finance from the University of California, Berkeley.
Non-Employee Directors
William J. Hunter (Director) has served as a Director since July 2022. From 2015 until 2022, Mr. Hunter served as Managing Partner of Hunter Resources LLC, a strategic and financial consulting firm. From 2017 until 2021, Mr. Hunter served as the President, Chief Financial Officer and Director of Advent Technologies post-merger with AMCI Acquisition Corp. From 2013 until 2015, Mr. Hunter served as Managing Director of the Industrial Group of Nomura Securities. Mr. Hunter is currently a Director at Tonogold Resources (OTCBB:TNGL) since 2022 and a former Director at American Battery Technology Corporation (NADAQ: ABAT) from 2016 to 2022. William Hunter received his B.Sc. from DePaul University in Chicago and an MBA with distinction from the Kellstadt School of Business at DePaul University.
John Randall (Director) has served as a Director since November 2021. From November 2022 to March 2023, Mr. Randall served as a professional geologist for Shopoff Reality Investment L.P. in connection with obtaining oil permits from the California Geologic Management Division for re-abandoned oil wells in Huntington Beach, California. From April 2017 until November 2021, Mr. Randall served as a professional geologist where he consulted to various companies and lenders. From April 2016 until April 2017, Mr. Randall was Vice President of the California Business Unit of Azimuth Energy. Before this, from 2003 until April 2016, Mr. Randall served as Senior Geologist at Freeport-McMoran Oil and Gas. From 1984 until 2001 Mr. Randall was a Geologist and senior manager at various divisions of Chevron in California and also during that time spent 4 years as an expatriate as the geological operations manager at Chevron’s Tengiz operations in Kazakhstan. From 1977 until 1984 Mr. Randall was a Geology Manager for Gulf Oil Corp and from 1970 until 1977 he was a development geologist for Union Oil Company. Mr. Randall holds an MS in Geology and a BS in Geology from Southern Illinois University. Mr. Randall also holds a registered professional geologic license in the states of California, Texas, Louisiana and Mississippi.
Thomas J. Pernice (Director) has served as a Director since November 2021. Mr. Pernice has served as the President of Modena Holding Corporation, a company providing corporate and executive advisory services, since 2000. In addition, he has served as a partner with The Abraham Group, an international strategic consulting firm and with Green Partners USA, LLC, a private equity real estate fund dedicated to green building since 2007. In 2004, he was appointed Senior Policy Advisor and Executive Director of the Secretary of Energy Advisory Board at the U.S. Department of Energy where he served until 2006. He was a partner and Managing Director of Cappello Group, a boutique investment and merchant bank in Los Angeles from 2000 to 2004. Mr. Pernice also served in the Family Offices of billionaire industrialist David H. Murdock where he was a member of the Chairman’s Global Leadership Team and Executive Officer of Dole Food Company, Inc. (NYSE: DOL) from 1992 to 2000. Mr. Pernice was as a Presidential Appointee and member of the senior White House staff serving from 1984 to 1992 where he traveled as a diplomatic representative of the United States to more than 92 countries. Further, Mr. Pernice has served as Executive Vice Chairman, a member of the board of director and an officer to Vaxanix Bio, Ltd since December 2023, as a member of the board of directors and officer to Vaxanix Bio Acquisition Corp I since January 2023, as a member of the board of director and officer to Vaxanix Bio Acquisition Corps II, III, IV, V, VI, VII and VIII since December 2023, as a member of the board of director of DrillWaste Corp. since October 2023, as a member of the board of directors of D3 Energy Corporation since 2022, and Panvaxal, LLC, a private biotechnology company since 2019. Mr. Pernice is also member of the board of advisors to JMS Energy Impact Fund since October 2023 and a member of the board of advisors to IOCharge Corp since September 2023. Mr. Pernice holds a BA in Broadcast Journalism from the University of Southern California.
James H. Blake (Director) has served as a Director since October 2024. From 1995 to 2024, when he retired, Mr. Blake served in the banking industry as an investment advisor and a Portfolio Manager and first Vice President overseeing a large portfolio of investments. Mr. Blake earned a Bachelor of Commerce degree in 1991 and completed his certification as a Chartered Financial Analyst in 2003.
Family Relationships
There are no family relationships among our directors or executive officers.
Director or Officer Involvement in Certain Prior Legal Proceedings
Our directors and executive officers were not involved in any legal proceedings as described in Item 401(f) of Regulation S-K in the past ten years, other than Mr. Pernice who served as a co-founder of Gibraltar Associates, LLC, a private company, from 2007 until 2013, which entity went into receivership in approximately September 2014.
Board Composition and Election of Directors
Our board of directors currently consists of six members. Under our amended and restated bylaws, the number of directors will be determined from time to time by our board of directors.
Director Independence
Our board has determined that Stanford Eschner and Robin Ross currently have relationships that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director, such that they cannot be deemed “independent” as that term is defined under the rules of the NYSE American, or the NYSE American rules. Our board has determined that William Hunter, John Randall, Thomas J. Pernice and James H. Blake are all “independent” as that term is defined under the NYSE American rules. As required under the NYSE American rules a majority of the members serving on the Board are considered to be “independent.”
Classified Board of Directors
In accordance with our amended and restated certificate of incorporation and amended and restated bylaws, our board of directors is divided into three classes with staggered, three-year terms. At each annual meeting of stockholders, the successors to directors whose terms then expire will be elected to serve from the time of election and qualification until the third annual meeting following election. Our directors are divided among the three classes as follows:
● the Class I directors are John Randall and Thomas J. Pernice, and their terms will expire at our annual meeting of stockholders in 2027;
● the Class II directors are William J. Hunter and James H. Blake, and their term will expire at our annual meeting of stockholders in 2025, and
● the Class III directors are Robin Ross and Stanford Eschner, and their terms will expire at the annual meeting of stockholders in 2026.
Our amended and restated certificate of incorporation and amended and restated bylaws provide that the authorized number of directors may be changed only by resolution of the board of directors. Any additional directorships resulting from an increase in the number of directors will be distributed among the three classes so that, as nearly as possible, each class will consist of one-third of the directors. The division of our board of directors into three classes with staggered three-year terms may delay or prevent a change of our management or a change in control of our company. Our directors may be removed only for cause by the affirmative vote of the holders of at least two-thirds of our outstanding voting stock entitled to vote in the election of directors.
Board Leadership Structure
Our corporate governance guidelines provide that, if the chairman of the board is a member of management or does not otherwise qualify as independent, the independent directors of the board may elect a lead director. The lead director’s responsibilities include, but are not limited to: presiding over all meetings of the board of directors at which the chairman is not present, including any executive sessions of the independent directors; approving board meeting schedules and agendas; and acting as the liaison between the independent directors and the chief executive officer and chairman of the board. Our corporate governance guidelines further provide the flexibility for our board of directors to modify our leadership structure in the future as it deems appropriate.
Role of the Board in Risk Oversight
One of the key functions of our board of directors is informed oversight of our risk management process. Our board of directors will not have a standing risk management committee, but will rather administer this oversight function directly through our board of directors as a whole, as well as through various standing committees of our board of directors that address risks inherent in their respective areas of oversight. In particular, our board of directors is responsible for monitoring and assessing strategic risk exposure and our Audit Committee has the responsibility to consider and discuss our major financial risk exposures and the steps our management has taken to monitor and control these exposures, including guidelines and policies to govern the process by which risk assessment and management is undertaken. Our Audit Committee also monitors compliance with legal and regulatory requirements. Our Nominating and Corporate Governance Committee monitors the effectiveness of our corporate governance practices, including whether they are successful in preventing illegal or improper liability-creating conduct. Our Compensation Committee assesses and monitors whether any of our compensation policies and programs has the potential to encourage excessive risk-taking. While each committee is responsible for evaluating certain risks and overseeing the management of such risks, our entire board of directors will be regularly informed through committee reports about such risks.
Board Committees
We have the following board of directors committees: an Audit Committee, a Compensation Committee and a Nominating and Corporate Governance Committee. The composition and responsibilities of each committee are described below. Members will serve on these committees until their resignation or until otherwise determined by our board of directors. Each committee’s charter is available under the Corporate Governance section of our website at www.trio-petroleum.com. The reference to our website address does not constitute incorporation by reference of the information contained at or available through our website, and you should not consider it to be a part of this Annual Report.
Audit Committee. The Audit Committee’s responsibilities include:
● appointing, approving the compensation of, and assessing the independence of our registered public accounting firm;
● overseeing the work of our registered public accounting firm, including through the receipt and consideration of reports from such firm;
● reviewing and discussing with management and the registered public accounting firm our annual and quarterly financial statements and related disclosures;
● coordinating our board of directors’ oversight of our internal control over financial reporting, disclosure controls and procedures and code of business conduct and ethics;
● discussing our risk management policies;
● meeting independently with our internal auditing staff, if any, registered public accounting firm and management;
● reviewing and approving or ratifying any related person transactions; and
● preparing the audit committee report required by SEC rules.
The members of our audit committee are William Hunter (chairperson), Thomas J. Pernice and John Randall. All members of our audit committee meet the requirements for financial literacy under the applicable rules and regulations of the SEC and the NYSE American. Our board has determined that William Hunter is an audit committee financial expert as defined under the applicable rules of the SEC and has the requisite financial sophistication as defined under the applicable rules and regulations of the NYSE American. Under the rules of the SEC, members of the audit committee must also meet heightened independence standards. Our board of directors has determined that all members of the audit committee are independent under the heightened audit committee independence standards of the SEC and the NYSE American.
The audit committee operates under a written charter that satisfies the applicable standards of the SEC and the NYSE American.
Compensation Committee. The Compensation Committee’s responsibilities include:
● reviewing and approving, or recommending for approval by the board of directors, the compensation of our Chief Executive Officer and our other executive officers;
● overseeing and administering our cash and equity incentive plans;
● reviewing and making recommendations to our board of directors with respect to director compensation;
● reviewing and discussing annually with management our “Compensation Discussion and Analysis,” to the extent required; and
● preparing the annual compensation committee report required by SEC rules, to the extent required.
The members of our compensation committee are Thomas J. Pernice (chair) and William Hunter. Each of the members of our compensation committee is independent under the applicable rules and regulations of the NYSE American and is a “non-employee director” as defined in Rule 16b-3 promulgated under the Exchange Act. The compensation committee operates under a written charter that satisfies the applicable standards of the SEC and the NYSE American.
Nominating and Corporate Governance Committee. The Nominating and Corporate Governance Committee’s responsibilities include:
● identifying individuals qualified to become board members;
● recommending to our board of directors the persons to be nominated for election as directors and to each board committee;
● developing and recommending to our board of directors corporate governance guidelines, and reviewing and recommending to our board of directors proposed changes to our corporate governance guidelines from time to time; and
● overseeing a periodic evaluation of our board of directors.
The members of our nominating and corporate governance committee are Thomas J. Pernice (chairperson) and John Randall. Each of the members of our Nominating and Corporate Governance Committee is an independent director under the applicable rules and regulations of the NYSE American relating to nominating and corporate governance committee independence. The Nominating and Corporate Governance Committee operates under a written charter that satisfies the applicable standards of the SEC and the NYSE American.
Compensation Committee Interlocks and Insider Participation
No member of our compensation committee is a current or former officer or employee. None of our executive officers served as a director or a member of a compensation committee (or other committee serving an equivalent function) of any other entity, one of whose executive officers served as a director or member of our compensation committee during the last completed fiscal year.
Code of Ethics and Code of Conduct
We have adopted a written code of business conduct and ethics that applies to our directors, officers and employees, including our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions. Our code of business conduct and ethics is available under the Corporate Governance section of our website at www.trio-petroleum.com. In addition, we have posted on our website all disclosures that are required by law or the rules of the NYSE American concerning any amendments to, or waivers from, any provision of the code. The reference to our website address does not constitute incorporation by reference of the information contained at or available through our website, and you should not consider it to be a part of this Annual Report.
Insider Trading Policies
On November 27, 2023, we adopted insider trading policies and procedures governing the purchase, sale, and/or other dispositions of our securities by directors, officers and employees, which are reasonably designed to promote compliance with insider trading laws, rules and regulations, and applicable Nasdaq listing standards (the “Insider Trading Policy”).
The foregoing description of the Insider Trading Policy does not purport to be complete and is qualified in its entirety by the terms and conditions of the Insider Trading Policy, a copy of which is attached hereto as Exhibit 19.1 and is incorporated herein by reference.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
Overview
We are currently considered a “smaller reporting company” for purposes of the SEC’s executive compensation and other disclosure rules. In accordance with such rules, we are required to provide a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year End Table, as well as limited narrative disclosures.
We design our executive officer compensation program to attract, motivate, and retain the key executives who drive our success and industry leadership. Our compensation program consists of several forms of compensation: base salary, cash incentive bonuses, equity compensation and other benefits and perquisites. Pay that reflects performance and alignment of that pay with the interests of long-term stockholders are key principles that underlie our compensation program. The Board believes that our current executive compensation program directly links executive compensation to our performance and aligns the interest of our executive officers with those of our shareholders.
Financial Restatement
It is a policy of our Board that the Compensation Committee will, to the extent permitted by governing law, have the sole and absolute authority to make retroactive adjustments to any cash or equity-based incentive compensation paid to executive officers and certain other officers where the payment was predicated upon the achievement of certain financial results that were subsequently the subject of a restatement. Where applicable, the Company will seek to recover any amount determined to have been inappropriately received by the individual executive.
Clawback Policy
We have adopted a Compensation Recovery Policy in accordance with applicable NYSE and NYSE American rules, a copy of which is filed as the exhibit 97.1 to this Annual Report. It is generally our policy that the Company will recoup any incentive compensation erroneously awarded to any current or former executive officers due to material noncompliance with any financial reporting requirement under applicable securities laws during the three completed fiscal years immediately preceding the date the Company determines that an accounting restatement is required.
Summary Compensation
The following sets forth the compensation paid by us to our named executive officers for the fiscal years ended October 31, 2024 and 2023.
Stock Option All Other
Salary Bonus Awards Awards Compensation Total
Name and Principal Position Year ($) ($) ($) ($) ($) ($)
Robin Ross 25,569 70,639 52,541 - 4,170 152,919
Chief Executive Officer and Chairman (1) - - - - - -
Michael Peterson 175,000 -
417,761 - - 592,761
Chief Executive Officer (2) 8,974 - - - 31,358 40,512
Greg Overholtzer 90,000 - 14,136
- - 104,136
Chief Financial Officer (3) 85,000 - - - - 85,000
Stanford Eschner 120,417 - 228,167 - - 348,584
Vice Chairman (4) 56,667 - 94,333 - - 151,000
Steven Rowlee 127,500 - 228,167 - - 355,667
Chief Operating Officer (5) 56,667 - 94,333 - - 151,000
Terence Eschner 120,417 - 228,167 - - 348,584
President (6) 56,667 - 94,333 - - 151,000
(1) Effective as of June 20, 2024, we appointed Mr. Ross as the Chairman of the Board of Directors; in connection with this appointment, we awarded Mr. Ross 50,000 shares of restricted stock, with 25% of the shares vesting six months after issuance and the remainder equally over the next twelve months on a quarterly basis. Effective as of July 11, 2024, we entered into an employment agreement with Mr. Ross, who became our Chief Executive Officer (“CEO”), for a term ending on December 31, 2026, which shall auto-renew for additional one-year terms. Per his employment agreement, we have agreed to pay Mr. Ross a salary at a rate of $300,000 per year. He is eligible for an annual bonus targeted at 100% of base salary, as determined by the Board based on his performance and the achievement by the Company of financial, operating and other objectives set by the Board. In connection with his appointment as the CEO, Mr. Ross was also granted an award of 100,000 shares of restricted stock, subject to Continuous Service, and which will vest with respect to 25% of the shares of restricted stock on January 9, 2025, and the remainder shall vest in equal tranches every three months thereinafter until either the shares of restricted stock are fully vested or Mr. Ross’s Continuous Service with the Company terminates, whichever occurs first.
(2) Effective as of October 23, 2023, we entered into an employment agreement with Mr. Peterson for a term ending on December 31, 2025; such employment agreement was terminated on July 11, 2024 as a result of his resignation as Chief Executive Officer of the Company. Per his employment agreement, Mr. Peterson was granted 50,000 shares of restricted stock, which had fully vested as of October 31, 2024. On July 11, 2024, the Company and Mr. Peterson entered into a Consulting Agreement, effective as of July 11, 2024, and continuing through October 11, 2024; in connection with the Consulting Agreement, the Company awarded Mr. Peterson 50,000 RSUs under the 2022 Plan, which were fully vested as of October 31, 2024. The Consulting Agreement was terminated on October 11, 2024, in accordance with its terms.
(3) Effective as of February 1, 2022, we entered into an employment agreement with Mr. Overholtzer, under which we agreed to pay him a salary of $60,000, with an increase to $120,000 on the first date the Company’s shares were publicly traded. He was eligible for an annual bonus that was targeted at 50% of his base salary beginning in 2022, and was also granted 5,000 RSUs, which were subject to Continuous Service and had a vesting period of two years. As of October 31, 2024, all such RSUs have vested and as of December 31, 2024, such agreement and Mr. Overholtzer’s employment with the Company expired by their terms. On January 1, 2025, we entered into an independent contractor agreement with Mr. Overholtzer, under which he continues to serve as the Chief Financial Officer of the Company and is paid a monthly fee of $12,500; the initial term of the agreement is for one year and will be automatically renewed unless either party provides a 30-day notice prior to the expiration of the agreement.
(4) Effective as of May 1, 2023, we entered into an employment agreement with Mr. Eschner for a term ending on December 31, 2024. Under his employment agreement, we agreed to pay Mr. Eschner a salary of $170,000, with the eligibility of an annual bonus targeted at 50% of his base salary, as determined by the Board based on his performance and the achievement by the Company of financial, operating and other objectives set by the Board. Mr. Eschner’s employment agreement and his employment with the Company expired by their terms on December 31, 2024. Mr. Eschner was also granted an award of 7,500 restricted shares, subject to continuous service, with a vesting schedule in which 25% of the restricted shares vest 5 months after the employment start date, with the remainder vesting in equal tranches every 6 months thereinafter. As of October 31, 2024, 5,625 of the shares awarded to Mr. Eschner had vested and as of December 31, 2024, the remaining 1,875 unvested shares were forfeited upon Mr. Eschner’s termination.
(5) Effective as of May 1, 2023, we entered into an employment agreement with Mr. Rowlee for a term ending on December 31, 2024. Under his employment agreement, we agreed to pay Mr. Rowlee a salary of $170,000, with the eligibility of an annual bonus targeted at 50% of his base salary, as determined by the Board based on his performance and the achievement by the Company of financial, operating and other objectives set by the Board. Mr. Rowlee’s employment agreement and his employment with the Company expired by their terms on December 31, 2024. Mr. Rowlee was also granted an award of 7,500 restricted shares, subject to continuous service, with a vesting schedule in which 25% of the restricted shares vest 5 months after the employment start date, with the remainder vesting in equal tranches every 6 months thereinafter. As of October 31, 2024, 5,625 of the shares awarded to Mr. Rowlee had vested and as of December 31, 2024, the remaining 1,875 unvested shares were forfeited upon Mr. Rowlee’s termination.
(6) Effective as of May 1, 2023, we entered into an employment agreement with Mr. Eschner for a term ending on December 31, 2024. Under his employment agreement, we agreed to pay Mr. Eschner a salary of $170,000, with the eligibility of an annual bonus targeted at 50% of his base salary, as determined by the Board based on his performance and the achievement by the Company of financial, operating and other objectives set by the Board. Mr. Eschner’s employment agreement and his employment with the Company expired by their terms on December 31, 2024. Mr. Eschner was also granted an award of 7,500 restricted shares, subject to continuous service, with a vesting schedule in which 25% of the restricted shares vest 5 months after the employment start date, with the remainder vesting in equal tranches every 6 months thereinafter. As of October 31, 2024, 5,625 of the shares awarded to Mr. Eschner had vested and as of December 31, 2024, the remaining 1,875 unvested shares were forfeited upon Mr. Eschner’s termination.
Outstanding Equity Awards at Year-End
The following table provides information on outstanding equity awards as of October 31, 2024 to our NEOs.
Equity Equity Incentive
incentive plan Plan awards:
awards: Market or
Number of payout value of
Number of Market value of unearned shares, unearned shares,
shares or units of shares or units of units or other units or other
stock that have stock that have rights that have rights that have
Name not vested not vested not vested not vested
Robin Ross (1) - - 150,000 $ 557,850
Michael Peterson (2) - - 50,000 $ 166,000
Greg Overholtzer (3) - - 10,000 $ 31,300
Stanford Eschner (4) - - 1,875 $ 66,770
Steven Rowlee (5) - - 1,875 $ 66,770
Terrence Eschner (6) - - 1,875 $ 66,770
(1) Mr. Ross was granted awards of 50,000 RSUs and 100,000 shares of restricted stock, which are all subject to Continuous Service and have vesting schedules in which 25% of the shares of restricted stock will vest six months after the effective date of the award, and the remainder shall vest in equal tranches every three months thereinafter until either the shares of restricted stock are fully vested or Mr. Ross’ Continuous Service with the Company terminates, whichever occurs first. As of October 31, 2024, none of the RSUs or shares of restricted stock awarded to Mr. Ross have vested.
(2) In connection with the Consulting Agreement that the Company and Mr. Peterson entered into on July 11, 2024, Mr. Peterson was granted 50,000 RSUs which fully vested 60 days after the date of grant; as of October 31, 2024, all of the shares of restricted stock awarded to Mr. Peterson had vested.
(3) Mr. Overholtzer was granted 10,000 RSUs which are subject to Continuous Service and have a vesting period of six months after the date of the award, at which point they will vest in full. As of October 31, 2024, none of the shares of restricted stock awarded to Mr. Overholtzer had vested.
(4) In connection with the employment agreement that the Company and Mr. Eschner entered into on May 1, 2023, Mr. Eschner was granted 7,500 RSUs which are subject to Continuous Service and have a vesting period of five months after the date of the award, with the remainder vesting in equal tranches every six months afterwards. As of October 31, 2024, all but 1,875 shares awarded to Mr. Eschner had vested.
(5) In connection with the employment agreement that the Company and Mr. Rowlee entered into on May 1, 2023, Mr. Rowlee was granted 7,500 RSUs which are subject to Continuous Service and have a vesting period of five months after the date of the award, with the remainder vesting in equal tranches every six months afterwards. As of October 31, 2024, all but 1,875 shares awarded to Mr. Rowlee had vested.
(6) In connection with the employment agreement that the Company and Mr. Eschner entered into on May 1, 2023, Mr. Eschner was granted 7,500 RSUs which are subject to Continuous Service and have a vesting period of five months after the date of the award, with the remainder vesting in equal tranches every six months afterwards. As of October 31, 2024, all but 1,875 shares awarded to Mr. Eschner had vested.
Narrative Disclosure to Summary Compensation Table
Employment Agreement - Robin Ross
We entered into an employment agreement with Robin Ross (the “Ross Employment Agreement”), who became our CEO, effective as of July 11, 2024, for a term ending on December 31, 2026, which shall auto-renew for additional one-year terms. Mr. Ross reports directly the Board and performs his services primarily in Toronto, Canada.
We have agreed to pay Mr. Ross a salary at a rate of $300,000 per year. He is eligible for an annual bonus targeted at 100% of base salary, as determined by the Board based on his performance and the achievement by the Company of financial, operating and other objectives set by the Board. Mr. Ross was also granted an award of 100,000 shares of restricted stock, subject to Continuous Service (as such term is defined in the Ross Employment Agreement, which award was made, and which will vest, with respect to 25% of the shares of restricted stock on January 9, 2025, and the remainder shall vest in equal tranches every three months thereinafter until either the shares of restricted stock are fully vested or Mr. Ross’s Continuous Service with the Company terminates, whichever occurs first. Mr. Ross also receives a standard benefit package, and reimbursement for reasonable business and travel expenses. He also is eligible for twenty-five vacation days per annum. Although Mr. Ross is employed pursuant to a term, either the Company or Mr. Ross may terminate his employment earlier. We may terminate Mr. Ross’s employment with or without Cause. “Cause” means: (a) conviction of, or plea of nolo contendere to any felony or crime involving dishonesty or moral turpitude (whether or not a felony); (b) any action by Mr. Ross involving fraud, breach of the duty of loyalty, malfeasance or willful misconduct; (c) the failure or refusal by Mr. Ross to perform any material duties hereunder or to follow any lawful and reasonable direction of the Company; (d) intentional damage to any property of the Company; (e) chronic neglect or absenteeism in the performance of Mr. Ross’s duties; (f) willful misconduct, or other material violation of Company policy or code of conduct that causes a material adverse effect upon the Company; (g) material uncured breach of any written agreement with the Company (subject to a 10 business day cure right on behalf of the Company); or (h) any action that in the reasonable belief of the Company shall or potentially shall subject the Company to negative or adverse publicity or effects.
Mr. Ross may resign on 90 days’ written notice.
Employment Agreement/Consulting Agreement - Michael L. Peterson
We entered into an employment agreement with Michael L. Peterson, who became our CEO, effective as of October 23, 2023, for a term ending on December 31, 2025, but his employment ended on July 11, 2024 as a result of his resignation as Chief Executive Officer of the Company.
On July 11, 2024, the Company and Mr. Peterson entered into a Consulting Agreement (the “Consulting Agreement”), effective as of July 11, 2024, and continuing through October 11, 2024, with a one-time option for the Company to renew the Consulting Agreement and Mr. Peterson’s services as a consultant for up to an additional three months thereafter. Pursuant to the Consulting Agreement, Mr. Peterson provided services relating to investor relations, public relations, financing strategies, corporate strategies, and development of business opportunities and providing background information with respect to Company’s history. In consideration for his consulting services, and pursuant to the terms of the Consulting Agreement, the Company paid Mr. Peterson a cash consulting fee equal to $10,000 per month, payable within five business days after the commencement of each calendar month during the term of the Consulting Agreement. In addition, the Company awarded Mr. Peterson 50,000 RSUs under the 2022 Plan, which award was made after the Company’s stockholders approved an increase in the number of shares available under the 2022 Plan at the 2024 Annual Meeting of Stockholders on August 15, 2024, and are fully vested. Mr. Peterson was also entitled to reimbursement for certain expenses. The Consulting Agreement was terminated on October 11, 2024, in accordance with its terms.
Employment Agreement/Independent Contractor Agreement - Gregory L. Overholtzer
Effective as of February 1, 2022, we entered into an employment agreement with our Chief Financial Officer, Gregory L. Overholtzer. Mr. Overholtzer was employed effective February 25, 2022, for a term ending on December 31, 2024. Mr. Overholtzer’s employment agreement and his employment with the Company expired by their terms on December 31, 2024. On January 1, 2025, we entered into an independent contractor agreement (the “IC Agreement”) with Mr. Overholtzer, under which he continues to serve as the Chief Financial Officer of the Company and performs his services in California.
The initial term of the IC Agreement continues until December 31, 2025, provided that the term will renew for successive one year periods, unless either party notifies the other party at least 30 days prior to the end of the then current term of its desire not to renew the IC Agreement. In addition, the IC Agreement may be terminated by either party upon 60 days’ prior written notice to the other party. Upon any such termination by the Company, the Company may terminate the Agreement prior to such 60-day notice period, but shall be required to pay Mr. Overholtzer the fees payable for such 60-day period. Furthermore, if Mr. Overholtzer provides notice of termination, but does not continue to provide the required services during such 60-day period, the Company may immediately terminate the IC Agreement and shall only be required to pay Mr. Overholtzer fees payable through such date of termination. Notwithstanding any of the foregoing, if the Company fails to timely pay Mr. Overholtzer any monthly fee, he shall have the right to terminate the IC Agreement on 30-days’ notice.
Mr. Overholtzer is entitled to the payment of a monthly fee of $12,500 for his services and reimbursement of all pre-approved expenses relating to his services upon presentation of invoices and receipts reasonably acceptable to the Company.
Each of the Company and Mr. Overholtzer has made customary representations and warranties to each other, and Mr. Overholtzer has agreed that during the term of the IC Agreement and for a period of two years, thereafter, not to solicit any employee of the Company for employment with any other business. Mr. Overholtzer has also agreed to a standard form of confidentiality provision under the terms of the Agreement and customary provisions relating to insider trading. Mr. Overholtzer has also agreed to assign to the Company any intellectual property rights relating to his services to the Company.
Employment Agreement- Steven A. Rowlee
We entered into an employment agreement with our former Chief Operating Officer, Steven A. Rowlee, effective as of May 1, 2023, for a term ending on December 31, 2024. Mr. Rowlee’s employment agreement and his employment with the Company expired by their terms on December 31, 2024. His position as Chief Operating Officer of the Company was officially eliminated by the Board as of January 2, 2025.
Employment Agreement- Terence B. Eschner
We entered into an employment agreement with our former President, Terence B. Eschner, effective as of May 1, 2023, for a term ending on December 31, 2024. Mr. Eschner’s employment agreement and his employment with the Company expired by their terms on December 31, 2024. His position as President of the Company was officially eliminated by the Board as of January 2, 2025.
Employment Agreement- Stanford Eschner
We entered into an employment agreement with our Vice Chairman, Stanford Eschner, effective as of May 1, 2023, for a term ending on December 31, 2024. Mr. Eschner’s employment agreement and his employment with the Company expired by their terms on December 31, 2024. Mr. Eschner continues to serve as our Vice Chairman in a non-employee capacity.
Incentive Award Plans
Equity Incentive Plan
We have adopted and approved the 2022 Plan. On August 15, 2024, at the 2024 annual meeting of the stockholders of the Company, the number of shares of common stock reserved for issuance with respect to awards granted under the 2022 Plan was approved by the stockholders to increase from 200,000 shares of common stock to 500,000 shares of common stock. Under the 2022 Plan, we may grant cash and equity incentive awards to eligible service providers in order to attract, motivate and retain the talent for which we compete. The material terms of the 2022 Plan are summarized below.
Types of Awards. The 2022 Plan provides for the grant of non-qualified stock options (“NQSOs”), incentive stock options (“ISOs”), restricted stock awards, restricted stock and restricted stock units (“RSUs”), equity appreciation rights, and other forms of stock-based compensation.
Eligibility and Administration. Employees, officers, consultants, directors, and other service providers of the Company and its subsidiaries are eligible to receive awards under the 2022 Plan. The 2022 Plan is administered by the board which may delegate its duties and responsibilities to committees of the company’s directors and/or officers (all such bodies and delegates referred to collectively as the plan administrator), subject to certain limitations that may be imposed under Section 16 of the Exchange Act, and/or other applicable law or stock exchange rules, as applicable. The plan administrator has the authority to make all determinations and interpretations under, prescribe all forms for use with, and adopt rules for the administration of, the 2022 Plan, subject to its express terms and conditions. The plan administrator also sets the terms and conditions of all awards under the 2022 Plan, including any vesting and vesting acceleration conditions.
Share Reserve. Pursuant to the 2022 Plan, we have reserved 500,000 shares of the shares of common stock for issuance thereunder. The share reserve is subject to the following adjustments:
● The share limit is increased by the number of shares subject to awards granted that later are forfeited, expire or otherwise terminate without issuance of shares, or that are settled for cash or otherwise do not result in the issuance of shares.
● Shares that are withheld upon exercise to pay the exercise price of a stock option or satisfy any tax withholding requirements are added back to the share reserve and again are available for issuance under the 2022 Plan.
Awards issued in substitution for awards previously granted by a company that merges with, or is acquired by, the Company do not reduce the share reserve limit under the 2022 Plan.
Stock Options and Equity Appreciation Rights. ISOs may be granted only to employees of the Company, or to employees of a parent or subsidiary of the Company, determined as of the date of grant of such options. An ISO granted to a prospective employee upon the condition that such person becomes an employee shall be deemed granted effective on the date such person commences employment. The exercise price of an ISO shall not be less than 100% of the fair market value of the shares covered by the awards on the date of grant of such option pursuant to the Internal Revenue Code of 1986, as amended from time to time (the “Code”). Notwithstanding the foregoing, an ISO may be granted with an exercise price lower than the minimum exercise price set forth above if such award is granted pursuant to an assumption or substitution for another option in a manner that complies with the provisions of Section 424(a) of the Code. Notwithstanding any other provision of the 2022 Plan to the contrary, no ISO may be granted under the 2022 Plan after 10 years from the date that the 2022 Plan was adopted. No ISO shall be exercisable after the expiration of 10 years after the effective date of grant of such award, subject to the following sentence. In the case of an ISO granted to a ten percent stockholder, (i) the exercise price shall not be less than 110% of the fair market value of a share on the date of grant of such ISO, and (ii) the exercise period shall not exceed 5 years from the effective date of grant of such ISO. Equity appreciation rights will entitle the holder to receive a payment (in cash or in shares) based on the appreciation in the fair market value of the shares subject to the award up to a specified date or dates. Equity appreciation rights may be granted to the holders of any stock options granted under the 2022 Equity Plan or may be granted independently of and without relation to stock options.
Restricted Stock and Restricted Stock Units. The committee may award restricted stock and RSUs under the 2022 Plan. Restricted stock awards consist of shares of stock that are transferred to the participant subject to restrictions that may result in forfeiture if specified vesting conditions are not satisfied. RSU awards result in the transfer of shares of stock to the participant only after specified vesting conditions are satisfied. A holder of restricted stock is treated as a current shareholder and shall be entitled to dividend and voting rights, whereas the holder of a restricted stock unit is treated as a shareholder with respect to the award only when the shares are delivered in the future. Specified vesting conditions may include performance goals to be achieved during any performance period and the length of the performance period. The committee may, in its discretion, make adjustments to performance goals based on certain changes in the Company’s business operations, corporate or capital structure or other circumstances. When the participant satisfies the conditions of an RSU award, the Company may settle the award (including any related dividend equivalent rights) in shares, cash or other property, as determined by the committee, in its sole discretion.
Other Shares or Share-Based Awards. The committee may grant other forms of equity-based or equity-related awards other than stock options, equity appreciation rights, restricted stock or restricted stock units. The terms and conditions of each stock-based award shall be determined by the committee.
Sale of the Company. Awards granted under the 2022 Plan do not automatically accelerate and vest, become exercisable (with respect to stock options), or have performance targets deemed earned at target level if there is a sale of the Company. The Company does not use a “liberal” definition of change in control as defined in Institutional Shareholder Services’ proxy voting guidelines. The 2022 Plan provides flexibility to the committee to determine how to adjust awards at the time of a sale of the Company.
Transferability of Awards. Except as described below, awards under the 2022 Plan generally are not transferable by the recipient other than by will or the laws of descent and distribution. Any amounts payable or shares issuable pursuant to an award generally will be paid only to the recipient or the recipient’s beneficiary or representative. The committee has discretion, however, to permit certain transfer of awards to other persons or entities.
Adjustments. As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the 2022 Plan and any outstanding awards, as well as the exercise price or base price of awards, and performance targets under certain types of performance-based awards, are subject to adjustment in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends, or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the stockholders.
Amendment and Termination. The board of directors may amend, modify or terminate the 2022 Plan without stockholder approval, except that stockholder approval must be obtained for any amendment that, in the reasonable opinion of the board or the committee, constitute a material change requiring stockholder approval under applicable laws, policies or regulations or the applicable listing or other requirements of a stock exchange on which shares of common stock are then listed. The 2022 Plan will terminate upon the earliest of (1) termination of the 2022 Plan by the board of directors, or (2) the tenth anniversary of the board adoption of the 2022 Plan. Awards outstanding upon expiration of the 2022 Plan shall remain in effect until they have been exercised or terminated or have expired.
Director Compensation
The following table provides information for the compensation of our non-employee directors for the fiscal year ended October 31, 2024:
Fees earned or Stock
paid in cash Awards Total
Name ($) ($) ($)
John Randall (1) 87,500 45,961 133,461
Thomas J. Pernice (2) 100,000 45,961 145,961
William J. Hunter (3) 87,500 45,961 133,461
James H. Blake (4) - 2,150 2,150
(1) Mr. Randall was awarded 5,000 and 12,500 restricted shares in September 2023 and October 2024, respectively, in connection with his Board service; such shares vest in full upon the six month anniversary and the three month anniversary, respectively, of the award dates.
(2) Mr. Pernice was awarded 5,000 and 12,500 restricted shares in September 2023 and October 2024, respectively, in connection with his Board service; such shares vest in full upon the six month anniversary and the three month anniversary, respectively, of the award dates.
(3) Mr. Hunter was awarded 5,000 and 12,500 restricted shares in September 2023 and October 2024, respectively, in connection with his Board service; such shares vest in full upon the six month anniversary and the three month anniversary, respectively, of the award dates.
(4) Mr. Blake was awarded 12,500 restricted shares in October 2024 in connection with his Board service; such shares vest in full upon the six month anniversary of the award date.
The material terms of the non-employee director compensation program are summarized below.
The non-employee director compensation provides for annual retainer fees and/or long-term equity awards for our non-employee directors. We expect each non-employee director will receive an annual retainer of $50,000 plus an additional $10,000 for each board committee that he or she is on.
Compensation under our non-employee director compensation policy will be subject to the annual limits on non-employee director compensation set forth in the 2022 Plan, as described above, but such limits will not apply prior to the first calendar year following the calendar year in which our initial public offering was completed. Our board of directors or its authorized committee may modify the non-employee director compensation program from time to time in the exercise of its business judgment, taking into account such factors, circumstances and considerations as it shall deem relevant from time to time, subject to the annual limit on non-employee director compensation set forth in the 2022 Plan. As provided in the 2022 Plan, our board of directors or its authorized committee may make exceptions to this limit for individual non-employee directors in extraordinary circumstances, as the board of directors or its authorized committee may determine in its discretion.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The following table sets forth information with respect to the beneficial ownership of our common stock, as of January 15, 2025 by:
● each person, or group of affiliated persons, known by us to beneficially own more than 5% of our outstanding shares of common stock (other than named executive officers and directors);
● each of our named executive officers;
● each of our directors;
● all of our executive officers and directors as a group;
The number of shares beneficially owned by each stockholder is determined in accordance with the rules issued by the SEC, and the information is not necessarily indicative of beneficial ownership for any other purpose. Under these rules, beneficial ownership includes any shares as to which the individual or entity has sole or shared voting power or investment power, which includes the power to dispose of or to direct the disposition of such security. Except as indicated in the footnotes below, we believe, based on the information furnished to us, that the individuals and entities named in the table below have sole voting and investment power with respect to all shares of common stock beneficially owned by them, subject to any community property laws.
Percentage ownership of our common is based on 6,725,702 shares of common stock outstanding as of January 15, 2025. In computing the number of shares beneficially owned by an individual or entity and the percentage ownership of that person, shares of common stock subject to options, restricted units, warrants or other rights held by such person that are currently exercisable or will become exercisable within 60 days of January 15, 2025 are considered outstanding, although these shares are not considered outstanding for purposes of computing the percentage ownership of any other person.
To calculate a stockholder’s percentage of beneficial ownership of common stock, we must include in the numerator and denominator those shares of common stock, as well as those shares of common stock underlying options, warrants and convertible securities, that such stockholder is considered to beneficially own. Shares of common stock underlying options, warrants and convertible securities, held by other stockholders, however, are disregarded in this calculation. Therefore, the denominator used in calculating beneficial ownership of each of the stockholders may be different.
Unless otherwise indicated, the address of each beneficial owner listed below is c/o Trio Petroleum Corp., 5401 Business Park South, Suite 115, Bakersfield, CA 93309. To our knowledge, there is no arrangement, including any pledge by any person of securities of the Company, the operation of which may at a subsequent date result in a change in control of the Company.
Beneficial Ownership of Common Stock
Name of Beneficial Owner Shares %
5% Stockholders:
- - -
Named Executive Officers and Directors:
Robin Ross (1) 150,000 2.23 %
Stanford Eschner (2) 57,500 *
Gregory L. Overholtzer (3) 15,000 *
William J. Hunter (4) 28,000 *
John Randall (5) 16,000 *
Thomas J. Pernice (6) 17,750 *
James H. Blake (7) 12,500 *
All directors and executive officers as a group (7 persons) 296,750 4.41 %
* Less than 1%
(1) Upon his appointment as the Chairman of the Company, in June 2024, the Board agreed to grant to Mr. Ross 50,000 RSUs, of which (i) 22,500 RSUs were awarded on June 20, 2024 and (ii) 27,500 RSUs were awarded after the Company’s stockholders approved an increase in the number of shares available under the 2022 Plan at the 2024 Annual Meeting of Stockholders on August 15, 2024. Additionally, upon being appointed as Chief Executive Officer of the Company on July 11, 2024, the Board agreed to grant to Mr. Ross 100,000 shares of restricted stock under the 2022 Plan, which were awarded after the Company’s stockholders approved an increase in the number of shares available under the 2022 Plan at the 2024 Annual Meeting of Stockholders on August 15, 2024. The number of shares of common stock includes 12,500 shares issuable to Mr. Ross upon the vesting of RSUs, within 60 days after January 15, 2025, if he continues to be employed by the Company on such vesting date but excludes 36,500 shares issuable to be Mr. Ross pursuant to the vesting of RSUs which do not vest within 60 days after January 15, 2025. The number of shares of common stock also includes 50,000 shares which have not yet been issued as of January 15, 2025.
(2) Consists of (i) 25,000 shares held by the Stanford Eschner Trust No. 1, for which Mr. Eschner holds investment and voting control over; the address of the Stanford Eschner Trust No. 1 is 6501 Kane Way, Bakersfield, CA 93309, (ii) 25,000 shares held by Trio LLC, a California Limited Liability Company, for which Mr. Eschner serves as the Executive Chairman, and as such may be deemed to hold investment and voting control over Trio LLC’s shares; the address of Trio LLC is 4115 Blackhawk Plaza Circle, Suite 100, Danville, CA 94506, and (iii) 7,500 shares held by Stanford Eschner himself.
(3) Includes 10,000 shares of restricted stock awarded to Mr. Overholtzer pursuant to the 2022 Plan, which will fully vest on April 21, 2025.
(4) Includes 12,500 shares of restricted stock awarded to Mr. Hunter pursuant to the 2022 Plan, which will fully vest on January 21, 2025.
(5) Includes 12,500 shares of restricted stock awarded to Mr. Randall pursuant to the 2022 Plan, which will fully vest on January 21, 2025.
(6) Includes 12,500 shares of restricted stock awarded to Mr. Pernice pursuant to the 2022 Plan, which will fully vest on January 21, 2025.
(7) Includes 12,500 shares of restricted stock awarded to Mr. Blake pursuant to the 2022 Plan, which will fully vest on April 21, 2025.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
The following includes a summary of transactions since July 19, 2021 (inception) to which we have been a party in which the amount involved will exceed $120,000, and in which any of our directors, executive officers or, to our knowledge, beneficial owners of more than 5% of our capital stock, or any member of the immediate family of any of the foregoing persons had or will have a direct or indirect material interest, other than equity and other compensation, termination, change in control and other arrangements, which are described under “Executive and Director Compensation.” We also describe below certain other transactions with our directors, executive officers and stockholders.
Related Party Transactions
Stanford Eschner and Steven Rowlee, former members of TPET’s management team, are also members of Trio LLC’s management team. Stanford Eschner, our Vice Chairman and a director, and Steven Rowlee, formerly our Chief Operating Officer, are employed by and/or part owners of Trio LLC. Stanford Eschner is Trio LLC’s Chairman and Steven Rowlee is its Vice President. Trio LLC personnel Stanford Eschner, Steven Rowlee, Gary Horace, Calli Shanley and Judy Ayler were salaried employees of TPET, until December 31, 2024, and are also employees and/or part owners of Trio LLC. Terence B. Eschner, our President, until December 31, 2024, also works as a consultant to Trio LLC through his company Sarlan Resources, Inc. Most of Trio LLC’s personnel are part owners of TPET. Trio LLC is Operator of the South Salinas Project and of the McCool Ranch Oil Field on behalf of TPET and of the other working interest owners. Transactions between TPET and Trio LLC are related party transactions because of these relationships. As a result of the related party transactions described above, a special committee of our board of directors, currently comprised of Mr. Ross, Mr. Randall and Mr. Hunter was formed to evaluate and negotiate the terms of any such transactions. In addition, in accordance with our Related Person Transaction Policy, we will have any such transactions reviewed and approved by our Board’s Audit Committee.
Michael Peterson, our former Chief Executive Officer and a former director until July 11, 2024, Frank C. Ingriselli, a former CEO of the Company and our former Vice Chairman and a director of TPET until June 17, 2024, and Gregory L. Overholtzer, our Chief Financial Officer, are employed by Lafayette Energy Corp (“LEC”). Michael Peterson is LEC’s Chief Executive Officer, Frank C. Ingriselli is a director of LEC, and Gregory L. Overholtzer is LEC’s Chief Financial Officer. TPET and LEC both have interests in the Asphalt Ridge Asset in Utah, TPET and LEC both have working interests and options for this asset. Transactions between TPET and LEC are related party transactions because of these relationships. As a result of the related party transactions described above, a special committee of our board of directors, comprised of Mr. Pernice, Mr. Randall and Mr. Hunter to evaluate and negotiate the terms of any such future transactions. In addition, in accordance with our Related Person Transaction Policy, we will have any such future transactions reviewed and approved by our Board’s Audit Committee.
South Salinas Project Purchase
Initial Purchase and Sale Agreement
On September 14, 2021, we entered into a purchase and sale agreement where we acquired Trio LLC’s approximate 82.75% WI in the South Salinas Project for consideration of $4 million and 245,000 shares of our common stock.
Fourth Amendment to the Purchase and Sale Agreement
On December 22, 2022, we entered into the Fourth Amendment where we acquired a subsequent additional approximate 3% WI in the South Salinas Project from Trio LLC for $60,529.40. In addition, the Fourth Amendment granted us a 120-day option to acquire the Optioned Assets. The Option Fee is $150,000, which was paid by the Company to Trio LLC. The Optioned Assets are as follows:
● The Hangman Hollow Field asset with an option to acquire Trio LLC’s 44% working interest and their Operatorship;
● The Kern Front Field asset with an option to acquire Trio LLC’s 22% working interest and their Operatorship; and
● The Union Avenue Field with an option to acquire Trio LLC’s 20% working interest and their Operatorship;
On May 12, 2023, subsequent to the 120-day option window referenced above, TPET announced the signing of an Acquisition Agreement to potentially acquire up to 100% of the working interest in the Union Avenue Field. The Agreement was between TPET and Trio LLC, with Trio LLC acting on behalf of itself as Operator and holding a 20% working interest in Union Avenue Field as well as agreeing to act to help facilitate the acquisition by TPET of the remaining 80% working interest. As Trio LLC is partly owned and controlled by members of Trio’s management, this would have been a related party transaction, and a special committee of Trio’s board of directors (the “Trio Special Committee”) was formed to evaluate and negotiate the terms of this acquisition. TPET engaged KLSP to conduct a comprehensive analysis and valuation of the asset, which analysis was delivered to TPET and evaluated by the Trio Special Committee. However, TPET and Trio LLC did not agree on the terms and transaction was not closed.
Under the Fourth Amendment, we also agreed to start the process of pursuing and consummating additional lease acquisitions in the areas deemed by the parties to be higher priority areas lying within and around the South Salinas Project Area. Such acquisitions were approved for an aggregate purchase price not to exceed approximately $79,000.00. Some leases were acquired in February and March, 2023, as described more-fully elsewhere hereunder.
Further under the Fourth Amendment, we agreed to engage the services of a contractor to do road access work and dirt-moving work (estimated to cost approximately $170,000.00) that was necessary before the commencement of drilling the HV-1 well. We also agreed to pay a deposit (in an amount not to exceed $25,000) to secure a drilling rig to drill the HV-1 well, which was drilled in May, 2023. This deposit was not required and was not paid.
Finally, we agreed, retroactively commencing on May 1, 2022, to accrue a monthly consulting fee of $35,000.00, due and payable by the Company to Trio LLC no later than two weeks following the closing date of Company’s IPO. This fee was intended to cover the work being done for the Company by Trio LLC’s employees prior to the closing date of our IPO. This consulting fee was paid by TPET to Trio LLC.
McCool Ranch Oil Field Asset Purchase
In October 2023, TPET entered into an agreement (“McCool Ranch Purchase Agreement”) with Trio LLC for purchase of a 21.918315% working interest in the McCool Ranch Oil Field located in Monterey County near the Company’s flagship South Salinas Project. As Trio LLC is partly owned and controlled by members of TPET’s management, this was a related party transaction, and the aforementioned Trio Special Committee was involved in the evaluation and negotiation of the terms of the acquisition. TPET engaged KLSP to conduct a comprehensive analysis and valuation of the asset, which in-progress, preliminary results were delivered to TPET and evaluated by the Trio Special Committee. The Company initially recorded a payment of $100,000 upon 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 mechanically capable of reasonably serving the produced water needs for the assets. With refurbishment successfully accomplished, the Company will pay an additional $400,000 per the McCool Ranch Purchase Agreement. TPET has paid approximately $284,000 to date for restarting production operations on the assets and has recorded a liability of $116,000 to Trio LLC as of October 31, 2024.
Asphalt Ridge Asset Purchase
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. LEC also have a working interest in the Asphalt Ridge Asset. Since LEC is partly owned and controlled by current and former members of our management, transactions including acquisitions between TPET and LEC relating to the Asphalt Ridge Asset and/or to other assets constitute related party transactions and, therefore, a special committee of our board of directors, comprised of Mr. Pernice, Mr. Randall and Mr. Hunter (the “Lafayette Special Committee”) has been formed to evaluate and negotiate the terms of any such future transactions. In addition, in accordance with our Related Person Transaction Policy, we will have any such future transactions reviewed and approved by our Board’s Audit Committee. TPET will engage KLS Petroleum Consulting LLC (“KLSP”) or other third-party experts, as deemed necessary by TPET’s management and/or by the Lafayette Special Committee, to conduct comprehensive analyses and to provide valuations of such assets, which analyses will be delivered to the Company and evaluated by the Trio Special Committee.
Restricted Stock Units (“RSUs”) issued to Directors
On July 11, 2022, the Company issued 3,000 shares of its $0.0001 par common stock to each of its five outside Directors with a fair value of $5.80 per share for an aggregate grant date value of $88,200. The fair value was calculated via a third-party valuation performed using income and market methods, as well as a discounted cash flow method, with the terminal value using a market multiples method, adjusted for a lack of marketability. The shares, or RSUs, vest in full upon the six-month anniversary of the IPO, subject to the directors’ continued service on the vesting date; upon issuance, the shares will be fully paid and non-assessable. Upon consummation of the IPO, the vesting period for these shares began and for the years ended October 31, 2023 and 2022, the Company recognized stock-based compensation in the amount of $88,200 and $0, respectively, within stock-based compensation expenses on the income statement, with unrecognized expense of $0 as of the period ended October 31, 2023.
On September 2, 2023, the Company issued an aggregate 21,250 shares of its $0.0001 par common stock to four outside directors with a fair value of $12.80 per share for a grant date value of $273,275. The shares, or RSUs, vested in full upon the six-month anniversary of the vesting commencement date (or August 28, 2023), subject to the directors’ continued service on the vesting date. For the three months ended April 30, 2024 and 2023, the Company recognized stock-based compensation in the amount of $41,364 and $177,259, respectively, within stock-based compensation expenses on the income statement, with no unrecognized expense as of the period ended April 30, 2024.
Restricted Shares issued to Executives and Employees
In February 2022, the Company entered into employee agreements with Frank Ingriselli (Chief Executive Officer or “CEO”) and Gregory L. Overholtzer (Chief Financial Officer or “CFO”) which, among other things, provided for the grant of restricted shares in the amounts of 50,000 and 5,000, respectively, pursuant to the 2022 Equity Incentive Plan (“the Plan”). Per the terms of the employee agreements, subject to continued employment, the restricted shares vest over a two-year period, under which 25% will vest upon the earlier of three months after the IPO or six months after the grant date. After this date, the remainder vest in equal tranches every six months until fully vested. As the Plan was not adopted until October 17, 2022 (see Note 7), these shares were recorded as of that date at a fair value of $5.88 per share; such value was calculated via a third-party valuation performed using income and market methods, as well as a discounted cash flow method, with the terminal value using a market multiples method, adjusted for a lack of marketability (see Note 10). As of October 31, 2022, the Company recorded 55,000 restricted shares at a fair value of $323,400, and for the years ended October 31, 2024 and 2023, the Company recognized stock-based compensation of $155,498 and $161,700, respectively, within stock-based compensation expenses on the income statement, with no unrecognized expense as of October 31, 2024.
In May 2023, the Company entered into six employee agreements which, among other things, provided for the grant of an aggregate of 35,000 restricted shares pursuant to the Plan. Per the terms of the employee agreements, subject to continued employment, the restricted shares vest as follows: 25% of the shares will vest five months after the issuance date, after which the remainder vest in equal tranches every six months until fully vested. The shares were recorded on the date of issuance at a fair value of $43.00 per share for an aggregate fair value of $1,505,000, and for the years ended October 31, 2024 and 2023, the Company recognized stock-based compensation of $753,188 and $440,219, respectively, within stock-based compensation expenses on the income statement, with no unrecognized expense as of the period ended October 31, 2024.
On July 20, 2023, pursuant to the Ingriselli Employment Agreement (see above), the Company issued 10,000 restricted shares (subject to the Plan) as a discretionary annual bonus at a fair value of $21.40 per share to Mr. Ingriselli for an aggregate fair value of $213,000. The shares vested fully on July 24, 2023 and the Company recognized stock-based compensation of $213,000 within stock-based compensation expenses on the income statement for the period ended October 31, 2023.
On October 16, 2023, the Company and Michael L. Peterson entered into an employment agreement (the “Peterson Employment Agreement”), effective as of October 23, 2023, pursuant to which Mr. Peterson served as Chief Executive Officer of the Company, replacing Mr. Ingriselli. Pursuant to the Peterson Employment Agreement, the Company issued Mr. Peterson is a grant of 50,000 shares of restricted stock pursuant to the Company’s Omnibus Incentive Compensation Plan (the “Plan”) at a fair value of $5.40 per share for a grant date fair value of $271,000. The restricted stock grant vests over a period of two years, with 25% of the shares of restricted stock vesting six months after the Peterson Employment Agreement Effective Date, and the remainder vesting in equal tranches on each of the 12-, 18-, and 24-month anniversary dates of the Peterson Employment Agreement. For the three months ended January 31, 2024 and 2023, the Company recognized stock-based compensation of $34,153 and $0, respectively, within stock-based compensation expenses on the income statement, with unrecognized expense of $233,505 as of the period ended January 31, 2024. On March 26, 2024, the Company borrowed $125,000 from Mr. Peterson (the “Peterson Loan”), in connection with which the Company delivered to Mr. Peterson an Unsecured Subordinated Promissory Note in the principal amount of $125,000 (the “Peterson Note”). As additional consideration for the Peterson Loan, the Company accelerated the vesting of 50,000 shares of restricted stock awarded to Mr. Peterson under the Company’s 2022 Equity Incentive Plan. For the years ended October 31, 2024 2023, the Company recognized stock-based compensation of $267,659 and $3,341, respectively, within stock-based compensation expenses on the income statement, with no unrecognized expense as of the period ended October 31, 2024. The Company repaid the entire outstanding principal balance of the Peterson Loan and all accrued interest thereon on November 26, 2024.
Peterson Consulting Agreement
On July 11, 2024, Mr. Peterson delivered notice of his resignation as the Company’s Chief Executive Officer, effective on July 11, 2024. In addition, on July 11, 2024, the Company and Mr. Peterson, entered into a consulting agreement, effective as of the date of resignation and continuing through October 11, 2024. Pursuant to the Consulting Agreement, the Company paid Mr. Peterson a cash consulting fee equal to $10,000 per month, during the term of the Consulting Agreement. In addition, the Company awarded to Mr. Peterson 50,000 RSUs under the 2022 Equity Incentive Plan, which award was made after the Company’s stockholders approved an increase in the number of shares available under the 2022 Equity Incentive Plan at the 2024 Annual Meeting of Stockholders on August 15, 2024.
Ingriselli Consulting Agreement
On October 6, 2023, Mr. Ingriselli delivered notice of his resignation as the Company’s Chief Executive Officer, effective on October 23, 2023. Upon his resignation, Mr. Ingriselli continued as a director and continued to hold the title of “Vice Chairman” of the Board of Directors of the Company. In addition, on October 16, 2023, the Company and Global Venture Investments LLC (“Consultant”), a Delaware Limited Liability Company and a wholly owned consulting firm owned 100% by Mr. Ingriselli, entered into a consulting agreement, effective as of the date of resignation and continuing through December 31, 2023. Pursuant to the Consulting Agreement, the Company will pay Mr. Ingriselli a cash consulting fee equal to $10,000 per month, payable within five business days after the commencement of each calendar month during the term of the Consulting Agreement. The Consulting Agreement terminated on December 31, 2023, in accordance with its terms. Mr. Ingriselli resigned as Vice Chairman and a director of the Company on June 17, 2024.
Asphalt Ridge Option Agreement
On November 10, 2023, the Company 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% production share 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 (the “Asphalt Ridge Leases”) and the Company acquired the option to participate in HSO’s initial 960 acre drilling and production program on such Asphalt Ridge Leases (the “Asphalt Ridge Option”).
The Asphalt Ridge Option had an original term of nine months, through August 10, 2024, which has been extended through February 10, 2025. Pursuant to the Asphalt Ridge Option, the Company has the exclusive right, but not the obligation, to acquire up to a 20% working interest in the Asphalt Ridge Leases for $2,000,000 (the “Purchase Price”), which may be invested in tranches, provided that the initial tranche closing occurs during the Asphalt Ridge Option period and subsequent tranches occurring as soon thereafter as practical within the Asphalt Ridge Option period, with each tranche providing the Company a portion of the ownership of the Asphalt Ridge Leases equal to 20% multiplied by a fraction, the numerator of which is the total consideration paid by the Company, and denominator of which is $2,000,000. Upon receipt of any funding from the Company pursuant to the Asphalt Ridge Option, HSO is required to pay that amount to the named operator of the properties, to pay for engineering, procurement, operations, sales, and logistics activities on the properties. The Asphalt Ridge Option Agreement provides that additional development capital is expected to be secured by HSO, and made available for the Company’s participation, by way of a reserve base lending facility (RBL), provided that if such RBL cannot be obtained or does not cover all subsequent capital costs, HSO agreed to fund a maximum of $5,000,000 of the first funding required for the development program, with the parties splitting any costs thereafter according to their ownership interests. The initial target is three wells, with an estimated cost of $5,000,000 for roads, pads, drilling, and above ground steam and storage facilities, and thereafter the parties anticipate working together to fund further well development based on their proportionate ownership thereof.
On or around the date the parties entered into the Asphalt Ridge Option Agreement, HSO entered into a Leasehold Acquisition and Development Option Agreement (the “LEC Option”) with Lafayette Energy Corp (“LEC”), of which Michael Peterson, Trio’s former Chief Executive Officer and director, is also the Chief Executive Officer and director. The LEC Option has similar terms as the Asphalt Ridge Option Agreement, except that it allows LEC to obtain a 30% interest in the Asphalt Ridge Leases and requires LEC to pay certain equity compensation to HSO.
The Company and HSO further agreed that, to the extent LEC does not fully exercise the LEC Option, the Company has the right to acquire up to all 30% of the rights set forth in the LEC Option (or such lesser amount which LEC has not exercised), from HSO, for $3,000,000 cash.
The exercise of the Asphalt Ridge Option is contingent, unless waived by the Company, upon the following: (a) HSO providing the Company the statements of revenues and direct operating expenses for the prior two years for the asset and the unaudited stub period for 2023, through the date of closing; (b) satisfactory due diligence review by the Company of HSO, the leases, the property and other information; (c) the negotiating of a mutually-acceptable joint operations agreement or other development and operations agreement(s) as agreed by the parties; and (d) HSO providing the Company an updated independent reserves report including proved undeveloped reserves (PUDs) and an estimate of gross valuation and discounted net present values, and indicating best estimate original oil-in-place (OOIP) volumes and gross (100%) contingent oil resources, as of a date no earlier than August 31, 2023, for discoveries located in Northwest Asphalt Ridge, Uinta Basin, Utah.
The Company previously exercised the Asphalt Ridge Option for a 2.25% working interest in the Asphalt Ridge Leases and 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 Asphalt Ridge Leases. If this option is not exercised on or before such date, the option will expire and the Company will forfeit any further right to acquire this additional 17.75% working interest.
Loan from former Chief Executive Officer
On March 26, 2024, the Company borrowed $125,000 from its former Chief Executive Officer, Michael L. Peterson (the “Peterson Loan”), in connection with which the Company delivered to Mr. Peterson an Unsecured Subordinated Promissory Note in the principal amount of $125,000 (the “Peterson Note”). As additional consideration for the Peterson Loan, the Company accelerated the vesting of 50,000 shares of restricted stock awarded to Mr. Peterson under the Company’s 2022 Equity Incentive Plan. The Company repaid the entire outstanding principal balance of the Peterson Loan and all accrued interest thereon on November 26, 2024.
Indemnification Agreements
We intend to enter into indemnification agreements with each of our directors and executive officers. These agreements, among other things, require us or will require us to indemnify each director and executive officer to the fullest extent permitted under the NRS, including indemnification of expenses such as attorneys’ fees, judgments, fines and settlement amounts incurred by the director or executive officer in any action or proceeding, including any action or proceeding by or in right of us, arising out of the person’s services as a director or executive officer. For further information, see “Description of Our Securities-Limitations on Liability and Indemnification Matters.”
Corporate governance and Director Independence.
See “Item 10. Directors, Executive Officers and Corporate Governance. - Board Composition and Election of Directors” beginning on page 47 of this Annual Report.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
The following table sets forth the aggregate fees billed by Bush & Associates CPA LLC and BF Borgers CPA PC for the fiscal years ending October 31, 2024 and 2023, respectively, as described below:
Audit Fees $ 158,500 $ 82,500
Audit Related Fees $ 27,500 $ 27,500
Tax Fees $ - $ -
All Other Fees $ 32,500 $ -
Total $ 218,500 $ 110,000
Pre-Approval Policies and Procedures
The Audit Committee mandate requires that the Audit Committee pre-approve any retainer of the auditor of the Company to perform any non-audit services to the Company that it deems advisable in accordance with applicable legal and regulatory requirements and policies and procedures of the Board. The Audit Committee is permitted to delegate pre-approval authority to one of its members; however, the decision of any member of the Audit Committee to whom such authority has been delegated must be presented to the full Audit Committee at its next scheduled meeting.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS, FINANCIAL STATEMENTS AND SCHEDULES.
Exhibit
Number
Description of Exhibit
3.1
Amended & Restated Certificate of Incorporation of Trio Petroleum Corp (incorporated by reference to Exhibit 3.2 of the Company’s Amendment No. 4 to Form S-1 (File No. 333-267380), filed with the Commission on January 5, 2023).
3.2
Certificate of Amendment to Amended and Restated Certificate of Incorporation of Trio Petroleum Corp. (incorporated by reference to Exhibit 3.1 of the Company’s Form 8-K, filed with the Commission on November 4, 2024)
3.3
Amended and Restated Bylaws of Trio Petroleum Corp. (incorporated by reference to Exhibit 3.4 of the Company’s Amendment No. 4 to Form S-1 (File No. 333-267380), filed with the Commission on January 5, 2023).
4.1
Specimen Common Stock Certificate evidencing the shares of Common Stock (incorporated by reference to Exhibit 4.1 of the Company’s Form S-1 (File No. 333-267380), filed with the Commission on September 12, 2022).
4.2
Common Stock Purchase Warrant (incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K, filed with the Commission on October 4, 2023).
4.3
Trio Petroleum Corp. Common Stock Purchase Warrant dated January 2, 2024 (incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K, filed with the Commission on January 2, 2024).
4.4
Trio Petroleum Corp. Placement Agent Warrant Agreement - Common Stock Purchase Warrant dated January 2, 2024. (incorporated by reference to Exhibit 4.3 of the Company’s Form 8-K, filed with the Commission on January 2, 2024).
4.5
Trio Petroleum Corp. Unsecured Subordinated Promissory Note in the principal amount of $125,000, with an issuance date of March 26, 2024 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K, filed with the Commission on April 1, 2024).
4.6
Promissory Note in the principal amount of $211,500, with an issue date of March 27, 2024 (incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K, filed with the Commission on April 8, 2024).
4.7
Senior Secured Convertible Promissory Note with an original issuance date of April 24, 2024 (incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K, filed with the Commission on April 25, 2024).
4.8
Amended and Restated Senior Secured Convertible Promissory Note with an original issuance date of April 16, 2024 and an amended and restated note issuance date of April 24, 2024 (incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K, filed with the Commission on April 25, 2024).
4.9
Promissory Note in the principal amount of $152,000, with an issue date of August 1, 2024 (incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K, filed with the Commission on August 5, 2024).
4.10
Promissory Note in the principal amount of $255,225, with an issue date of August 6, 2024 (incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K, filed with the Commission on August 8, 2024).
4.11
Senior Secured 10% Original Issue Discount Convertible Promissory Note (Aggregate Principal Amount of $800,000, dated June 27, 2024 (incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K, filed with the Commission on June 28, 2024).
4.12
Common Stock Purchase Warrant, dated June 27, 2024 (incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K, filed with the Commission on June 28, 2024).
4.13
Amendment No. 1 to Amended and Restated Senior Secured Convertible Promissory Note, dated August 14, 2024 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K, filed with the Commission on August 16, 2024).
4.14
Amendment No. 2 to Amended and Restated Senior Secured Convertible Promissory Note, dated September 16, 2024 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K, filed with the Commission on September 19, 2024).
4.15
Amendment No. 2 to Secured Convertible Promissory Note, dated September 16, 2024 (incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K, filed with the Commission on September 19, 2024).
4.16
Amendment No. 1 to Unsecured Subordinated Promissory Note, dated September 26, 2024 (incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K, filed with the Commission on September 27, 2024).
4.17
Description of Securities (incorporated by reference to Exhibit 4.2 of the Company’s Form 10-K, filed with the Commission on January 29, 2024).
10.1
Bid Proposal and Daywork Drilling Contract - U.S., by and Between Trio Petroleum LLC and Ensign United States Drilling (California) Inc., dated April 19, 2023 (incorporated by reference to Exhibit 10.1 of the Company’s current report on Form 8-K filed with the Commission on April 25. 2023),
10.2
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 of the Company’s Form S-1 (File No. 333-267380), filed with the Commission on September 12, 2022).
10.3†
Incentive Plan (incorporated by reference to Exhibit 10.2 of the Company’s Form S-1 (File No. 333-267380), filed with the Commission on September 12, 2022).
10.4†
Employment Agreement with Gregory L. Overholtzer (incorporated by reference to Exhibit 10.4 of the Company’s Form S-1 (File No. 333-267380), filed with the Commission on September 12, 2022.
10.5
Purchase and Sale Agreement with Trio Petroleum LLC (incorporated by reference to Exhibit 10.5 of the Company’s Form S-1 (File No. 333-267380), filed with the Commission on September 12, 2022).
10.6
First Amendment to Purchase and Sale Agreement with Trio Petroleum LLC (incorporated by reference to Exhibit 10.6 of the Company’s Form S-1 (File No. 333-267380), filed with the Commission on September 12, 2022).
10.7
Second Amendment to Purchase and Sale Agreement with Trio Petroleum LLC (incorporated by reference to Exhibit 10.7 of the Company’s Form S-1 (File No. 333-267380), filed with the Commission on September 12, 2022).
10.8
Third Amendment to Purchase and Sale Agreement with Trio Petroleum LLC (incorporated by reference to Exhibit 10.8 of the Company’s Form S-1 (File No. 333-267380), filed with the Commission on September 12, 2022).
10.9
Fourth Amendment to Purchase and Sale Agreement with Trio Petroleum LLC (incorporated by reference to Exhibit 10.9 of the Company’s Amendment No. 1 to Form S-1 (File No. 333-267380), filed with the Commission on January 5, 2023).
10.10
Blue Lease with Bradley Minerals (incorporated by reference to Exhibit 10.11 of the Company’s Form S-1 (File No. 333-267380), filed with the Commission on September 12, 2022).
10.11
First Amendment to Blue Lease with Bradley Minerals (incorporated by reference to Exhibit 10.10 of the Company’s Form S-1 (File No. 333-267380), filed with the Commission on September 12, 2022).
10.12
Red Lease with Bradley Minerals (incorporated by reference to Exhibit 10.11 of the Company’s Form S-1 (File No. 333-267380), filed with the Commission on September 12, 2022).
10.13
First Amendment to Red Lease with Bradley Minerals (incorporated by reference to Exhibit 10.12 of the Company’s Form S-1 (File No. 333-267380), filed with the Commission on September 12, 2022).
10.14
Second Amendment to Red Lease with Bradley Minerals (incorporated by reference to Exhibit 10.13 of the Company’s Form S-1 (File No. 333-267380), filed with the Commission on September 12, 2022).
10.15
Third Amendment to Red Lease with Bradley Minerals (incorporated by reference to Exhibit 10.14 of the Company’s Form S-1 (File No. 333-267380), filed with the Commission on September 12, 2022).
10.16
Fourth Amendment to Red Lease with Bradley Minerals (incorporated by reference to Exhibit 10.15 of the Company’s Form S-1 (File No. 333-267380), filed with the Commission on September 12, 2022.
10.17
Fifth Amendment to Red Lease with Bradley Minerals (incorporated by reference to Exhibit 10.16 of the Company’s Form S-1 (File No. 333-267380), filed with the Commission on September 12, 2022.
10.27
Joint Operating Agreement (incorporated by reference to Exhibit 10.27 of the Company’s Amendment No. 2 to Form S-1 (File No. 333-267380), filed with the Commission on November 18, 2022, as amended).
10.28
December 2022 Subscription Agreement (incorporated by reference to Exhibit 10.28 of the Company’s Amendment No. 5 to Form S-1 (File No. 333-267380), filed with the Commission on January 20, 2023, as amended).
10.29
December 2022 Warrant (incorporated by reference to Exhibit 10.29 of the Company’s Amendment No. 5 to Form S-1 (File No. 333-267380), filed with the Commission on January 20, 2023, as amended).
10.30
First Amendment to Convertible Promissory Note with GenCap Fund I LLC (incorporated by reference to Exhibit 10.30 of the Company’s Amendment No. 6 to Form S-1 (File No. 333-267380), filed with the Commission on February 6, 2023, as amended).
10.31
Second Amendment to Convertible Promissory Note with GenCap Fund I LLC (incorporated by reference to Exhibit 10.31 of the Company’s Amendment No. 7 to Form S-1 (File No. 333-267380), filed with the Commission on February 28, 2023, as amended).
10.32
Extension Letter for Note Payable with Trio Petroleum LLC (incorporated by reference to Exhibit 10.32 of the Company’s Amendment No. 7 to Form S-1 (File No. 333-267380), filed with the Commission on February 28, 2023, as amended).
10.33
Third Amendment to Convertible Promissory Note with GenCap Fund I LLC (incorporated by reference to Exhibit 10.33 of the Company’s Amendment No. 8 to Form S-1 (File No. 333-267380), filed with the Commission on March 17, 2023, as amended).
10.34
Second Extension Letter for Note Payable with Trio Petroleum LLC (incorporated by reference to Exhibit 10.34 of the Company’s Amendment No. 8 to Form S-1 (File No. 333-267380), filed with the Commission on March 17, 2023, as amended).
10.35
Extension Letter for Original Issue Discount Note (incorporated by reference to Exhibit 10.35 of the Company’s Amendment No. 8 to Form S-1 (File No. 333-267380), filed with the Commission on March 17, 2023, as amended).
10.36†
Form of Employment Agreement with Stanford Eschner (incorporated by reference to Exhibit 10.31 of the Company’s Amendment No. 6 to Form S-1 (File No. 333-267380), filed with the Commission on February 6, 2023, as amended).
10.41
Securities Purchase Agreement, dated as of October 4, 2023, by and between the Investor and Trio Petroleum Corp (incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K, filed with the Commission on October 4, 2023).
10.44
Registration Rights Agreement, dated October 4, 2023, by and between the Investor and Trio Petroleum Corp. (incorporated by reference to Exhibit 10.5 of the Company’s Form 8-K, filed with the Commission on October 4, 2023).
10.46
Amendment to Transaction Documents between the Investor and Trio Petroleum Corp., dated December 29, 2023. (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K, filed with the Commission on January 2, 2024).
10.47
Leasehold Acquisition and Development Agreement, dated November 10, 2023, entered into by and between Trio Petroleum Corp and Heavy Sweet Oil LLC (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K, filed with the Commission on January 5, 2024).
10.48
Amendment to Leasehold Acquisition and Development Agreement, dated December 29, 2023, entered into by and between Trio Petroleum Corp and Heavy Sweet Oil LLC (incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K, filed with the Commission on January 5, 2024)
10.49
Amended and Restated Securities Purchase Agreement between the Company and the Investors signatory thereto, dated as of April 24, 2024 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K, filed with the Commission on April 25, 2024).
10.50
Amended and Restated Security Agreement between the Company and the Secured Parties signatory thereto, dated as of April 24, 2024 (incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K, filed with the Commission on April 25, 2024).
10.51†
Form of Employment Agreement between the Company and Robin Ross, dated as of July 11, 2024 (incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K, filed with the Commission on July 15, 2024).
10.52
Form of Consulting Agreement between the Company and Michael L. Peterson, dated as of July 21, 2024 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K, filed with the Commission on July 15, 2024).
10.53
Securities Purchase Agreement between the Company and the Investor signatory thereto, dated as of March 27, 2024 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K, filed with the Commission on April 8, 2024).
10.54
Securities Purchase Agreement between the Company and the Investor signatory thereto, dated as of August 1, 2024 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K, filed with the Commission on August 5, 2024).
10.55
Securities Purchase Agreement between the Company and the Investor signatory thereto, dated as of August 6, 2024 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K, filed with the Commission on August 8, 2024).
10.56
Second Amendment to Leasehold Acquisition and Development Agreement, dated August 5, 2024, entered into by and between Trio Petroleum Corp and Heavy Sweet Oil LLC (incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K, filed with the Commission on August 8, 2024).
10.57
Media Advertising Agreement, dated September 9, 2024 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K, filed with the Commission on September 12, 2024).
10.58
Amendment No. 3 to Leasehold Acquisition and Development Option Agreement (incorporated by reference to Exhibit 10.3 of the Company’s Form 8-K, filed with the Commission on September 27, 2024).
10.59†
Independent Contractor Agreement between the Company and Greg Overholtzer, dated as of January 1, 2025 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K, filed with the Commission on January 8, 2025).
14.1*
Code of Ethics
16.1
Letter from Marcum LLP to the Securities Exchange Commission (incorporated by reference to Exhibit 16.1 of the Company’s Amendment No. 6 to Form S-1 (File No. 333-267380), filed with the Commission on February 6, 2023, as amended).
19.1
Insider Trading Policy (incorporated by reference to Exhibit 19.1 of the Company’s Annual Report on Form 10-K filed with the Commission on January 29, 2024).
23.1*
Consent of Independent Registered Public Accounting Firm
23.2*
Consent of KLS Petroleum Consulting LLC
24.1*
Power of Attorney
31.1
Certification of the Principal Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
Certification of the Principal Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**
Certification of the Principal Executive Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**
Certification of the Principal Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
97.1
Executive Compensation Clawback Policy (incorporated by reference to Exhibit 97 of the Company’s Annual Report on Form 10-K filed with the Commission on January 29, 2024).
99.1
Reserves Attributable to Trio Petroleum Corp South Salinas Area for Development Plan Phases 1 and 2 (incorporated by reference to Exhibit 99.1 of the Company’s Amendment No. 2 to Form S-1 (File No. 333-267380), filed with the Commission on November 18, 2022, as amended).
99.2
S. Salinas Area, Full Development Reserves Supplement to SEC Report Dated 1-28-2022 (incorporated by reference to Exhibit 99.2 of the Company’s Amendment No. 2 to Form S-1 (File No. 333-267380), filed with the Commission on November 18, 2022, as amended).
99.3
Reserve Attributable to Trio Petroleum Corp. South Salinas Area for Phased and Full Development (incorporated by reference to Exhibit 99.3 of the Company’s Amendment No. 2 to Form S-1 (File No. 333-280816), filed with the Commission on November 29, 2024, as amended).
101.INS*
Inline XBRL Instance Document
101.SCH*
Inline XBRL Taxonomy Extension Schema Document
101.CAL*
Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*
Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*
Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*
Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*
Cover Page Interactive Data File (Embedded as Inline XBRL document and contained in Exhibit 101).
* Filed herewith.
** Furnished, not filed
† Includes management contracts and compensation plans and arrangements