Trio Petroleum Corp

Overview

We are a California-based oil and gas exploration and development company headquartered in Malibu, California, with our principal executive offices located at 23823 Malibu Road, Suite 304, Malibu, California 90265, with operations in Monterey County, California, Uintah County, Utah and Lloydminster, Saskatchewan.

We have had revenue-generating operations since the McCool Ranch Oil Field (defined hereafter) 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. During the period ended April 30, 2025 we began generating revenue from our newly acquired properties in Saskatchewan, Canada.

Our Canadian projects represent a significant growth opportunity, driven primarily by planned workovers intended to enhance production across the acquired assets. We began executing this program immediately following the closing of our April 2025 acquisition of certain heavy oil assets in west-central Saskatchewan, Canada, including producing heavy oil wells, from Novacor (defined below), a company recognized as one of the lowest-cost operators in the region. In November 2025, we expanded our presence with the acquisition of a second Canadian project from Capital Land (defined below). Our strategy continues to focus on acquiring assets that generate immediate cash flow, provide meaningful long-term development potential, and offer the potential for transformative value creation through targeted strategic investment.

We were formed to initially acquire an approximate 82.75% working interest (which was subsequently increased to an approximate 85.775% working interest) from Trio LLC (“Trio LLC”) in the large, approximately 9,300-acre South Salinas Project that is located in Monterey County, California, and subsequently partner with certain members of Trio LLC’s management team to develop and operate those assets. We hold an approximate 68.62% interest after the application of royalties (“net revenue interest”) in the South Salinas Project. Trio LLC holds an approximate 3.9% working interest in the South Salinas Project. We and Trio LLC are separate and distinct companies. The remaining working interests are owned by two unrelated parties.

Initially, California was a significant part of our geographic focus; however, due to rising drilling costs and the negative impact on potential profitability, we have strategically shifted our efforts beyond California to pursue more economically viable opportunities. This transition is reflected in our acquisition of an interest in oil properties that are a part of the Asphalt Ridge Project in Uintah County, Utah, as well as our recent acquisition from Novacor, described above, in the prolific Lloydminster, Saskatchewan heavy oil region and from Capital Land in the County of Vermilion of River (formerly known as the Municipal District of Wellington No. 41).

Recent Business Developments

Changes to Company Management

Effective as of August 1, 2025, Stanford Eschner retired as Vice Chairman and a director of the Company.

Changes to Independent Registered Public Accounting Firm

On May 6, 2024, the Company dismissed BF Borgers CPA PC (“Borgers”) as the Company’s independent registered public accounting firm, as a result of Borgers no longer being able to audit the Company’s financial statements, pursuant to an order by the Securities and Exchange Commission against Borgers (the “SEC Order”). Effective May 8, 2024, the Company retained Bush & Associates CPA LLC (“Bush & Associates”) as its new independent registered public accounting firm. Also, pursuant to the requirements of the SEC Order, Bush & Associates re-audited the Company’s financial statements for the fiscal years ended October 31, 2023 and 2022, which financial statements were filed with Amendment No. 1 to the Company’s Report on Form 10-K/A filed with the SEC on June 13, 2024.

Efforts to obtain from Monterey County conditional use permits and a full field development permit for the South Salinas Project are progressing. Efforts to obtain from the California Geologic Energy Management Division (“CalGEM”) and from the California Water Boards a permit for a water disposal project at the South Salinas Project are also progressing. In the meantime, the Company recently determined that existing permits allow production testing to continue at the HV-3A discovery well at Presidents Field and, consequently, testing operations were restarted at this well on March 22, 2024. Oil production from this well has occurred and the Company is assessing steps to attempt to increase the well’s gross production rate, for example by adding up to 650 feet of additional perforations in the oil zone and/or acidizing the well for borehole cleanup. First oil sales from the HV-3A well occurred in the third calendar quarter of 2024 but is currently idled as we further discussions with local oil and gas companies to joint venture the project.

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 entered into an agreement to acquire an approximate 22% working interest in and to certain oil and gas assets at the McCool Ranch Field, located in Monterey County, California, near our flagship South Salinas Project.

The acquired assets included six oil wells, a water-disposal well, a steam generator, boiler, storage tanks, and various operational infrastructure. While initial production was restarted on February 22, 2024, we have subsequently determined that under previously negotiated terms, natural gas prices and water disposal costs, particularly in California, makes it cost prohibitive for the Company to employ cyclic-steam operations to increase production and will not be economically feasible in the long run. On May 27, 2025, we executed a termination agreement with Trio LLC to end operations at the location and abandon all related leases. Capitalized costs totaling $500,614 have been written off and expensed in the statement of operations for the period ended April 30, 2025.

Asphalt Ridge Option Agreement and the Lafayette Energy Leasehold Acquisition and Development Option Agreement

On November 10, 2023, we entered into a Leasehold Acquisition and Development Option Agreement (the “Asphalt Ridge Option Agreement”) with Heavy Sweet Oil LLC (“HSO”). Pursuant to the Asphalt Ridge Option Agreement, we acquired an option to purchase up to a 20% working interest in certain leases at a long-recognized, major oil accumulation in northeastern Utah, including an initial 960 acres and a subsequent 1,920 acres, as well as a right-of-refusal option on approximately 30,000 acres.

On December 29, 2023, we and HSO entered into an Amendment to the Asphalt Ridge Option Agreement, under which we funded $200,000 in exchange for an immediate 2% working interest in the initial 960 acres. An additional $25,000 was funded in January 2024, increasing our working interest to 2.25%. While we had the option to acquire an additional 17.75% working interest, we decided not to exercise this option and will instead retain our existing 2.25% working interest in the initial 960 acres.

Novacor Asset Purchase Agreement

As of April 4, 2025, we entered into an Asset Purchase Agreement (the “April 2025 Novacor APA”) with Trio Petroleum Canada, Corp., an Alberta, Canada corporation and a wholly owned subsidiary of the Company (“Trio Canada”), and Novacor Exploration Ltd., a corporation incorporated under the Canada Business Corporations Act (“Novacor”), pursuant to which, subject to the terms and conditions set forth in the April 2025 Novacor APA, Trio Canada agreed to acquire certain assets of Novacor relating its oil and gas business, including certain contracts, leases and permits for working interests in petroleum and natural gas and mineral rights located in the Lloydminster, Saskatchewan heavy oil region in Canada (collectively, the “April 2025 Novacor Assets”), free and clear of any liens other than certain specified liabilities of Novacor that are being assumed (collectively, the “Liabilities” and such acquisition of the Novacor Assets and assumption of the Liabilities together, the “April 2025 Novacor Acquisition”) for a total purchase price of (i) US$650,000, in cash, US$65,000 of which was previously provided as a deposit to Novacor, and (ii) the issuance to Novacor of 526,536 shares of common stock of common stock. The April 2025 Novacor Acquisition was consummated in two closings, which was completed on May 22, 2025. All five of our currently active wells are in the newly acquired Novacor property.

P.R. Spring Letter of Intent and Option

On May 15, 2025, we entered into a non-binding Letter of Intent (LOI) with HSO for the potential acquisition of 2,000 acres of oil and gas properties at P.R. Spring, Uintah Basin, Utah (“P.R. Spring”), which is adjacent to Asphalt Ridge. The LOI contemplates our issuance of 1,492,272 restricted shares of common stock and the payment of $850,000 at closing, subject to execution of definitive agreements. Upon signing the LOI, we made a non-refundable $150,000 payment to HSO in consideration for the option. The LOI requires evidence of a minimum sustained production rate of 40 barrels per day for a continuous 30-day period from two wells at Asphalt Ridge by May 15, 2026, or the LOI will expire unless extended by us. We are not under any obligation to enter into definitive agreements in connection with an acquisition.

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.

Market Opportunity

We believe that our newly established oil and gas operations in Canada strategically positions the Company to expand its operations into one of North America’s most promising heavy oil basins, with upside potential for long term production and reserve growth. Trio believes expanding operations into Canada offers economic development and low operational costs. Trio also believes that the market accessibility combined with a favorable regulatory process makes this area very attractive for continued and future development.

The oil and gas industry is operationally challenging in California, where we have the South Salinas Project, due primarily to regulatory issues and to efforts to facilitate an energy transition away from fossil fuels. TPET believes that given the size and future anticipated costs of exploration, it is best to seek out a joint venture partner who has the capacity to continue to operate in California with the expectation that the market for oil and gas in California will remain strong for the foreseeable future. Furthermore, TPET is attempting to launch a Carbon Capture and Storage Project as part of the South Salinas Project, consistent with efforts in California to reduce carbon footprint. The Company hopes and expects TPET’s commitment to reduce carbon footprint through a Carbon Capture and Storage Project to be viewed favorably by California regulatory bodies, perhaps helping to facilitate operations at the South Salinas Project and elsewhere.

The oil and gas industry currently appears operationally favorable in Utah, where we have the Asphalt Ridge asset and an option on the PR Spring project in the same Uintah basin. TPET believes that the overall operating environment and the market for oil and gas in Utah should remain favorable for the foreseeable future.

TPET’s operations may help meet the USA’s demanding oil and gas needs that are expected to remain strong for the foreseeable future, while supporting the country’s goal of energy independence, and supporting local and state economies with tax revenue and jobs.

Business Strategies

Our primary business strategies and objectives are to grow our recently acquired Canadian assets aggressively by acquiring projects that generate immediate cash flow and/or offer workover opportunities without committing huge resources to new exploratory drilling, or offer transformative growth potential with strategic investment in favorable political and economic environments such as our option on PR Spring in Uintah Basin, Utah. TPET’s current strategy and focus at the South Salinas Project is to seek out a joint venture partner with the knowledge and capacity to operate in California. We are also endeavoring to secure approval from CalGEM and WaterBoards of a proposed short-term water-disposal program that should significantly reduce lease operating costs, launching a Carbon Capture and Storage Project, pursuing permits for full field development, and similar matters. Efforts to obtain from Monterey County conditional use permits and a full field development permit for the South Salinas Project are progressing. Efforts to obtain from the California Geologic Energy Management Division (“CalGEM”) and from the California Water Boards a permit for a water disposal project at the South Salinas Project are also progressing. In the meantime, the Company recently determined that existing permits allow production testing to continue at the HV-3A discovery well at Presidents Field and, consequently, testing operations were restarted at this well on March 22, 2024. Oil production from this well has occurred and the Company has idled operations currently pending an assessment of the viability of increasing 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.

TPET’s current strategy and focus at the PR Spring project is to monitor the results of the new 2-4 and 8-4 wells at the Company’s Asphalt Ridge project. Once production attains 40 barrels per day for thirty days from both wells, TPET will be in a position to exercise its option on the 2000-acre project and enter into a Definitive development agreement.

TPET’s primary strategies and objectives are focused on growing the Company into a highly profitable, independent oil and gas company.

Our Growth Strategy

TPET’s goal is the building and growing of a substantial independent oil and gas company by acquiring projects that generate immediate cash flow as in our Canadian assets or offer transformative growth potential with strategic investment such as our option on P.R. Spring in Utah.

Competition

There are many large, medium, and small-sized oil and gas companies and third-parties that are our competitors. Many of these competitors have extensive operational histories, experienced oil and gas industry management, profitable operations, and significant reserves and funding resources. Our efforts to acquire additional oil/gas properties in California and elsewhere may be met with competition*.*

Government Regulation

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. These burdens include regulations relating to transportation of oil and gas, drilling and production and other regulatory matters.

Certain Recent Developments

Formation of a Canadian Wholly-Owned Subsidiary

On March 28, 2025, we formed Trio Petroleum Canada, Corp., an Alberta, Canada corporation and our wholly owned subsidiary (“Trio Canada”). Our Chief Executive Officer, Robin Ross, is also the Chief Executive Officer of Trio Canada and also serves as Secretary/Treasurer. Our Chief Financial Officer, Greg Overholtzer, is also the Chief Financial Officer of Trio Canada. Robin Ross also serves as the sole director of Trio Canada.

Loan to Trio Canada

As of April 4, 2025, we entered into a Loan and Note Purchase Agreement (the “Loan Agreement”) with Trio Canada, made a loan (the “Subsidiary Loan”) to Trio Canada, in the amount of US$1,131,000 (the “Loan Amount”), and Trio Canada issued to us a three-year promissory note, with a maturity date of April 4, 2028, in the principal amount of US$1,131,000 (the “Subsidiary Note”) evidencing the Loan Amount. The outstanding principal amount of the Subsidiary Note accrues interest at a rate of 12% per annum. As of October 31, 2025, the outstanding principal balance of the Subsidiary Note was US$430,335 and accrued but unpaid interest totaled US$27,606.

Under the terms of the Loan Agreement, the Loan Amount was used to pay the remaining cash amount payable to Novacor, in connection with the Novacor Acquisition, and the remainder of the Loan Amount is to be used for ongoing operating costs of Trio Canada.

Convertible Notes Financings

April 2025 Convertible Note Financing

On April 11, 2025, we issued an Unsecured Original Discount Convertible Promissory Note (the “April 2015 Note”) to an institutional investor (the “April 2025 Note Investor”) in a principal amount of $321,176, having an original issue discount of $48,176, resulting in a funding amount of $273,000. After the payment of a commission of $15,015 to Spartan Capital Securities, LLC and the payment of $10,000 to reimburse the April Note Investor for its legal fees, we received net proceeds of $247,985.

On April 17, 2025, we issued an amended and restated Unsecured Original Discount Convertible Promissory Note to the April 2025 Convertible Note Investor (the “April 2025 Amended and Restated Note”), in an aggregate principal amount, with the principal amount of the April 2025 Note, of $712,941, having an aggregate original issue discount of $106,941, including the original issue discount of the April 2025 Note, and resulting in an aggregate funding amount, with the April 2025 Note, of $606,000. We received additional net proceeds of $333,000.

The April 2025 Amended and Restated Note also contained “piggyback” registration rights and the shares issuable upon conversion of the April 2025 Amended and Restated Note were registered for resale in a registration statement declared effective by the SEC on May 22, 2025. As of October 31, 2025, the Amended and Restated Note has been fully converted by the April 2025 Note Investor into shares of common stock.

August 2025 Convertible Note Financing

On August 15, 2025, we closed a private placement (the “August 2025 Convertible Note Financing”) pursuant to which we issued the August 2025 Notes to three institutional investors (the “August 2025 Note Investors”) in an aggregate principal amount of $1,200,000 (the “August 2025 Notes Principal Amount”), having an aggregate original issue discount of $180,000, or 15%, resulting in an aggregate funding amount of $1,020,000 (the “August 2025 Notes Funding Amount”). After the payment of $71,400 to Ladenburg Thalman & Co. Inc, as an exclusive placement agent fee, and $20,000 to reimburse the lead Investor for its legal fees, net proceeds of the financing was $928,600.

We may prepay all or any portion of the August 2015 Notes at any time (without penalty or premium if prepaid on or before the maturity date of February 15, 2026). If, during the period the August 2025 Notes remain outstanding, the Company raises any type of equity-related financing, the August 2024 Note Investors have the right to request that an aggregate of up to 25% of the gross proceeds raised by us in any such financing be used to repay the outstanding amounts of the August 2025 Notes.

The August 2025 Note Investors may request conversion of the August 2025 Notes, at any time, into shares of common stock (the “Conversion Shares”). Additionally, we have the right to require the August 2025 Note Investors to convert their August 2025 Notes in the event that at such time, for each of the five (5) preceding trading days prior to such date (i) the daily volume weighted average price (“VWAP”) of our common stock on the NYSE American or any other principal securities exchange on which the common stock is then traded (the “Principal Exchange”) is greater than $0.85 (subject to adjustments for forward splits and reverse splits of the common stock and other similar recapitalizations, as well as such other adjustments as provided in the August 2025 Notes), (ii) all of the Conversion Shares have been registered for resale under an effective registration statement filed with the SEC, and (iii) the daily dollar trading volume for the common stock on the Principal Exchange exceeds $500,000 per trading day; provided, however, that the amount subject to such conversion, under any of the August 2025 Notes, shall not exceed twenty percent (20%) of the total dollar trading volume of the common stock during such 5-day period. Furthermore, any conversion may not result in the issuance of shares of common stock to an August 2025 Note Investor, which would cause such August 2025 Note Investor, along with its affiliates, to own more than 4.99% (9.99%, if elected by the Investor) of the Company’s then outstanding shares of common stock nor to exceed the maximum number of shares that such Investor may convert pursuant to its Note (the “Beneficial Ownership Limitation”).

The conversion price of the August 2025 Notes is equal to the lesser of (i) $1.32 and (ii) 90% of the lowest daily VWAP of the common stock on the Principal Exchange, during the five (5) trading days prior to the date of a notice of conversion (a “Conversion Notice”). Notwithstanding the foregoing, the Conversion Price shall not be less than a floor price of $0.72, subject to certain adjustments, as provided in the August 2025 Notes (the “Floor Price”). In the event that any August 2025 Note Investor desires to convert its August 2025 Note at a time when the applicable Conversion Price is less than the Floor Price, such Investor may request a reduction to the Floor Price to the then applicable Conversion Price, but, in any event, not less than $0.22, which is 20% of the closing price of $1.10 of the common stock on the Principal Exchange on the trading day immediately prior the original issuance date of the August 2025 Notes. Upon any such reduction in the Floor Price, the Floor price of the other August 2025 Notes shall be similarly reduced.

Notwithstanding any of the other terms of the August 2025 Notes, the maximum number of shares of common stock which may be issued upon the conversion of all of the August 2025 Notes is 1,679,127 shares (the “Maximum Number of Conversion Shares), which is equal to 19.99% of the 8,399,839 shares of the Company’s common stock issued and outstanding on the closing date of the private placement.

Under the terms of a Registration Rights Agreement entered into by us with each of the August 2025 Note Investors, we have agreed to register the Conversion Shares for resale in a registration statement. The Conversion Shares were registered for resale in a Registration Statement on Form S-3, which was declared effective by the SEC on September 11, 2025. As of October 31, 2025, a portion of the August 2025 Notes have been converted into an aggregate of 606,809 Conversion Shares and the aggregate outstanding balance of the August 2025 Notes was $467,179.

For additional information on the terms of the August 2025 Convertible Note Financing, see our Current Report on Form 8-K filed with the SEC on August 18, 2025, including the August 2025 Notes and Registration Rights Agreement filed as exhibits hereto.

Capital Land Services Acquisition

On August 20, 2025, the Company), through its wholly owned subsidiary Trio Canada, entered into an Asset Purchase Agreement (“APA”) with Capital Land Services Ltd. (“Capital Land”). Pursuant to the APA, Trio Canada agreed to acquire certain mineral leasehold interests and related rights located in the County of Vermilion of River, Alberta, Canada, together with associated contracts, permits, and registrations (collectively, the “Assets”). The total purchase price consists of CAD $150,000 in cash and the issuance of restricted shares of the Company’s common stock having an aggregate value of CAD $150,000.

On November 3, 2025, subsequent to the Company’s fiscal year ended October 31, 2025, the transactions contemplated under the APA were completed (the “Capital Land Acquisition”). At closing, Trio Canada paid Capital Land CAD $150,000 in cash and we issued 104,227 restricted shares of our common stock to Capital Land. In exchange, Trio Canada acquired the Assets, including certain wells that had been purchased out of receivership. Due to regulatory requirements of the Alberta Energy Regulator (“AER”), the Company arranged for all applicable licenses to be transferred to Novacor, an experienced operator with whom the Company has an existing commercial relationship. Novacor utilizes Capital Land as its AER agent. In consideration for Capital Land’s services as AER agent, the Company granted Capital Land a 1% gross overriding royalty with respect to the mineral rights, for as long as Capital Land continues to provide such services.

Asset Purchase Transaction with Novacor Exploration Ltd.

As of December 30, 2025, the Company entered into an Asset Purchase Agreement (the “December 2025 Novacor APA”) with Trio Canada, and Novacor, pursuant to which, subject to the terms and conditions set forth in the December 2025 Novacor APA, Trio Canada agreed to acquire certain assets of Novacor’s relating to Novacor’s oil and gas business, including certain contracts, leases and permits for working interests in petroleum and natural gas and mineral rights located in the Lloydminster, Saskatchewan heavy oil region in Canada (collectively, the “December 2025 Novacor Assets”), free and clear of any liens other than certain specified liabilities of Novacor that are being assumed (collectively, the “Liabilities” and such acquisition of the Assets and assumption of the Liabilities together, the “December 2025 Novacor Acquisition”) for a total purchase price of CAD $1,000,000 (US$730,300 based on the applicable exchange rate to U.S. Dollars). The Company issued to Seller 912,875 restricted shares of common stock of the Company, subject to certain registration rights (the “Purchase Price”).

The December 2025 Novacor Acquisition was closed on December 30, 2025, simultaneously with the execution by the Company, Trio Canada and Novacor of the December 2025 Novacor APA and other transaction documents (the “Closing”). At the Closing, title to the December 2025 Novacor Assets was delivered to the Trio Canada, and the Company, thereafter deliver the restricted shares to Novacor.

Following the Closing, (i) operating costs for the December 2025 Novacor Assets shall, for a period of two (2) years, be held at the levels detailed in the auditor’s report over the eighteen (18) month period prior to the Closing, prepared for Trio Canada on the basis of the due diligence materials provided by Novacor to Trio Canada in connection with the December 2025 Novacor Acquisition, unless mutually agreed otherwise; (ii) after such two-year period, operating costs shall remain competitive with other operators in the area; and (iii) Trio Canada shall be entitled to terminate Novacor’s post-Closing actions at any time on 30 days’ prior written notice to the Novacor. After the Closing, with respect to the December 2025 Novacor Assets, Novacor shall act as the on-site operator of the December 2025 Novacor Assets and perform all work and services as provided in the December 2025 Novacor APA.

On December 30, 2025, the Company and Novacor executed and entered into a Registration Rights Agreement with respect to the restricted shares (the “RRA”). Pursuant to the provisions of the RRA, Novacor is entitled to certain “piggyback” registration rights, with respect to the Registrable Securities (as such term is defined in the RRA), providing Novacor with the right to include the Registrable Securities in a registration statement filed by the Company for the registration of its securities and/or the resale of shares of Common Stock by other stockholders of the Company (a “Piggyback Registration Statement”), subject to certain limitations and restrictions. In the event that the Registrable Securities are not included in a Piggyback Registration Statement filed by the Company with the Securities and Exchange Commission (“SEC”) on or before March 31, 2026, the Company is obligated to file a registration statement on or before March 31, 2026, to register the resale of the Registrable Securities, subject to certain limitations and restrictions. The Company has agreed to pay all fees relating to the registration of the Registrable Securities, except any broker or similar commissions payable by a holder of Registrable Securities.

For additional information on the terms of the Asset Purchase Transaction with Novacor, see our Current Report on Form 8-K filed with the SEC on January 5, 2026, including the APA and RRA filed as exhibits hereto.

Ladenburg ATM Agreement

On January 9, 2026, we entered into an At Market Issuance Sales Agreement (the “ATM Agreement”) with Ladenburg Thalmann & Co. Inc. (“Ladenburg”) as agent, pursuant to which the Company may issue and sell shares of our common stock from time to time through Ladenburg (the “ATM Offering”). On January 9, 2026, the Company also filed a prospectus supplement with the SEC covering the sale of shares of common stock having an aggregate offering price of up to $3,600,000 (the “Placement Shares”), in connection with the ATM Offering. Upon delivery of a Placement Notice (as such term is defined in the ATM Agreement) and subject to the terms and conditions of the ATM Agreement, Ladenburg shall use its commercially reasonable efforts to sell the Placement Shares by (i) any method permitted by law deemed to be an “at the market offering” as defined in Rule 415(a)(4) promulgated under the Securities Act of 1933, as amended (the “Securities Act”), including sales made directly on or through the NYSE American or on any other existing trading market for the common stock and/or (ii) any other method permitted by law with the Company’s consent. The ATM Agreement provides that Ladenburg will be entitled to aggregate compensation for its services up to 3.0% of the gross proceeds from each sale of Placement Shares sold through Ladenburg under the ATM Agreement.

For additional information on the terms of the ATM Agreement with Ladenburg, see our Current Report on Form 8-K filed with the SEC on January 9, 2026, including the ATM Agreement filed as an exhibit hereto.

South Salinas Project

Oil Rights and Ownership

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

Description of South Salinas Property and Current Operations

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

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

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

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

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

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

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

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

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

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. When appropriate funding is in place, the Company will evaluate 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 2026, 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 2026. 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 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.

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. On page 25 of the Reserve Report in the Society of Petroleum Engineers’ Petroleum Resource Management System (PRMS Section 4.1.1), use of analogs is described as “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.” While the use of analogs for the South Salinas Project were consistent with the PRMS guidelines, the Reserve Report cover letter emphasized “The reserves 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 S-K.” And, specifically, in 210.4-10(a)(2) “Analogous reservoirs have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) same environment of deposition; (iii) similar geological structure; and (iv) same drive mechanism.”

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 assumed that by September 2025 Trio should be experiencing the timely approval of drilling permits from CALGEM which have been delayed. Of the 12 Phase 2 wells, four wells will target the Yellow Zone, seven are planned for the Blue Zone, and one well is a horizontal well in the Vaqueros Zone. The capital requirement for Phase 2 well work and facilities expansion is estimated to be $43.2 million.

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

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

Table 1: Estimated Undeveloped Reserves and Cash Flow

ESTIMATED UNDEVELOPED RESERVES AND CASH FLOW

Reasonable Expectations of Reserve Analyses

This Annual Report provides a summary of risks and detailed discussions of risks relating to our business. The Company recognizes these risks as being real and substantial. Nevertheless, the Company has reasonable expectations that the Company’s South Salinas Project will prove to have reserves approximately as estimated 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. See “Item 1A. Risk Factors -Risks Relating to Our Business -We may face delays and/or obstacles in project development due to difficulties in obtaining necessary permits from federal, state, county and/or local agencies, which may materially affect our business;” “Item 1A. Risk Factors -Risks Relating to Our Business - We face substantial uncertainties in estimating the characteristics of our assets, so you should not place undue reliance on any of our measures;” “Item 1A. Risk Factors -Risks Relating to Our Business - The drilling of wells is speculative, often involving significant costs that may be more than our estimates, and drilling may not result in any discoveries or additions to our future production or future reserves, or it may result in disproving or diminishing our current reserves.; “Item 1A. Risk Factors -Risks Relating to Our Business - Seismic studies do not guarantee that oil or gas is present or, if present, will produce in economic quantities; and “Item 1A. Risk Factors -Risks Relating to Our Business - We are subject to numerous risks inherent to the exploration and production of oil and natural gas.”

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

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

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

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

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

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

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

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

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

The Company’s expectation that it will have adequate funding to develop the reserves at the South Salinas Project is based on anticipated proceeds from additional capital raises and anticipated operating revenues:

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

Employees

As of December 31, 2025, we had one employee, who is located in Canada.

Subsidiaries

Our only subsidiary is Trio Petroleum Canada, Corp., an Alberta, Canada corporation. Our Chief Executive Officer, Robin Ross, is also the Chief Executive Officer of Trio Canada and also serves as Secretary/Treasurer. Our Chief Financial Officer, Greg Overholtzer, is also the Chief Financial Officer of Trio Canada. Robin Ross also serves as the sole director of Trio Canada.

Implications of Being an Emerging Growth Company and a Smaller Reporting Company

We qualify as an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As an “emerging growth company” we may take advantage of reduced reporting requirements that are otherwise applicable to public companies. These provisions include, but are not limited to: