2023 Year-End Oil Reserves

2P estimated ultimate recovery now over 117 million barrels

1P and 2P reserves replacement ratios of 150% and 167%, respectively

1P and 2P reserve increases of 6% and 4%, respectively

2P reserve life of 19 years

2P after tax NPV-10 value increased 9% since year-end 2022 to more than USD$1.6 billion

Calgary, AB and Houston, TX - February 12, 2024-PetroTal Corp. ("PetroTal" or the "Company") (TSX: TAL, AIM: PTAL and OTCQX: PTALF) is pleased to announce the results of its 2023 year-end reserve evaluation (the "NSAI Report") by Netherland, Sewell & Associates, Inc. ("NSAI") for the Bretana oil field, operated 100% by PetroTal. All currency amounts are in United States dollars (unless otherwise stated) and comparisons refer to equivalent information as at December 31, 2022. All figures subject to rounding differences.

Highlights:

• For 1P and 2P (each as defined below) categories respectively, increases of 13% and 9% to Net Present Value (discounted at 10% after tax ("NPV-10 AT")), and per share values to US$0.97/share (CAD$1.29/share) and US$1.80/share (CAD$2.39/share);
• Increases in reserve categories:

• Strong results for various key year-end 2023 reserve-based metrics:

o 2023 reserves life index for 1P and 2P reserves, is approximately 9 and 19 years, respectively, using the average 2023 production run rate of 14,248 barrels ("bbls") of oil per day ("bopd");

o Robust 2023 production reserves replacement ratios of 150% and 167% for 1P and 2P reserves, respectively;

o Original Oil in Place ("OOIP") largely flat from 2022 levels. Now at 326, 442, and 595 million bbls ("mmbbls"), respectively, for the 1P, 2P and 3P cases;

o Increased 1P and 2P total booked well counts in 2023 by 2 and 3 wells, to 23 and 32 wells, respectively. Total 3P well count remains at 36; and,

o 2P recovery factor continued to increase in 2023 to 26% (from 24% at year-end 2022).

• 2023 Proved Developed Producing ("PDP") reserves increased 18% to 29 mmbbls, representing 60% of 1P reserves, reflecting an attractive ratio of base production to low risk drilling proved undeveloped ("PUD") targets;
• 2P Future Development Capital ("FDC") increased 36% to $551 million from year-end 2022 reflecting an additional 3 wells booked at year-end 2023, erosion control costs, and associated water disposal capacity and facilities needed to accommodate anticipated flush and run rate production volumes; and,
• For the first time since the Company's inception, operating costs, in the current 2023 year ended reserve report do not include any diluent, reflecting the Company's commercial efforts to find new ways to reduce operating costs.

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Manuel Pablo Zuniga-Pflucker, President and Chief Executive Officer, commented:

"The PetroTal team is committed to increasing value for all stakeholders from Bretana's oil recovery enhancement. It is noteworthy that our market capitalization is currently at a discount to our PDP after tax NPV-10 valuation even as the Company continues to make significant shareholder distributions and remains debt free.

Reserves attributed to the Bretana oil field have grown tremendously since 2017. Our drilling success combined with the field's strong natural aquifer support that allows for recovery factors beyond 30% has underpinned a world class oil operation that is expected to deliver material free cash flow for the next 20 years. The field's 2P and 3P reserves of 100 and 200 million barrels, respectively, will be extracted with one of the smallest operational footprints in the world, sustainable for years to come."

2023 Year-end Reserves Summary

The summary below sets forth PetroTal's reserves as at December 31, 2023, as presented in the reserves report prepared by NSAI, an independent qualified reserves evaluator. The figures in the following tables have been prepared in accordance with the standards contained in the most recent publication of the Canadian Oil and Gas Evaluation Handbook (the "COGEH") and the reserve definitions contained in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). In addition to the summary information disclosed in this announcement, more detailed information will be included in PetroTal's annual information form for the year ended December 31, 2023 (the "AIF") to be filed on SEDAR+ (www.sedarplus.ca) and posted on PetroTal's website (www.petrotal-corp.com) in March 2024.

Five Year Crude Oil Price Forecast - NSAI Report

The oil price projections used by NSAI are based upon an average of December 31, 2023 and 2022 forecasts of Brent Crude futures prices prepared by three qualified reserves evaluators: GLJ Petroleum Consultants Ltd., McDaniel & Associates Consultants Ltd. and Sproule Associates Limited. The five year average for the NSAI Report reflects an average Brent oil price of $80.55, which as at the time of this press release, is approximately $2/bbl higher than current market Brent prices.

Year-End Crude Oil Reserves (mmbbls)

Represents gross and net bbls since PetroTal has a 100% working interest and a 100% net revenue interest in these properties. Royalties are paid from sales proceeds.

Year-End Net Present Value at 10% - Before Tax ($ millions)

Year-End Net Present Value at 10% - After Tax ($ millions)

• Royalties include the 2.5% social fund for all years.
• Future Development Capital ("FDC") includes abandonment.
• Net Revenue is defined as revenue less royalties less operating costs less FDC.
• B-tax and A-tax refer to before and after tax.
• Discounted values are discounted at 10%.

Year-End Reserves Value per Share - After tax

Represents NPV-10 (after tax) divided by the number of common shares issued as of December 31 of each respective year and excludes other balance sheet items at the relevant date. Canadian and GBP share prices are converted at the respective year end foreign exchange conversion rates. Common shares issued at December 31, 2023 total 912.3 million shares and at December 31, 2022 total 862.2 million shares.

Reserve Life Index(1-3)

• 2023 values based on 2023 year-end reserves divided by average 2023 production of 14,248 bopd.
• The license for Block 95 expires in 2041.
• 2022 values based on 2022 year-end reserves divided by average 2022 production of 12,200 bopd.

Future Development Costs

The following information sets forth development and abandonment costs deducted in the estimation of PetroTal's future net revenue attributable to the reserve categories noted below:

The future development and abandonment costs are estimates of the future capital expenditures required to convert the corresponding reserves to PDP reserves. Future development per bbl is determined using the future development capital divided by the 1P, 2P, or 3P reserves, less cumulative PDP.

2023 Year-End Gross Reserves Reconciliation (mmbbls)

Well 16H and Corporate Production Update

January 2024 average production was 20,450 bopd with an associated Brent price of $80/bbl, ahead of Company guidance on a production and revenue basis.

Well 16H continues to produce at above expected level rates with a 26 day production average of approximately 4,850 bopd as at February 11, 2024 and an estimated investment payback in Q2 2024.

Douglas Urch

Executive Vice President and Chief Financial Officer

Manolo Zuniga

President and Chief Executive Officer

Mzuniga@PetroTal-Corp.comT: (713) 609-9101

PetroTal Investor Relations

Celicourt Communications

Mark Antelme / Jimmy Lea

Strand Hanson Limited (Nominated & Financial Adviser)

Ritchie Balmer / James Spinney / Robert Collins

Stifel Nicolaus Europe Limited (Joint Broker)

Callum Stewart / Simon Mensley / Ashton Clanfield

Peel Hunt LLP (Joint Broker)

Richard Crichton / Bhavesh Patel / Georgia Langoulant

READER ADVISORIES

SHORT-TERM RESULTS: References in this press release to peak production rates, current production rates, average 30-day production rates and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for PetroTal. The Company cautions that such results should be considered to be preliminary.

OIL REFERENCES: All references to "oil" or "crude oil" production, revenue or sales in this press release mean "heavy crude oil" as defined in NI 51-101. All references to Brent indicate Intercontinental Exchange Brent. Recovery factor percentages include historical production.

RESERVES DISCLOSURE: PetroTal's Statement of Reserves Data and Other Oil and Gas Information on Form 51-101F1 dated effective as at December 31, 2023, which will include further disclosure of PetroTal's oil and gas reserves and other oil and gas information in accordance with NI 51-101 and COGEH forming the basis of this press release, will be included in the AIF, which will be available on SEDAR+ at www.sedarplus.ca in March 2024. All reserves values, future net revenue and ancillary information contained in this press release are derived from the NSAI Report unless otherwise noted. Estimates of reserves and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves and future net revenue for all properties, due to the effect of aggregation. There is no assurance that the forecast price and cost assumptions applied by NSAI in evaluating PetroTal's reserves will be attained and variances could be material. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. The recovery and reserve estimates of PetroTal's oil reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual oil reserves may be greater than or less than the estimates provided herein. There are numerous uncertainties inherent in estimating quantities of crude oil, reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth herein are estimates only. Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Proved developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. Possible reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned. Certain terms used in this press release but not defined are defined in NI 51-101, CSA Staff Notice 51-324 - Revised Glossary to NI 51-101, Revised Glossary to NI 51-101, Standards of Disclosure for Oil and Gas Activities ("CSA Staff Notice 51-324") and/or the COGEH and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101, CSA Staff Notice 51-324 and the COGEH, as the case may be.

OIL AND GAS MEASURES: This press release contains metrics commonly used in the oil and natural gas industry which have been prepared by management, such as "OOIP", "development capital", "F&D costs", "net asset value" and "reserves life index". These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. "OOIP" is equivalent to total petroleum initially-in-place ("TPIIP"). TPIIP, as defined in the COGEH, is that quantity of petroleum that is estimated to exist in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. A portion of the TPIIP is considered undiscovered and there is no certainty that any portion of such undiscovered resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of such undiscovered resources. With respect to the portion of the TPIIP that is considered discovered resources, there is no certainty that it will be commercially viable to produce any portion of such discovered resources. A significant portion of the estimated volumes of TPIIP will never be recovered. "Development capital" means the aggregate exploration and development costs incurred in the financial year on reserves that are categorized as development. Development capital excludes capitalized administration costs. "Finding and development costs" or "F&D costs" are calculated as the sum of field capital plus the change in future development costs for the period divided by the change in reserves that are characterized as development for the period. Finding and development costs take into account reserves revisions during the year on a per bbl basis. The aggregate of the exploration and development costs incurred in the financial year and changes during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. "Net asset value" is based on present value of future net revenues discounted at 10% before tax on reserves, net of estimated net debt at year end divided by the basic shares outstanding at year end. "Reserve life index" is calculated as total Company interest reserves divided by annual production. These terms have been calculated by management and do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare PetroTal's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes.

FOFI DISCLOSURE: This press release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about NPV-10, future development and abandonment costs and the components thereof, prospective results of operations, production and production capacity, free cash flow, revenue, forecast revenues and costs and the components thereof, five year crude oil Price forecast, shareholder returns (including that shareholders of PetroTal will continue to receive a significant quarterly dividend), and tax rates, all of which are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraphs. FOFI contained in this press release was approved by management as of the date of this press release and was included for the purpose of providing further information about PetroTal's anticipated future business operations. PetroTal disclaims any intention or obligation to update or revise any FOFI contained in this press release, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this press release should not be used for purposes other than for which it is disclosed herein. All FOFI contained in this press release complies with the requirements of Canadian securities legislation, including NI 51-101. Changes in forecast commodity prices, differences in the timing of capital expenditures, and variances in average production estimates can have a significant impact on the key performance measures included in PetroTal's guidance. The Company's actual results may differ materially from these estimates.

Neither the TSX Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Exchange) accepts responsibility for the adequacy or accuracy of this press release.