Touchstone Exploration Inc. (TSX, LON:TXP) has announced 2025 year-end reserves. Touchstone’s independent reserves evaluation was prepared by GLJ Ltd. with an effective date of December 31, 2025. Highlights of our total proved developed producing, total proved (1P), and total proved plus probable (2P) reserves from the Reserves Report are provided below. Unless otherwise stated, all financial amounts referenced herein are stated in United States dollars. Readers are further cautioned to read the applicable advisories contained herein.
Paul Baay, Touchstone Exploration President and Chief Executive Officer, commented:
“Our year-end reserves report highlights the strategic integration of the Central block into our producing reserve base, establishing a new pillar for LNG-linked growth alongside our stable oil production and Ortoire natural gas assets. This year’s report also reflects the expansion of our gas marketing portfolio, underpinned by fixed-price sales at Ortoire and high-value LNG contracts tied to Central block production.
While data from the Cascadura-5 well necessitated a downward revision to our Block B reserves, Block A remains on forecast and continues to represent a significant opportunity for production growth, particularly as natural gas pricing is subject to redetermined in October 2027.
This independent evaluation underscores the substantial value of our Trinidadian portfolio. The NPV10 of future net revenues for our 2P reserves was estimated at approximately $653 million before tax and approximately $315 million after tax, which represented a 2 percent increase over 2024 despite our 2025 production.
Furthermore, the addition of medium-gravity oil reserves from Cascadura-5 reinforces the potential of our emerging Herrera play. Through low-cost recompletion opportunities, we are well-positioned to efficiently enhance our production base by tapping lower-zone oil within our Block B assets.
Looking ahead, we remain focused on execution. We look forward to tying in Carapal Ridge-3 for production in late March 2026, commencing our legacy oil block drilling program in March, and commissioning the Cascadura compressor in the second quarter of 2026.“
2025 Operational Highlights
· Transformational acquisition: Closed and integrated the acquisition of a 65 percent working interest in the Central block, successfully adding base LNG production and significant reserves to the Company’s portfolio.
· Facility optimization: Implemented operational enhancements at the Central block natural gas processing plant, driving an approximate 20 percent production increase over acquired levels.
· Cascadura-4 drilling: While the well successfully encountered hydrocarbon-bearing zones, the drill string became irretrievably stuck during operations. Following an assessment of potential completion options, the Company has determined that the ability to safely and reliably produce from the current wellbore is unlikely.
· Cascadura-5 drilling: Drilled and brought onstream the first Block B well to produce both natural gas and medium-gravity crude oil, diversifying the Cascadura production stream. The well contributed a field estimated gross average sales of approximately 1.9 MMcf/d of natural gas and 46 bbls/d of medium crude oil (approximately 362 boe/d) in December 2025.
· Carapal Ridge-3 drilling: Drilled the first new well in the Central block in over 17 years, encountering approximately 1,000 feet of net Herrera sand pay.
– Post-year-end progress: Successfully completed the well in the Herrera formation. Following perforation, cleanup operations recovered natural gas and associated liquids, confirming hydrocarbon presence. The well is currently shut-in and is scheduled to be tied into the Central block facility for production in late March 2026.
· Base oil stability: Maintained consistent performance across the CO-1, WD-4, and WD-8 blocks through a disciplined program of optimizations and workovers, ensuring a stable production foundation throughout 2025.
– Post-year-end progress: In December 2025, the Company completed the sale of the non-core Fyzabad property in exchange for three turnkey drilling wells on the WD-8 and WD-4 blocks. A drilling rig is currently mobilizing to WD-8 to commence the first of a four well campaign, with spudding anticipated in early March 2026.
· Production: Achieved 2025 annual average net production of 4,686 boe/d, with fourth quarter performance climbing to 4,877 boe/d following the startup of Cascadura-5 and Central block optimizations.
Year-end 2025 Reserves Overview
Touchstone’s year-end reserves reflect the strategic addition of natural gas and NGL reserves from the Central block acquisition, alongside a technical revision to Block B at Cascadura. The Cascadura subsurface model has evolved with each development well, providing a foundation for full-field development. The Cascadura compressor is targeted for commissioning in the second quarter of 2026, which is expected to provide a stable production profile to enhance future forecasting and well-deliverability modeling. With an established pipeline network and infrastructure in place, the Company is positioned for efficient and cost-effective future development.
· Reserves changes: Relative to year-end 2024 and after accounting for 2025 production, gross PDP reserves increased by 45 percent to 9,933 Mboe. Gross 1P reserves declined by 5 percent to 27,559 Mboe, and gross 2P reserves decreased by 1 percent to 49,558 Mboe.
· Asset base evolution: The increase in year-end 2025 PDP reserves reflect the acquisition of the Central block and the addition of Cascadura-5 to the producing base, partially offset by the disposition of the Fyzabad block.
· Technical revisions: Changes to 1P and 2P reserves reflect technical revisions to natural gas and NGL reserves at Cascadura Block B and the Fyzabad disposition, offset by the Central block acquisition and positive technical revisions to crude oil reserves at CO-1, WD-4, and WD-8.
· Before tax value: The before-tax NPV10 of future net revenues increased 35 percent year-over-year to $107 million for PDP. Before-tax NPV10 for 1P reserves was $336 million (down 5 percent from 2024) and $653 million for 2P reserves (down 3 percent from 2024).
· After tax Value: Realized after-tax PDP NPV10 reached $89 million, a 34 percent increase from the prior year. After-tax 1P and 2P NPV10 increased by 2 percent compared to 2024 levels.
· Extensive reserve life: The Company maintains a robust reserve life index of 13.3 years (1P) and 23.2 years (2P), highlighting the long-term sustainability of the asset portfolio.
2025 Year-end Reserves Report Summary
Touchstone’s year-end light and medium crude oil, conventional natural gas and NGL reserves in Trinidad were evaluated by independent reserves evaluator, GLJ, in accordance with definitions, standards, and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).
The reserve estimates set forth below are based upon GLJ’s Reserves Report dated February 24, 2026, with an effective date of December 31, 2025. The Reserves Report uses the average price and inflation forecasts of three independent evaluation consultants (GLJ, McDaniel & Associates Consultants Ltd., and Sproule Associates Ltd. (collectively, the “Consultants”)). All values in this announcement are based on the three Consultants’ average forecast pricing and GLJ’s estimates of future operating and capital costs as of December 31, 2025. Additional reserves information as required under NI 51-101 will be included in the Company’s Annual Information Form, which will be filed on SEDAR+ (www.sedarplus.ca) on or before March 31, 2026. Please refer to “Advisories: Reserves Disclosure” for further information. In certain tables set forth below, the columns may not add due to rounding.
2025 Reserves Summary by Category
| PDP | 1P | 2P | |
| Total gross reserves(1) (Mboe) | 9,933 | 27,559 | 49,558 |
| Reserve additions(2) (Mboe) | 4,882 | 275 | 1,281 |
| NPV10 before income tax(3) ($000’s) | 107,295 | 335,710 | 652,516 |
| NPV10 after income tax(3) ($000’s) | 89,142 | 183,103 | 314,844 |
Notes:
(1) Gross reserves are the Company’s working interest share before deduction of royalty obligations.
(2) Reserve additions exclude 2025 annual production and include the effect of 2025 acquisitions and dispositions. See “Advisories: Oil and Gas Metrics“.
(3) Based on the Consultants’ average December 31, 2025 forecast prices and costs. See “Forecast Prices and Costs” herein.
Summary of Crude Oil and Natural Gas Reserves by Product Type
| Company Gross(1) Reserves | Light and Medium Crude Oil (Mbbl) | Conventional Natural Gas (MMcf) | Natural Gas Liquids (Mbbl)(2) | Total Oil Equivalent (Mboe) |
| Proved | ||||
| Developed producing | 3,274 | 35,240 | 785 | 9,933 |
| Developed non-producing | 1,332 | 7,493 | 251 | 2,832 |
| Undeveloped | 4,544 | 59,718 | 297 | 14,795 |
| Total Proved | 9,151 | 102,451 | 1,333 | 27,559 |
| Probable | 8,960 | 76,036 | 367 | 21,999 |
| Total Proved plus Probable | 18,111 | 178,486 | 1,700 | 49,558 |
| Company Net(3) Reserves | Light and Medium Crude Oil (Mbbl) | Conventional Natural Gas (MMcf) | Natural Gas Liquids (Mbbl)(2) | Total Oil Equivalent (Mboe) |
| Proved | ||||
| Developed producing | 1,944 | 30,624 | 687 | 7,735 |
| Developed non-producing | 900 | 6,517 | 220 | 2,206 |
| Undeveloped | 3,392 | 51,890 | 260 | 12,300 |
| Total Proved | 6,236 | 89,031 | 1,166 | 22,241 |
| Probable | 6,805 | 66,091 | 321 | 18,141 |
| Total Proved plus Probable | 13,041 | 155,122 | 1,487 | 40,382 |
Notes:
(1) Gross reserves are the Company’s working interest share before deduction of royalty obligations.
(2) NGLs including field condensate.
(3) Net reserves are the Company’s working interest share after the deduction of royalty obligations.
Summary of Net Present Values of Future Net Revenues
| Net Present Values Before Income Taxes(1) ($000’s) | Undiscounted | Discounted at 5% | Discounted at 10% | Discounted at 15% | Discounted at 20% |
| Proved | |||||
| Developed producing | 156,204 | 126,758 | 107,295 | 93,202 | 82,459 |
| Developed non-producing | 77,615 | 60,539 | 49,826 | 42,321 | 36,719 |
| Undeveloped | 290,765 | 225,246 | 178,588 | 144,311 | 118,450 |
| Total Proved | 524,584 | 412,543 | 335,710 | 279,834 | 237,627 |
| Probable | 584,583 | 419,085 | 316,806 | 247,878 | 198,922 |
| Total Proved plus Probable | 1,109,167 | 831,628 | 652,516 | 527,712 | 436,550 |
| Net Present Values After Income Taxes(1)(2) ($000’s) | Undiscounted | Discounted at 5% | Discounted at 10% | Discounted at 15% | Discounted at 20% |
| Proved | |||||
| Developed producing | 116,217 | 101,364 | 89,142 | 79,350 | 71,433 |
| Developed non-producing | 32,884 | 27,699 | 24,232 | 21,674 | 19,661 |
| Undeveloped | 123,263 | 92,008 | 69,729 | 53,515 | 41,476 |
| Total Proved | 272,364 | 221,071 | 183,103 | 154,539 | 132,570 |
| Probable | 242,575 | 175,757 | 131,742 | 101,492 | 79,928 |
| Total Proved plus Probable | 514,939 | 396,829 | 314,844 | 256,031 | 212,498 |
Notes:
(1) Based on the Consultants’ average December 31, 2025 forecast prices and costs. See “Forecast Prices and Costs” herein.
(2) The after-tax net present values prepared by GLJ in the evaluation of the Company’s petroleum and natural gas assets presented herein are calculated by considering current Trinidad tax regulations and are based on the Company’s estimated tax pools and non-capital losses as of December 31, 2025. The values reflect the expected income tax burden on the assets on a consolidated basis. Values do not represent an estimate of the value at the business entity level or consider tax planning, which may be significantly different. See “Advisories: Unaudited Financial Information“.
Reconciliation of Gross Reserves by Product Type
The following table sets forth a reconciliation of the Company’s total gross proved, probable, and proved plus probable reserves by product type as of December 31, 2025, against such reserves as at December 31, 2024. The reconciliation is based on forecast price and cost assumptions.
| Reserves Category and Factors | Light and Medium Crude Oil (Mbbl) | Heavy Crude Oil(Mbbl) | Conventional Natural Gas (MMcf) | Natural Gas Liquids (Mbbl)(1) | Total Oil Equivalent (Mboe) |
| Total Proved | |||||
| December 31, 2024(2) | 9,360 | 276 | 113,377 | 537 | 29,070 |
| Extensions and improved recovery(3) | 191 | – | – | – | 191 |
| Technical revisions(4) | (8) | – | (34,909) | (180) | (6,006) |
| Acquisitions(5) | – | – | 31,647 | 1,086 | 6,361 |
| Dispositions(5) | – | (258) | – | – | (258) |
| Economic factors(6) | (12) | – | – | – | (12) |
| Production | (379) | (18) | (7,664) | (111) | (1,785) |
| December 31, 2025 | 9,151 | – | 102,451 | 1,333 | 27,559 |
| Total Probable | |||||
| December 31, 2024(2) | 8,889 | 56 | 70,750 | 257 | 20,993 |
| Extensions and improved recovery(3) | 210 | – | – | – | 210 |
| Technical revisions(4) | (123) | – | 1,752 | (13) | 156 |
| Acquisitions(5) | – | – | 3,534 | 123 | 712 |
| Dispositions(5) | – | (56) | – | – | (56) |
| Economic factors(6) | (15) | – | – | – | (15) |
| December 31, 2025 | 8,960 | – | 76,036 | 367 | 21,999 |
| Total Proved plus Probable | |||||
| December 31, 2024(2) | 18,249 | 332 | 184,127 | 794 | 50,063 |
| Extensions and improved recovery(3) | 400 | – | – | – | 400 |
| Technical revisions(4) | (132) | – | (33,157) | (193) | (5,851) |
| Acquisitions(5) | – | – | 35,181 | 1,210 | 7,073 |
| Dispositions(5) | – | (314) | – | – | (314) |
| Economic factors(5) | (27) | – | – | – | (27) |
| Production | (379) | (18) | (7,664) | (111) | (1,785) |
| December 31, 2025 | 18,111 | – | 178,486 | 1,700 | 49,558 |
Notes:
(1) NGLs including field condensate.
(2) Prior year reserve estimates per GLJ’s independent reserves evaluation dated March 5, 2025, with an effective date of December 31, 2024.
(3) Reserve amounts for Infill Drilling, Extensions and Improved Recovery are combined and reported as “Extensions and improved recovery”.
(4) Technical revisions include all changes in reserves due to well performance and previously booked wells which were drilled in the year.
(5) Touchstone acquired its interest in the Central block effective May 16, 2025, and disposed of its interest in the Fyzabad block effective Dec. 1, 2025.
(6) Economic factors are the change in reserves exclusively due to changes in pricing.
As of December 31, 2025, gross proved plus probable reserves were 49,558 Mboe, representing a slight decrease of 505 Mboe or 1 percent from the prior year.
· Light and medium crude oil: proved plus probable reserves decreased by 138 Mbbl from 2024. This was primarily driven by 2025 annual production and negative technical revisions at Balata East. These decreases were partially offset by positive technical revisions and extensions at WD-4, WD-8, and CO-1, as well as geological refinements in the Cascadura Block B oil zone.
· Heavy crude oil: proved plus probable reserves reduced by 332 Mbbl from the prior year following the disposition of the Fyzabad property and related 2025 production.
· Conventional natural gas: proved plus probable reserves decreased by 5,641 MMcf from 2024. Significant negative technical revisions at Cascadura Block B and annual production were the primary drivers, though largely offset by the strategic acquisition of the Central block.
· Natural gas liquids: proved plus probable reserves increased by 906 Mbbl (approximately 114 percent) from the prior year, almost entirely attributed to the Central Block acquisition, which outweighed performance-related technical revisions at Cascadura.
Future Development Costs
The following table provides information regarding the future development costs (“FDC”) deducted in the estimation of the Company’s future net revenue using forecast prices and costs as included in the Reserves Report.
| Year ($000’s) | 1P | 2P | |
| 2026 | 10,558 | 14,868 | |
| 2027 | 26,093 | 33,436 | |
| 2028 | 34,195 | 56,904 | |
| 2029 | 32,461 | 69,673 | |
| 2030 | 11,372 | 27,205 | |
| Thereafter | – | – | |
| Total undiscounted | 114,680 | 202,086 | |
| Total discounted at 10% per year | 90,953 | 156,708 |
The following table sets forth the changes in undiscounted FDC included in the Reserves Report against such costs in the December 31, 2024, reserves report prepared by GLJ dated March 5, 2025.
| ($000’s unless otherwise stated) | 1P | 2P | |
| Increase in forecasted well costs | 5,618 | 9,243 | |
| Decrease in forecasted well locations | (13,611) | (8,616) | |
| Decrease in forecasted facility and pipeline costs | (1,586) | (1,586) | |
| Total decrease in FDC from 2024 | (9,579) | (959) | |
| Total decrease in FDC from 2024 (%) | (8) | (0) |
Forecast Pricing and Costs
Forecast pricing and costs are prices and costs that are generally acceptable, in the opinion of GLJ, as being a reasonable outlook of the future as of the evaluation effective date. The forecast cost assumptions consider inflation with respect to future operating and capital costs.
The following table sets forth the benchmark reference commodity prices and inflation rates reflected in the Reserves Data as of December 31, 2025. These price assumptions were provided to the Company by GLJ and represented the average price forecast of the Consultants as of the date of the Reserves Report.
| Forecast Year | Brent Crude Oil(1)($/bbl) | Henry Hub Natural Gas(1)($/MMBtu) | NBP Natural Gas($/MMBtu) | JKM Natural Gas($/MMBtu) | Inflation Rate(% per year) |
| 2026 | 63.92 | 3.74 | 10.00 | 9.20 | – |
| 2027 | 69.13 | 3.78 | 9.74 | 9.70 | 2.0 |
| 2028 | 74.36 | 3.85 | 9.97 | 10.40 | 2.0 |
| 2029 | 76.10 | 3.93 | 10.27 | 11.08 | 2.0 |
| 2030 | 77.62 | 4.01 | 10.47 | 11.30 | 2.0 |
| 2031 | 79.17 | 4.09 | 10.68 | 11.53 | 2.0 |
| 2032 | 80.76 | 4.17 | 10.89 | 11.76 | 2.0 |
| 2033 | 82.37 | 4.26 | 11.11 | 11.99 | 2.0 |
| 2034 | 84.01 | 4.34 | 11.34 | 12.23 | 2.0 |
| 2035 | 85.70 | 4.43 | 11.56 | 12.49 | 2.0 |
| Thereafter | +2.0% / year | +2.0% / year | +2.0% / year | +2.0% / year | 2.0 |
Note:
(1) This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer. Product sales prices will reflect these reference prices with further adjustments for specific marketing arrangements, quality differentials, heat content and transportation to point of sale.
