Gran Tierra Energy Inc. Reports Seventh Consecutive Year of South American Reserves Growth

2026-01-29

NYSE - New York Stock Exchange · Oil · Natural Gas · Natural Gas Liquids · Canada

Seventh Consecutive Year of South American Reserves Growth With Over 100% Reserve Replacement PDP and 2P _World Class Resource Base Captured Including 2P Reserves of __258__MMBOE_ _1P and 2P Reserve Life Index of __8__and __15__Years, Respectively_ _Net Present Value Before Tax Discounted at 10% of __$1.5__Billion (1P), __$2.5__Billion (2P), and __$3.3__Billion (3P)_ _Net Asset Value per Share of __$22.63__Before Tax and __$13.62__After Tax (1P), and __$51.09__Before Tax and __$31.19__After Tax (2P)_ _Unrisked 2C Resources of __74__MMBOE (Glauconitic) and __118__MMBOE Unrisked Mean Prospective Resources (Colombia and Ecuador)__1_ _Significant Unbooked Upside Potential Canadian Long-Term Gas__1_

CALGARY, Alberta, Jan. 28, 2026 (GLOBE NEWSWIRE) -- Gran Tierra Energy Inc. (“Gran Tierra”or the “Company”) (NYSE American:GTE)(TSX:GTE)(LSE:GTE), an independent international energy company focused on oil and natural gas exploration and production in Canada, Colombia and Ecuador, today announced the Company’s 2025 year-end reserves and specified resources as evaluated by the Company’s independent qualified reserves evaluator McDaniel & Associates Consultants Ltd. (“McDaniel”) in separate reports each with an effective date of December 31, 2025. See “Disclosure of Oil and Gas Information” for more information.

All dollar amounts are in United States (“U.S.”) dollars and all reserves and production volumes are on a working interest before royalties (“WI”) basis (net). Reserves are expressed in barrels (“bbl”), millions of barrels (“MMBBL”), bbl of oil equivalent (“boe”) or million boe (“MMBOE”), while production is expressed in boe per day (“BOEPD”), unless otherwise indicated.

Gary Guidry, President and Chief Executive Officer of Gran Tierra, commented: “Our 2025 year-end reserves and resources results reinforce the underlying strength and optionality of our asset base. As a result of exploration success and asset performance, we achieved greater than 100% reserve replacement in South America on both a proved developed producing (“PDP”) and proved plus probable (“2P”) basis for 2025. Our results clearly demonstrate the resources we have captured in the portfolio including 2P reserves of 258 MMBOE, unrisked best estimate contingent resources (“2C”) in the Hoadley Glauconitic project (“Glauconitic”) of 74 MMBOE and 118 MMBBL unrisked mean prospective resources in the noted Colombia and Ecuador prospects. In Canada, certain natural gas reserve volumes were reclassified as contingent resources reflecting a lower forecasted gas price, however, this does not diminish the underlying quality or long-term value of these assets and has limited impact on net present value. We have a deep inventory of oil assets and at current strip pricing our five year plan is focused on developing those assets, resulting in the reclassification based on reserve booking standards. We are the operator of the vast majority of our assets and in a higher natural gas price environment we could allocate capital quickly to our natural gas assets. With increased LNG capacity in North America and on going expansion of data centers, we remain more positive than ever on the long term demand for natural gas.

We have focused on portfolio longevity and asset quality, building a highly diversified portfolio across three countries, five basins, and two continents. This portfolio captures a substantial resource base, including approximately 296,965 MMcf or 0.3 trillion cubic feet (“Tcf”) of unrisked high-estimate contingent resources (“3C”) in the Glauconitic and 425,338 MMcf or 0.4 Tcf of proved plus probable plus possible reserves (“3P”) across our natural gas resources and reserves inventory. Our PDP reserves continue to generate strong cash flow, supporting debt reduction and strengthening the balance sheet, while our significant contingent and prospective resources provide option value and flexibility as market conditions evolve. The Company maintains a highly attractive PDP foundation, significant proved (“1P”) and 2P reserves, a demonstrated track record of moving 2P to 1P to PDP, and a deep inventory of resources that underpin meaningful long-term value.”

1These figures represent contingent resources under Canadian National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and are not reserves under NI 51-101 or SEC requirements. See “Disclosure of Oil and Gas Information, Disclosure of Reserves Information, Resources Information and Cautionary Note to U.S. Investors”.

Highlights

2025Year-End Reserves and Values

The net present value of reserves decreased from the 2024 year-end reserve which is predominately driven by a 7% percent decrease in the five-year average Brent oil price.

| Before Tax (as of December 31, 2025) | Units | 1P | 2P | 3P | | Reserves | MMBOE | 142 | 258 | 329 | | Net Present Value at 10% Discount (“NPV10”) | $ million | 1,456 | 2,461 | 3,317 | | Net Debt1 | $ million | (657) | (657) | (657) | | Net Asset Value (NPV10 less Net Debt) (“NAV”) | $ million | 799 | 1,804 | 2,660 | | Outstanding Shares | million | 35.30 | 35.30 | 35.30 | | NAV per Share | $/share | 22.63 | 51.09 | 75.35 | | | | | | |

| After Tax (as of December 31, 2025) | Units | 1P | 2P | 3P | | Reserves | MMBOE | 142 | 258 | 329 | | NPV10 | $ million | 1,138 | 1,758 | 2,283 | | Net Debt1 | $ million | (657) | (657) | (657) | | NAV | $ million | 481 | 1,101 | 1,626 | | Outstanding Shares | million | 35.30 | 35.30 | 35.30 | | NAV per Share | $/share | 13.62 | 31.19 | 46.06 | | | | | | |

1Based on estimated unaudited 2025 year-end Net Debt of $657 million comprised of Senior Notes of $741 million (gross) less cash and cash equivalents of $83 million, prepared in accordance with GAAP._See “Non-GAAP Measures”._

South America

Gran Tierra’s South American reserves base continues to be underpinned by material new discoveries in multi-zone, waterfloodable reservoirs. The Company’s strategic acquisition in Ecuador of the Perico and Espejo blocks added scale and high-quality inventory, enabling coordinated development across adjacent blocks and enhancing long-term development optionality. Recent exploration success, including the Conejo discoveries, added material reserves across the Hollin and Basal Tena reservoirs, while the Chanangue Este reactivation contributed incremental reserves and extended productive field life within the block. In addition, Gran Tierra holds approximately 118 MMBBL of mean unrisked prospective resources across its South American portfolio, which we believe highlights the depth of our exploration inventory and provides meaningful long-term development runway. Core producing assets continue to perform reliably, with Acordionero and Cohembi delivering steady base production and strong reserves support. While base performance at Costayaco and Moqueta trailed reserve forecasts during the year, these variances are well understood and operationally addressable. Gran Tierra has increased its focus on waterflood surveillance and optimization focus for 2026, positioning these fields for improved recovery and reserves realization. Taken together, South America remains the Company’s principal source of reserves replacement and capital-efficient growth.

Canada

As part of our ongoing commitment to capital discipline and portfolio high-grading, Gran Tierra reclassified our development inventory in the Glauconitic during 2025. Certain drilling locations were reclassified from reserves to contingent resources to better align development timing with prevailing commodity price assumptions and expected activity levels. This reclassification resulted in a reduction of 19 MMBOE on a 1P basis and 32 MMBOE on a 2P basis. Importantly, these volumes remain within the Company’s portfolio, with 74 MMBOE now classified as unrisked 2C contingent resources, approximately 50% of which is natural gas, providing meaningful leverage to a potential recovery in North American natural gas prices. The reclassification did not have a material impact on Gran Tierra’s NAV. At year-end 2024, the affected Glauconitic locations represented approximately 13% of 1P future development costs (“FDC”), yet contributed approximately 3% of before-tax NPV10 value under conservative natural gas price assumptions. These locations remain economically attractive at higher gas prices, and Gran Tierra estimates that an increase in AECO pricing from C$3.00/mcf to C$4.00/mcf reduces Glauconitic well payout periods by approximately 25%, improving project economics and development timing. This supports the Company’s decision to prioritize near-term capital toward higher-return opportunities while preserving the technical and potential economic upside of the Glauconitic in a higher-price environment.

Reserves

As of December 31, 2025, Gran Tierra achieved: Before Tax NAV of $0.8 billion (1P), $1.8 billion (2P), and $2.7 billion (3P) After Tax NAV of $0.5 billion (1P), $1.1 billion (2P), and $1.6 billion (3P) Reserve Life Index*: 1P: 8 years 2P: 15 years 3P: 19 years

South American reserves replacement: 101% PDP, with PDP reserves additions of 11 MMBOE 61% 1P, with 1P reserves additions of 6 MMBOE 105% 2P, with 2P reserves additions of 11 MMBOE

Canadian reserves replacement was negative as a result of the reclassification of certain reserves to contingent resources

Canada now represents 39% of 1P and 44% of 2P reserves of Gran Tierra’s total reserves. FDC are forecast by McDaniel to be $888 million for 1P reserves and $1,682 million for 2P reserves. Decreases in FDC relative to 2024 year-end reflect that the GTE McDaniel Reserves Report now assigns Gran Tierra 168 Proved Undeveloped future drilling locations (down from 227 at 2024 year-end with 62 Glauconitic locations moved to contingent resources) and 362 Proved plus Probable Undeveloped future drilling locations (down from 441 at 2024 year-end with 74 Glauconitic locations moved to contingent).

*The reserve life indexes were calculated based on a Q4 2025 total average production rate of 46,513 BOEPD. Reserves replacement were calculated based on an annual basis using South America average production rate of 29,066 BOEPD.

GTE McDaniel Reserves Report

All reserves values, future net revenue and ancillary information contained in this press release have been prepared by McDaniel and calculated in compliance with NI 51-101 and the Canadian Oil and Gas Evaluation Handbook (“COGEH”) and derived from a report with an effective date of December 31, 2025 (the “GTE McDaniel Reserves Report”), unless otherwise expressly stated.

Future Net Revenue

Future net revenue reflects McDaniel’s forecast of revenue estimated using forecast prices and costs, arising from the anticipated development and production of reserves, after the deduction of royalties, operating costs, development costs and abandonment and reclamation costs but before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. The estimate of future net revenue below does not necessarily represent fair market value.

| Consolidated Properties at December 31, 2025 | | | | | | | | | | | | | | | Proved (1P) Total Future Net Revenue ($ million) | | | | | | | | | | | | | | | Forecast Prices and Costs | | | | | | | | | | | | | | | | Sales Revenue | Total Royalties | Operating Costs | Future Development Capital | Abandonment and Reclamation Costs | Future Net Revenue Before Future Taxes | Future Taxes | Future Net Revenue After Future Taxes* | | | | | | | 2026 - 2030 (5 Years) | 4,479 | (883 | ) | (1,443 | ) | (882 | ) | (31 | ) | 1,239 | (280 | ) | 959 | | Remainder | 3,167 | (589 | ) | (1,413 | ) | (5 | ) | (345 | ) | 815 | (212 | ) | 603 | | Total (Undiscounted) | 7,645 | (1,472 | ) | (2,856 | ) | (888 | ) | (376 | ) | 2,054 | (492 | ) | 1,562 | | Total (Discounted @ 10%) | | | | | | 1,456 | (318 | ) | 1,138 | | | | |

| Consolidated Properties at December 31, 2025 | | | | | | | | | | | | | | | Proved Plus Probable (2P) Total Future Net Revenue ($ million) | | | | | | | | | | | | | | | Forecast Prices and Costs | | | | | | | | | | | | | | | Years | Sales Revenue | Total Royalties | Operating Costs | Future Development Capital | Abandonment and Reclamation Costs | Future Net Revenue Before Future Taxes | Future Taxes | Future Net Revenue After Future Taxes* | | | | | | | 2026 - 2030 (5 Years) | 5,222 | (1,040 | ) | (1,550 | ) | (1,016 | ) | (27 | ) | 1,589 | (404 | ) | 1,185 | | Remainder | 8,851 | (1,944 | ) | (3,080 | ) | (666 | ) | (391 | ) | 2,770 | (900 | ) | 1,870 | | Total (Undiscounted) | 14,073 | (2,984 | ) | (4,629 | ) | (1,682 | ) | (419 | ) | 4,359 | (1,304 | ) | 3,055 | | Total (Discounted @ 10%) | | | | | | 2,461 | (703 | ) | 1,758 | | | | |

| Consolidated Properties at December 31, 2025 | | | | | | | | | | | | | | | Proved Plus Probable Plus Possible (3P) Total Future Net Revenue ($ million) | | | | | | | | | | | | | | | Forecast Prices and Costs | | | | | | | | | | | | | | | Years | Sales Revenue | Total Royalties | Operating Costs | Future Development Capital | Abandonment and Reclamation Costs | Future Net Revenue Before Future Taxes | Future Taxes | Future Net Revenue After Future Taxes* | | | | | | | 2026 - 2030 (5 Years) | 5,790 | (1,172 | ) | (1,613 | ) | (1,067 | ) | (26 | ) | 1,911 | (529 | ) | 1,382 | | Remainder | 12,799 | (3,029 | ) | (4,078 | ) | (818 | ) | (407 | ) | 4,467 | (1,516 | ) | 2,951 | | Total (Undiscounted) | 18,589 | (4,202 | ) | (5,691 | ) | (1,886 | ) | (433 | ) | 6,378 | (2,044 | ) | 4,334 | | Total (Discounted @ 10%) | | | | | | 3,317 | (1,033 | ) | 2,283 | | | | |

*The after-tax future net revenue of the Company’s oil and gas properties reflects the tax burden on the properties on a stand-alone basis. It does not consider the corporate tax situation, or tax planning. It does not provide an estimate of the value at the Company level which may be significantly different. The Company’s financial statements, when available for the year ended December 31, 2025, should be consulted for information at the Company level.

Total Company WI Reserves

The following table summarizes Gran Tierra’s NI 51-101 and COGEH compliant reserves in aggregate for Colombia, Ecuador and Canada derived from the GTE McDaniel Reserves Report calculated using forecast oil and gas prices and costs.

| | Light and Medium Crude Oil | Heavy Crude Oil | Tight Oil | Conventional Natural Gas | Shale Gas | Natural Gas Liquids | 2025 Year- End | | Reserves Category | Mbbl* | Mbbl* | Mbbl* | MMcf | MMcf | Mbbl* | Mboe* | | Proved Developed Producing | 25,603 | 20,216 | 761 | 107,711 | 3,695 | 13,145 | 78,293 | | Proved Developed Non-Producing | 1,715 | 733 | 22 | 4,105 | 56 | 309 | 3,472 | | Proved Undeveloped | 29,603 | 15,649 | 3,566 | 26,440 | 18,417 | 3,536 | 59,829 | | Total Proved | 56,921 | 36,598 | 4,349 | 138,256 | 22,168 | 16,990 | 141,594 | | Total Probable | 42,603 | 20,003 | 5,350 | 145,188 | 33,923 | 18,130 | 115,938 | | Total Proved plus Probable | 99,524 | 56,601 | 9,699 | 283,444 | 56,091 | 35,120 | 257,532 | | Total Possible | 32,612 | 13,554 | 2,614 | 70,761 | 15,042 | 8,777 | 71,858 | | Total Proved plus Probable plus Possible | 132,136 | 70,155 | 12,313 | 354,205 | 71,133 | 43,897 | 329,390 |

*Mbbl (thousand bbl of oil). MMcf (million cubic feet). *Mboe (thousand boe).

Net Present Value Summary

Gran Tierra’s reserves were evaluated using McDaniel’s commodity price forecasts at January 1, 2026. See “Forecast Prices” for more information. It should not be assumed that the net present value of cash flow estimated by McDaniel represents the fair market value of Gran Tierra’s reserves.

| Total Company | Discount Rate | | | | | | ($ millions) | 0% | 5% | 10% | 15% | 20% | | Before Tax | | | | | | | Proved Developed Producing | 1,106 | 1,091 | 988 | 894 | 816 | | Proved Developed Non-Producing | 56 | 45 | 37 | 30 | 26 | | Proved Undeveloped | 892 | 615 | 431 | 304 | 213 | | Total Proved | 2,054 | 1,751 | 1,456 | 1,228 | 1,055 | | Total Probable | 2,305 | 1,473 | 1,005 | 720 | 537 | | Total Proved plus Probable | 4,359 | 3,224 | 2,461 | 1,948 | 1,592 | | Total Possible | 2,019 | 1,263 | 856 | 614 | 461 | | Total Proved plus Probable plus Possible | 6,378 | 4,487 | 3,317 | 2,562 | 2,053 | | After Tax | | | | | | | Proved Developed Producing | 939 | 953 | 870 | 791 | 724 | | Proved Developed Non-Producing | 47 | 37 | 30 | 25 | 21 | | Proved Undeveloped | 577 | 372 | 238 | 148 | 84 | | Total Proved | 1,563 | 1,362 | 1,138 | 964 | 829 | | Total Probable | 1,493 | 929 | 620 | 437 | 322 | | Total Proved plus Probable | 3,056 | 2,291 | 1,758 | 1,401 | 1,151 | | Total Possible | 1,279 | 784 | 525 | 375 | 280 | | Total Proved plus Probable plus Possible | 4,335 | 3,075 | 2,283 | 1,776 | 1,431 |

Reserve Life Index (Years)

| | December 31, 2025* | | Total Proved | 8 | | Total Proved plus Probable | 15 | | Total Proved plus Probable plus Possible | 19 |

The reserve life indexes were calculated based on a Q4 2025 total average production rate of 46,513 BOEPD.

Future Development Costs

FDC reflects McDaniel’s best estimate of what it will cost to bring the Proved Undeveloped and Probable Undeveloped reserves on production. Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities, and changes in capital cost estimates based on improvements in well design and performance, as well as changes in service costs. FDC for 2P reserves decreased to $1,682 million at year-end 2025 from $1,809 million at year-end 2024. The decrease in FDC in 2025 was predominantly attributed to the capital spending in the Suroriente block as well as the reduction of capex in Canada due to the movement of certain reserves to our contingent resources.

| ($ millions) | Total Proved | Total Proved Plus Probable | Total Proved Plus Probable Plus Possible | | 2026 | 95 | 100 | 100 | | 2027 | 177 | 186 | 189 | | 2028 | 209 | 232 | 245 | | 2029 | 223 | 274 | 287 | | 2030 | 178 | 224 | 246 | | Remainder | 5 | 666 | 818 | | Total (undiscounted) | 887 | 1,682 | 1,885 |

| ($ millions) | Proved | Proved plus Probable | Proved plus Probable plus Possible | | Colombia - Acordionero | 161 | 161 | 161 | | Colombia - Chaza Block (Costayaco & Moqueta) | 120 | 145 | 145 | | Colombia - Suroriente | 88 | 110 | 126 | | Ecuador - Chanangue | 117 | 189 | 252 | | Ecuador - Charapa | 128 | 235 | 289 | | Canada - Central | 50 | 186 | 186 | | Canada - Simonette | 130 | 255 | 255 | | Other | 93 | 401 | 471 | | Total FDC Costs (undiscounted) | 887 | 1,682 | 1,885 |

Drilling Locations Summary By Country

| | Total Proved | Total Proved Plus Probable | Total Proved Plus Probable Plus Possible | | Colombia | 67 | 100 | 111 | | Ecuador | 38 | 63 | 74 | | Canada | 63 | 199 | 199 | | Total | 168 | 362 | 384 |

GTE McDaniel Resources Report

All resources values and ancillary information contained in this press release have been prepared by McDaniel and calculated in compliance with NI 51-101 and the COGEH and derived from a report with an effective date of December 31, 2025 (the “GTE McDaniel Resources Report”), unless otherwise expressly stated.

Summary of Unrisked and Risked Contingent Resources

The following table sets forth Gran Tierra’s unrisked and risked gross(6) contingent resources by product type for the Glauconitic at December 31, 2025 and is derived from the GTE McDaniel Resources Report. The project is considered a development on hold(5)as it could be economic at some point in the future:

| | Gross(6) Contingent Resources(1)(2)(4) | | | | | | | | | By Product Type | | | | | | | | Hoadley Glauconitic Play | Unrisked | | Risked | | Chance of Development(3) | | | | Product | 1C | 2C | 3C | | 2C | | % | | Light and Medium Crude Oil (Mbbls) | 825 | 1,237 | 1,650 | | 990 | | 80% | | Conventional Natural Gas (MMcf) | 148,483 | 222,724 | 296,965 | | 178,179 | | 80% | | Natural Gas Liquids (Mbbls) | 23,609 | 35,413 | 47,217 | | 28,330 | | 80% | | TOTALS (Mboe)(7) | 49,181 | 73,771 | 98,362 | | 59,017 | | 80% |