Gran Tierra Energy Inc. Announces 2025 Fourth Quarter & Year-End Results
- Achieved Average Working Interest Fourth Quarter Production of 46,344 BOEPD
- Realized 2025 Adjusted EBITDA1 of $284 Million
- Delivered Net Cash Provided by Operating Activities of $313 Million, up 31% from 2024
- Generated 2025 Funds Flow from Operations1 of $178 Million
- Seventh Consecutive Year of South American Reserves Growth With Over 100% Reserve Replacement PDP & 2P
- Achieved Company’s Best Safety Performance on Record in 2025
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Subsequent to Year-End Completed a Bond Exchange, Sold Non-Core Assets and Signed an Agreement in Azerbaijan
CALGARY, Alberta, March 03, 2026 (GLOBE NEWSWIRE) -- Gran Tierra Energy Inc. (“Gran Tierra” or the “Company”) (NYSE American:GTE) (TSX:GTE) (LSE:GTE) today announced the Company’s financial and operating results for the fourth quarter (“the Quarter”) and year ended December 31, 2025. Gran Tierra’s 2025 year-end reserves were evaluated by the Company's independent qualified reserves evaluator McDaniel & Associates Consultants Ltd. (“McDaniel”) in a report with an effective date of December 31, 2025 (the “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 Canadian National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGEH”) and derived from the GTE McDaniel Reserves Report, unless otherwise expressly stated. The following reserves categories are discussed in this press release: Proved Developed Producing (“PDP”), Proved (“1P”), 1P plus Probable (“2P”) and 2P plus Possible (“3P”). All dollar amounts are in United States (“U.S.”) dollars and all production volumes are on an average working interest before royalties (“WI”) basis unless otherwise indicated. Production is expressed in barrels (“bbl”) of oil equivalent (“boe”) per day (“boepd” or “boe/d”) and are based on WI sales before royalties. Reserves are expressed in boe or million boe (“MMBOE”), unless otherwise indicated. For per boe amounts based on net after royalty (“NAR”) production, see Gran Tierra’s Annual Report on Form 10-K filed March 4, 2026.
Message to Shareholders
Gary Guidry, President and Chief Executive Officer of Gran Tierra, commented: “We exited 2025 in a position of operational strength and enhanced financial flexibility. The successful exchange of our 9.500% Senior Secured Amortizing Notes due 2029, with approximately 88% participation, demonstrates strong bondholder confidence in Gran Tierra and our strategy. The exchange extended our maturity profile and reduced total bond debt outstanding while strengthening our capital structure. Together with the prepayment facility and non-core asset sales, this significantly enhances our liquidity and provides greater flexibility to allocate capital and accelerate deleveraging as we enter 2026.
These actions provide a clear path toward deleveraging while we execute on a clear development plan across the portfolio. Over the past several years, our team has assembled a diversified, high-quality asset base across South America and Canada. That portfolio build-out required disciplined investment and the strategic use of leverage to secure long-life, high-quality assets with a focus on portfolio longevity. With the portfolio now established, our focus shifts to optimizing and developing those assets while steadily reducing debt and maximizing free cash flow. As we close out 2025, we look toward a 2026 program centered on disciplined development and capital allocation, leveraging our technical capabilities across the portfolio to deliver stable production growth and free cash flow.”
Operational:
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Production:
- Gran Tierra achieved 2025 average WI production of 45,709 BOEPD, representing a 32% increase from 2024, as a result of positive exploration well results in Ecuador, full year production from the Canadian operations, partially offset by lower production in Southern Colombia and Ecuador as a result of two major export pipeline disruptions, and trunk line repairs at the Moqueta field which resulted in the field being shut-in during the third quarter of 2025.
- The Quarter: Gran Tierra produced an average WI production of 46,344 BOEPD, a 13% increase from the fourth quarter 2024 and a 9% increase from the third quarter 2025 (“the Prior Quarter”).
- Commitments: Gran Tierra significantly reduced its capital commitments in both Ecuador and Colombia during the year. In Ecuador, the Company completed all Phase 1 commitments and submitted the required Field Development Plans, fully securing its country entry. In Colombia, commitments were streamlined through targeted portfolio and work program revisions. Together with ongoing debt reduction, these actions reduced letters of credit and obligations, materially improving liquidity and enhancing capital allocation flexibility going forward.
- 2026 Suroriente Drilling Campaign: The Company recently drilled the Raju-2 well on the Suroriente Block, targeting the northern extent of the Cohembi field. The well is currently producing at a rate of approximately 790 barrels of oil per day, 6 barrels of water per day and 0.6 thousand cubic feet of gas per day and is on track to exceed management’s initial 30-day production expectations. Raju-2 further delineates the productive limits of the field while reinforcing the development potential of the broader Cohembi structure. The well is part of is part ofthe capital carry commitment associated with Suroriente and with three wells remaining, the Company expects to complete the remaining capital carry by the middle of 2026.
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Azerbaijan Entry: Gran Tierra entered into an exploration, development and production sharing agreement (“EDPSA”) with the State Oil Company of the Azerbaijan Republic (“SOCAR”), providing for a 65% participating interest to Gran Tierra and 35% to SOCAR. The EDPSA includes a five-year exploration phase and upon a commercial discovery, a 25-year development phase. Minimum exploration commitments to be completed within 36 months include the acquisition of 250 square kilometres of 3D seismic, the drilling of two exploration wells, and geological and environment impact studies.
2025 Year-End Reserves and Values2:
| 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 Debt* | $ million | (658) | (658) | (658) |
| Net Asset Value (NPV10 less Net Debt) (“NAV”)3 | $ million | 798 | 1,803 | 2,659 |
| Outstanding Shares4 | million | 35.30 | 35.30 | 35.30 |
| NAV per Share3 | $/share | 22.61 | 51.08 | 75.33 |
| 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 Debt* | $ million | (658) | (658) | (658) |
| NAV3 | $ million | 480 | 1,100 | 1,625 |
| Outstanding Shares4 | million | 35.30 | 35.30 | 35.30 |
| NAV per Share3 | $/share | 13.61 | 31.17 | 46.05 |
- As of December 31, 2025, Gran Tierra achieved2,3:
- 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*** of:
- 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 due to lower forecasted gas prices.
- Canada now represents 39% of 1P and 44% of 2P reserves compared to Gran Tierra’s total reserves.
- Future development costs (“FDC”) are forecasted 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).
*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”.
**The reserve life indexes were calculated based on a Q4 2025 total average production rate of 46,344 BOEPD.
***Reserves replacement were calculated based on an annual basis using South America average production rate of 29,023 BOEPD.
Financial:
- 2025 Net Income: Gran Tierra realized a net loss of $193.1 million or $5.45 per share (basic and diluted), which included non-cash ceiling test impairment losses of $136.3 million, compared to net income of $3.2 million, or $0.10 per share (basic and diluted) in 2024.
- 2025 Adjusted EBITDA1: The Company realized Adjusted EBITDA1 of $283.7 million, a decrease of 23% from $366.8 million in 2024, commensurate with the decrease in the Brent oil price.
- 2025 Net Cash Provided by Operating Activities: The Company generated net cash provided by operating activities of $313.2 million, an increase of 31% from $239.3 million in 2024.
- 2025 Funds Flow from Operations1: Gran Tierra realized funds flow from operations1 of $177.8 million, compared to $224.9 million in 2024.
- 2025 Capital Expenditures: Capital expenditures increased by $8.2 million or 3% to $256.3 million compared to 2024 due to a higher number of wells drilled in 2025 in Colombia, Ecuador, and Canada, which was predominately funded by the Company’s 2025 net cash provided by operating activities of $313.2 million.
- Key Metrics During the Quarter: The Company realized a net loss of $141.1 million, Adjusted EBITDA1 of $52.5 million, and funds flow from operations1 of $26.8 million in the Quarter, compared with a net loss of $20.0 million, Adjusted EBITDA1 of $69.0 million, and funds flow from operations1 of $41.7 million in the Prior Quarter. The Company recognized quarterly production of 46,344 BOEPD.
- Cash Balance: The Company had $82.9 million in cash and cash equivalents as at December 31, 2025, a decrease compared to a cash balance of $103.4 million as at December 31, 2024.
- Bonds Buybacks: During 2025, Gran Tierra bought back approximately $21.3 million in face value of the Company’s 9.50% senior notes due October 15, 2029. This represents a discount of about 20% to the face value of the repurchased bonds.
- Share Buybacks: Since January 1, 2022, through its NCIB programs, the Company has re-purchased approximately 7.5 million shares of Common Stock, representing about 21% of shares outstanding as of December 31, 2025.
- 2025 Operating Costs: Total operating expenses were $248.7 million, compared to $202.3 million in 2024, representing a 23% increase while operating expenses per boe were $15.17, 6% lower when compared to 2024. The increase in total operating expenses in 2025 was a result of higher operating costs in Ecuador driven by a production ramp-up in 2025, and the full year of Canadian operations.
- 2025 Cash General and Administrative Costs: The Company’s gross cash general and administrative (“G&A”) costs increased to $3.47 per boe from $3.30 per boe in 2024. Total cash G&A costs were $56.9 million, an increase of 37% from $41.4 million in 2024, driven by a full year of G&A expenses from Canadian operations, higher business development costs, and consulting costs attributed to optimization projects.
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Oil, Natural Gas and Natural Gas Liquids (“NGL”) Sales:
- 2025: Gran Tierra’s oil, natural gas and NGL sales decreased 4% to $596.7 million, compared to $621.8 million in 2024. This decrease was primarily driven by a 15% decrease in Brent price and a 19% decrease in sales volumes in Colombia, offset by higher sales volumes in Ecuador, lower differentials, and a full year of sales from Canadian operations.
- The Quarter: Gran Tierra generated oil, natural gas and NGL sales of $129.9 million, a decrease of 13% or $19.3 million from the Prior Quarter, primarily driven by a 7% decrease in the Brent oil price, offsetting a 13% increase in production. Oil, natural gas and NGL sales were $32.95 per boe, a 10% decrease from the Prior Quarter primarily as a result of lower oil prices and lower natural gas prices in Canada. Sales in the Quarter were impacted by the timing of a lifting in Ecuador that deferred approximately $15 million of revenue, which was recognized in early January 2026.
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Operating Netback1:
- 2025: Gran Tierra’s operating netback1 of $20.18 per boe was down 37% from $31.99 in 2024.
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The Quarter: The Company’s operating netback1 of $17.53 per boe was lower by 21% from the fourth quarter 2024 and a decrease of 7% from the Prior Quarter due to increased weighting to natural gas in Canada and lower oil prices.
Closing of Bond Exchange and Upsized Prepayment Facility:
- Subsequent to December 31, 2025, Gran Tierra successfully closed its previously announced bond exchange, achieving approximately 88% participation, reflecting strong bondholder confidence in the Company’s asset base, strategy and long-term credit profile. The Company exchanged $629 million of its 9.500% Senior Secured Amortizing Notes due 2029 for $504 million of new 9.750% Senior Secured Amortizing Notes maturing April 15, 2031, with a structured amortization profile beginning in 2029. In connection with the exchange, the Company paid $125.0 million in cash consideration and cancelled the tendered and treasury-held notes. On a pro forma basis, reflecting the exchange, Gran Tierra’s net debt is approximately $5338 million. The Company also amended and expanded its oil offtake and prepayment agreement with Trafigura to a facility of up to $350.0 million, enhancing liquidity and extending maturities while further strengthening the balance sheet.
Gran Tierra’s Commitment to Go “Beyond Compliance” with Safe and Sustainable Operations
- 2025 was the Company’s safest year on record. Gran Tierra has accumulated a total of 37.2 million person-hours without a Lost Time Injury (LTI), and in 2025, the Company’s Total Recordable Incident Frequency (TRIF) was 0.02, placing Gran Tierra in the top quartile for safety performance across its operating regions.
- Gran Tierra opened the Acordionero Forestry Centre in El Cairo, Cesar, Colombia — the Company’s second forestry centre dedicated to biodiversity, conservation, sustainable agricultural management and environmental innovation. Nearly 11,000 native trees have already been planted at the site, and the nursery produces approximately 9,000 plants per month, reinforcing its contribution to regional ecosystem recovery. The Centre also features a solar-powered aquaponics system that operates as a closed loop: tilapia waste fertilizes soil-free crops while water is continuously recycled, reducing water use by more than 90% compared with traditional farming.
- Launched in 2017 in Colombia, Gran Tierra’s flagship program NaturAmazonas, has evolved into much more than a traditional conservation project. While Gran Tierra has consistently expanded our reforestation efforts to exceed initial targets, the program now also integrates the local economy into it. Gran Tierra has grown to support over 800 local families in deforestation-free cacao farming, connected them with international buyers and has trained over 420 local beekeepers to produce sustainable honey from native bee species.
- Throughout all of Gran Tierra’s environmental initiatives, Gran Tierra has planted over 1.9 million trees and restored or protected over 5,600 hectares of land so far.
- More than 400,000 people have benefited from Gran Tierra’s social investment programs in South America to date.
- As part of the Works for Taxes program, Gran Tierra is building four major infrastructure projects in Putumayo, including a new aqueduct that will deliver potable water to 1,300 residents in the municipalities of Mocoa, Valle del Guamuez and Puerto Asís. Other initiatives include rural road upgrades benefiting 24,000 local residents and improvements to local school facilities.
- Gran Tierra has been accepted by the Voluntary Principles Initiative as an official member of the Voluntary Principles for Security and Human Rights world-wide initiative. This membership is a recognition of Gran Tierra’s efforts at respecting and promoting human dignity and provides support to improve the Company’s security and Human Rights performance.
Corporate Presentation:
- Gran Tierra’s Corporate Presentation has been updated and is available at www.grantierra.com.
Financial and Operational Highlights5 (all amounts in $000s, except per share and boe amounts)
| Consolidated Information | Year Ended | Three Months Ended | ||||||||||||||
| December 31, | December 31, | December 31, | December 31, | September 30, | ||||||||||||
| 2025 | 2024 | 2025 | 2024 | 2025 | ||||||||||||
| Net (Loss) Income | $ | (193,119 | ) | $ | 3,216 | $ | (141,148 | ) | $ | (34,210 | ) | $ | (19,950 | ) | ||
| Net (Loss) Income Per Share - Basic | $ | (5.45 | ) | $ | 0.10 | $ | (4.00 | ) | $ | (1.04 | ) | $ | (0.57 | ) | ||
| Net (Loss) Income Per Share - Diluted | $ | (5.45 | ) | $ | 0.10 | $ | (4.00 | ) | $ | (1.04 | ) | $ | (0.57 | ) | ||
| Operating Netback1 | ||||||||||||||||
| Gross Profit6 | $ | 66,419 | $ | 182,637 | $ | 851 | $ | 22,180 | $ | 14,670 | ||||||
| Depletion and Accretion7 | 264,522 | 218,417 | 68,236 | 60,061 | 61,908 | |||||||||||
| Operating Netback1 | $ | 330,941 | $ | 401,054 | $ | 69,087 | $ | 82,241 | $ | 76,578 | ||||||
| Oil, Natural Gas and NGL Sales | $ | 596,713 | $ | 621,849 | $ | 129,929 | $ | 147,290 | $ | 149,254 | ||||||
| Operating Expenses | (248,748 | ) | (202,331 | ) | (57,160 | ) | (60,770 | ) | (68,379 | ) | ||||||
| Transportation Expenses | (17,024 | ) | (18,464 | ) | (3,682 | ) | (4,279 | ) | (4,297 | ) | ||||||
| Operating Netback1 | $ | 330,941 | $ | 401,054 | $ | 69,087 | $ | 82,241 | $ | 76,578 | ||||||
| G&A Expenses Before Stock-based Compensation | $ | 56,873 | $ | 41,431 | $ | 16,817 | $ | 8,672 | $ | 13,453 | ||||||
| G&A Expenses Stock-Based Compensation | 3,214 | 9,707 | 3,042 | 3,331 | 143 | |||||||||||
| G&A Expenses, Including Stock-Based Compensation | $ | 60,087 | $ | 51,138 | $ | 19,859 | $ | 12,003 | $ | 13,596 | ||||||
| EBITDA1 | $ | 146,790 | $ | 355,690 | $ | (77,030 | ) | $ | 65,247 | $ | 59,202 | |||||
| Adjusted EBITDA1 | $ | 283,656 | $ | 366,758 | $ | 52,473 | $ | 76,168 | $ | 69,034 | ||||||
| Net Cash Provided by Operating Activities | $ | 313,249 | $ | 239,321 | $ | 157,193 | $ | 26,607 | $ | 48,149 | ||||||
| Funds Flow from Operations1 | $ | 177,762 | $ | 224,941 | $ | 26,827 | $ | 44,129 | $ | 41,685 | ||||||
| Capital Expenditures (Before Changes in Working Capital) | $ | 256,277 | $ | 248,103 | $ | 53,040 | $ | 78,579 | $ | 57,340 | ||||||
| Free Cash Flow1 | $ | (78,515 | ) | $ | (23,162 | ) | $ | (26,213 | ) | $ | (34,450 | ) | $ | (15,655 | ) | |
| Average Daily Volumes (BOEPD) | ||||||||||||||||
| Working Interest Production Before Royalties | 45,709 | 34,710 | 46,344 | 41,009 | 42,685 | |||||||||||
| Royalties | (7,266 | ) | (6,820 | ) | (6,880 | ) | (7,327 | ) | (6,723 | ) | ||||||
| Production NAR | 38,443 | 27,890 | 39,464 | 33,682 | 35,962 | |||||||||||
| (Decrease) Increase in Inventory | (779 | ) | (454 | ) | (3,480 | ) | (712 | ) | 1,391 | |||||||
| Sales | 37,664 | 27,436 | 35,984 | 32,970 | 37,353 | |||||||||||
| Royalties, % of WI Production Before Royalties | 16 | % | 20 | % | 15 | % | 18 | % | 16 | % | ||||||
| Per boe5 | ||||||||||||||||
| Gross Profit6 | $ | 4.05 | $ | 14.57 | $ | 0.22 | $ | 5.98 | $ | 3.62 | ||||||
| Depletion and Accretion7 | 16.13 | 17.42 | 17.30 | 16.20 | 15.27 | |||||||||||
| Operating Netback(1)(5) | $ | 20.18 | $ | 31.99 | $ | 17.53 | $ | 22.19 | $ | 18.89 | ||||||
| Brent | $ | 68.19 | $ | 79.86 | $ | 63.08 | $ | 74.01 | $ | 68.17 | ||||||
| Quality and Transportation Discount | (24.78 | ) | (17.93 | ) | (23.83 | ) | (25.45 | ) | (24.73 | ) | ||||||
| Royalties | (7.02 | ) | (12.33 | ) | (6.30 | ) | (8.83 | ) | (6.63 | ) | ||||||
| Average Realized Price | $ | 36.39 | $ | 49.60 | $ | 32.95 | $ | 39.73 | $ | 36.81 | ||||||
| Transportation Expenses | (1.04 | ) | (1.47 | ) | (0.93 | ) | (1.15 | ) | (1.06 | ) | ||||||
| Average Realized Price Net of Transportation Expenses | $ | 35.35 | $ | 48.13 | $ | 32.02 | $ | 38.58 | $ | 35.75 | ||||||
| Operating Expenses | (15.17 | ) | (16.14 | ) | (14.49 | ) | (16.39 | ) | (16.86 | ) | ||||||
| Operating Netback1 | $ | 20.18 | $ | 31.99 | $ | 17.53 | $ | 22.19 | $ | 18.89 | ||||||
| Cash G&A Expenses | (3.47 | ) | (3.30 | ) | (4.26 | ) | (2.75 | ) | (3.32 | ) | ||||||
| Transaction Costs | — | (0.47 | ) | — | (1.20 | ) | — | |||||||||
| Export Tax | (0.20 | ) | — | (0.17 | ) | — | (0.65 | ) | ||||||||
| Realized Foreign Exchange (Loss) Gain | (0.47 | ) | 0.07 | (0.71 | ) | 0.07 | (0.53 | ) | ||||||||
| Cash Settlement on Derivative Instruments | 0.63 | 0.09 | 0.19 | 0.30 | 1.84 | |||||||||||
| Interest Expense, Excluding Amortization of Debt Issuance Costs | (5.02 | ) | (5.38 | ) | (5.45 | ) | (5.40 | ) | (5.22 | ) | ||||||
| Interest Income | 0.07 | 0.29 | 0.06 | 0.34 | 0.05 | |||||||||||
| Other Cash Gain | 0.10 | 0.12 | — | 0.40 | 0.31 | |||||||||||
| Net Lease Payments | (0.01 | ) | 0.07 | (0.03 | ) | 0.07 | (0.10 | ) | ||||||||
| Current Income Tax (Expense) Recovery | (0.97 | ) | (5.53 | ) | (0.35 | ) | (2.12 | ) | (0.99 | ) | ||||||
| Cash Netback1 | $ | 10.84 | $ | 17.95 | $ | 6.81 | $ | 11.90 | $ | 10.28 | ||||||
| Share Information (000s) | ||||||||||||||||
| Common Stock Outstanding, End of Period | 35,299 | 35,972 | 35,299 | 35,972 | 35,296 | |||||||||||
| Weighted Average Number of Common - Basic | 35,436 | 32,043 | 35,294 | 34,333 | 35,291 | |||||||||||
| Weighted Average Number of Common - Diluted | 35,436 | 32,043 | 35,294 | 34,333 | 35,291 | |||||||||||
| Colombia Information | Year Ended, | Three Months Ended, | ||||
| December 31, | December 31, | December 31, | December 31, | September 30, | ||
| 2025 | 2024 | 2025 | 2024 | 2025 | ||
| Operating Netback(1)(5) | ||||||
| Gross Profit6 | $53,685 | $180,605 | $(2,865) | $21,728 | $10,237 | |
| Depletion and Accretion7 | 186,319 | 199,323 | 49,383 | 47,858 | 44,041 | |
| Operating Netback(1)(5) | $240,004 | $379,928 | $46,518 | $69,586 | $54,278 | |
| Oil Sales | $418,411 | $575,482 | $89,072 | $119,310 | $101,999 | |
| Operating Expenses | (165,902) | (179,257) | (39,897) | (46,614) | (44,819) | |
| Transportation Expenses | (12,505) | (16,297) | (2,657) | (3,110) | (2,902) | |
| Operating Netback(1)(5) | $240,004 | $379,928 | $46,518 | $69,586 | $54,278 | |
| Capital Expenditures (Before Changes in Working Capital) | $149,138 | $126,867 | $32,858 | $28,855 | $32,573 | |
| Average Daily Production (BOEPD) | ||||||
| WI Production Before Royalties | 24,169 | 29,389 | 23,258 | 25,990 | 22,701 | |
| Royalties | (3,685) | (5,545) | (3,013) | (4,548) | (3,481) | |
| Production NAR | 20,484 | 23,844 | 20,245 | 21,442 | 19,220 | |
| Increase (Decrease) in Inventory | (210) | 53 | (908) | 245 | 337 | |
| Sales | 20,274 | 23,897 | 19,337 | 21,687 | 19,557 | |
| Royalties, % of WI Production Before Royalties | 15% | 19% | 13% | 17% | 15% | |
| Operating Netback ($/boe)(1)(5) | ||||||
| Gross Profit6 | $6.14 | $16.76 | $(1.39) | $9.00 | $4.83 | |
| Depletion and Accretion7 | 21.31 | 18.50 | 24.02 | 19.83 | 20.78 | |
| Operating Netback(1)(5) | $27.44 | $35.26 | $22.63 | $28.83 | $25.60 | |
| Brent | $68.19 | $79.86 | $63.08 | $74.01 | $68.17 | |
| Quality and Transportation Discount | (11.65) | (14.06) | (13.01) | (14.21) | (11.48) | |
| Royalties | (8.70) | (12.39) | (6.75) | (10.37) | (8.57) | |
| Average Realized Price | 47.84 | 53.41 | 43.32 | 49.43 | 48.12 | |
| Transportation Expenses | (1.43) | (1.51) | (1.29) | (1.29) | (1.37) | |
| Average Realized Price Net of Transportation Expenses | 46.41 | 51.90 | 42.03 | 48.14 | 46.75 | |
| Operating Expenses | (18.97) | (16.64) | (19.40) | (19.31) | (21.15) | |
| Operating Netback(1)(5) | $27.44 | $35.26 | $22.63 | $28.83 | $25.60 | |
| Ecuador Information | Year Ended, | Three Months Ended, | ||||
| December 31, | December 31, | December 31, | December 31, | September 30, | ||
| 2025 | 2024 | 2025 | 2024 | 2025 | ||
| Operating Netback(1)(5) | ||||||
| Gross Profit6 | $5,479 | $2,336 | $3,678 | $756 | $859 | |
| Depletion and Accretion7 | 29,624 | 10,156 | 5,258 | 3,265 | 9,519 | |
| Operating Netback(1)(5) | $35,103 | $12,492 | $8,936 | $4,021 | $10,378 | |
| Oil Sales | $62,609 | $27,412 | $12,486 | $9,025 | $20,605 | |
| Operating Expenses | (24,270) | (13,425) | (2,918) | (4,507) | (9,157) | |
| Transportation Expenses | (3,236) | (1,495) | (632) | (497) | (1,070) | |
| Operating Netback(1)(5) | $35,103 | $12,492 | $8,936 | $4,021 | $10,378 | |
| Capital Expenditures (Before Changes in Working Capital) | $62,275 | $102,377 | $16,197 | $31,416 | $15,474 | |
| Average Daily Production (BOEPD) | ||||||
| WI Production Before Royalties | 4,854 | 2,477 | 6,898 | 3,705 | 3,872 | |
| Royalties | (1,497) | (881) | (1,925) | (1,213) | (1,273) | |
| Production NAR | 3,357 | 1,596 | 4,973 | 2,492 | 2,599 | |
| Increase (Decrease) in Inventory | (569) | (507) | (2,572) | (957) | 1,054 | |
| Sales | 2,788 | 1,089 | 2,401 | 1,535 | 3,653 | |
| Royalties, % of WI Production Before Royalties | 31% | 36% | 28% | 33% | 33% | |
| Operating Netback ($/boe)(1)(5) | ||||||
| Gross Profit6 | $3.50 | $3.24 | $9.24 | $2.99 | $1.90 | |
| Depletion and Accretion7 | 18.94 | 14.08 | 13.21 | 12.91 | 21.00 | |
| Operating Netback(1)(5) | $22.44 | $17.33 | $22.45 | $15.90 | $22.90 | |
| Brent | $68.19 | $79.86 | $63.08 | $74.01 | $68.17 | |
| Quality and Transportation Discount | (6.66) | (11.06) | (6.56) | (10.09) | (6.88) | |
| Royalties | (21.50) | (30.78) | (25.15) | (28.22) | (15.83) | |
| Average Realized Price | 40.03 | 38.02 | 31.37 | 35.70 | 45.46 | |
| Transportation Expenses | (2.07) | (2.07) | (1.59) | (1.97) | (2.36) | |
| Average Realized Price Net of Transportation Expenses | 37.96 | 35.95 | 29.78 | 33.73 | 43.10 | |
| Operating Expenses | (15.52) | (18.62) | (7.33) | (17.83) | (20.20) | |
| Operating Netback(1)(5) | $22.44 | $17.33 | $22.45 | $15.90 | $22.90 | |
| Canadian Information | Year Ended, | Three Months Ended, | ||||
| December 31, | December 31, | December 31, | December 31, | September 30, | ||
| 2025 | 2024 | 2025 | 2024 | 2025 | ||
| Operating Netback(1)(5) | ||||||
| Gross Profit6 | $7,255 | $(304) | $38 | $(304) | $3,574 | |
| Depletion and Accretion7 | 48,579 | 8,938 | 13,595 | 8,938 | 8,348 | |
| Operating Netback(1)(5) | $55,834 | $8,634 | $13,633 | $8,634 | $11,922 | |
| Oil Sales | $84,769 | $14,832 | $19,785 | $14,832 | $21,884 | |
| Natural Gas Sales | 23,940 | 3,546 | 4,026 | 4,193 | 4,314 | |
| NGL Sales | 20,275 | 4,193 | 7,477 | 3,546 | 3,702 | |
| Royalties | (13,291) | (3,616) | (2,917) | (3,616) | (3,250) | |
| Oil, Natural Gas and NGL Sales After Royalties | $115,693 | $18,955 | $28,371 | $18,955 | $26,650 | |
| Operating Expenses | (58,576) | (9,649) | (14,345) | (9,649) | (14,403) | |
| Transportation Expenses | (1,283) | (672) | (393) | (672) | (325) | |
| Operating Netback(1)(5) | $55,834 | $8,634 | $13,633 | $8,634 | $11,922 | |
| Capital Expenditures (Before Changes in Working Capital) | $44,096 | $18,114 | $3,712 | $18,114 | $9,228 | |
| Average Daily Production | ||||||
| Crude Oil (bbl/d) | 4,049 | 627 | 4,220 | 2,486 | 4,013 | |
| Natural Gas (mcf/d) | 48,840 | 8,274 | 46,158 | 32,814 | 49,260 | |
| NGLs (bbl/d) | 4,496 | 847 | 4,274 | 3,358 | 3,889 | |
| WI Production Before Royalties (BOEPD) | 16,685 | 2,853 | 16,187 | 11,313 | 16,112 | |
| Royalties (BOEPD) | (2,083) | (394) | (1,942) | (1,566) | (1,969) | |
| Production NAR (BOEPD) | 14,602 | 2,459 | 14,245 | 9,747 | 14,143 | |
| Sales (BOEPD) | 14,602 | 2,459 | 14,245 | 9,747 | 14,143 | |
| Royalties, % of WI Production Before Royalties | 12% | 14% | 12% | 14% | 12% | |
| Benchmark Prices | ||||||
| West Texas Intermediate ($/bbl) | $64.87 | $69.62 | $59.24 | $69.62 | $65.07 | |
| AECO Natural Gas Price (C$/GJ) | $1.59 | $1.56 | $2.11 | $1.56 | $0.60 | |
| Average Realized Price | ||||||
| Crude Oil ($/bbl) | $57.35 | $64.86 | $50.96 | $64.86 | $59.28 | |
| Natural Gas ($/mcf) | $1.34 | $1.17 | $1.76 | $1.17 | $0.82 | |
| NGLs ($/bbl) | $12.36 | $13.57 | $10.24 | $13.57 | $12.06 | |
| Operating Netback ($/boe)(1)(5) | ||||||
| Gross Profit6 | $1.19 | $(0.29) | $0.03 | $(0.29) | $2.41 | |
| Depletion and Accretion7 | 7.98 | 8.59 | 9.13 | 8.59 | 5.63 | |
| Operating Netback(1)(5) | $9.17 | $8.30 | $9.16 | $8.30 | $8.04 | |
| Average Realized Price | $21.18 | $21.69 | $21.01 | $21.69 | $20.17 | |
| Royalties | (2.18) | (3.47) | (1.96) | (3.47) | (2.19) | |
| Transportation Expenses | (0.21) | (0.65) | (0.26) | (0.65) | (0.22) | |
| Operating Expenses | (9.62) | (9.27) | (9.63) | (9.27) | (9.72) | |
| Operating Netback(1)(5) | $9.17 | $8.30 | $9.16 | $8.30 | $8.04 | |
| As at December 31 | ||||||
| ($000s) | 2025 | 2024 | % Change | |||
| Cash and cash equivalents | $ | 82,931 | $ | 103,379 | (20 | ) |
| Credit facility | $ | — | $ | — | — | |
| Senior Notes | $ | 740,541 | $ | 786,619 | (6 | ) |
Additional information on 2025 expenses:
- Quality and Transportation Discount: increased in 2025 to $24.78 per boe compared to $17.93 per boe in 2024 as a result of a change in production mix, driven by the full integration of Canadian operations acquired in October 2024.
- Transportation Expenses: decreased by 29% to $1.04 per boe in 2025 from $1.47 per boe in 2024 as a result of higher sales volumes transported in Ecuador, two months of transportation of sales volumes in Canada through pipelines, and an increase in trucking tariffs for Acordionero volumes in 2025.
- Royalties: decreased to $7.02 per boe in 2025, from $12.33 per boe in 2024. This decrease was driven by the 15% decrease in the Brent oil price in 2025 relative to 2024 and the price sensitive royalty regime in Colombia and Ecuador.
1 Operating netback, EBITDA, Adjusted EBITDA, funds flow from operations, net debt, free cash flow, and cash netback, are non-GAAP measures and do not have a standardized meaning under GAAP. Cash flow refers to the GAAP line item “net cash provided by operating activities”. Refer to “Non-GAAP Measures” in this press release for descriptions of these non-GAAP measures and reconciliations to the most directly comparable measures calculated and presented in accordance with GAAP.
2 The after-tax net present value 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 should be consulted for information at the Company level.
3 NAV per share is calculated as NPV10 (before or after tax, as applicable) of the applicable reserves category minus net debt, divided by the number of shares of Gran Tierra’s common stock issued and outstanding.
4 Outstanding shares of common stock based on December 31, 2025 balance of 35,298,774 shares of common stock.
5 Per boe amounts are based on WI sales before royalties. For per boe amounts based on NAR production, see Gran Tierra’s Annual Report on Form 10-K filed on March 4, 2026.
6 Gross profit is calculated as oil, gas and NGL sales, less operating and transportation expenses, and depletion and accretion related to producing assets.
7 Depletion and Accretion is calculated as DD&A expenses less depreciation of administrative assets.
8 Proforma Net Debt is based on $616 million outstanding of Senior Notes less $83 million of cash and cash equivalents as at December 31, 2025.
Conference Call Information
Gran Tierra will host its fourth quarter and full year 2025 results conference call on Wednesday March 4, 2026, at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time, and 4:00 p.m. Greenwich Mean Time. Interested parties may register for the conference call at the following link: https://register-conf.media-server.com/register/BIea135c3b51d44c9cb4d060ac04b977dd. Please note that there is no longer a general dial-in number to participate and each individual party must register through the provided link. Once parties have registered, they will be provided a unique PIN and call-in details. There is also a feature that allows parties to elect to be called back through the “Call Me” function on the platform. Interested parties can also continue to access the live webcast from their mobile or desktop devices at the following link: https://edge.media-server.com/mmc/p/ruvvrgwq, which is also available on Gran Tierra’s website at https://www.grantierra.com/investor-relations/presentations-events/.
About Gran Tierra Energy Inc.
Gran Tierra Energy Inc., together with its subsidiaries, is an independent international energy company currently focused on oil and natural gas exploration and production in Canada, Colombia and Ecuador. The Company is currently developing its existing portfolio of assets in Canada, Colombia and Ecuador; however, we have recently entered into an exploration, development and production sharing agreement with SOCAR and may eventually expand our operations into Azerbaijan and will continue to pursue additional new growth opportunities that would further strengthen the Company’s portfolio. The Company’s common stock trades on the NYSE American, the Toronto Stock Exchange and the London Stock Exchange under the ticker symbol GTE. Additional information concerning Gran Tierra is available at www.grantierra.com. Except to the extent expressly stated otherwise, information on the Company’s website or accessible from our website or any other website is not incorporated by reference into and should not be considered part of this press release. Investor inquiries may be directed to info@grantierra.com or (403) 265-3221.
Gran Tierra’s Securities and Exchange Commission (the “SEC”) filings are available on the SEC website at http://www.sec.gov. The Company’s Canadian securities regulatory filings are available on SEDAR+ at http://www.sedarplus.ca and UK regulatory filings are available on the National Storage Mechanism website at https://data.fca.org.uk/#/nsm/nationalstoragemechanism.
Contact Information
For investor and media inquiries please contact:
Gary Guidry, President & Chief Executive Officer
Ryan Ellson, Executive Vice President & Chief Financial Officer
Tel: +1.403.265.3221
For more information on Gran Tierra please go to: www.grantierra.com.
Forward Looking Statements and Legal Advisories:
This press release contains opinions, forecasts, projections, and other statements about future events or results that constitute forward-looking statements within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, and financial outlook and forward looking information within the meaning of applicable Canadian securities laws (collectively, “forward- looking statements”), which can be identified by such terms as “believe,” “expect,” “anticipate,” “forecast,” “budget,” “will,” “estimate,” “target,” “project,” “plan,” “should,” “guidance,” “outlook,” “strives” or similar expressions are forward-looking statements. Such forward-looking statements include, but are not limited to, the Company’s strategies and expectations, capital program, drilling plans, cost saving initiatives, future sources of funding for capital expenditures and other activities, future planned operations and production estimates, forecast prices, and the Company’s plans to benefit the environment or communities in which it operates. Statements relating to “reserves” are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, including that the reserves described can be profitably produced in the future.
The forward-looking statements contained in this press release reflect several material factors and expectations and assumptions of Gran Tierra including, without limitation, that Gran Tierra will continue to conduct its operations in a manner consistent with its current expectations, the ability of Gran Tierra to realize the anticipated benefits and operating synergies expected from the acquisition of i3 Energy, the accuracy of testing and production results and seismic data, pricing and cost estimates (including with respect to commodity pricing and exchange rates), rig availability, the risk profile of planned exploration activities, the effects of drilling down-dip, the 5-year weighted-average Brent forecast, the effects of waterflood and multi-stage fracture stimulation operations, the extent and effect of delivery disruptions, and the general continuance of current or, where applicable, assumed operational, regulatory and industry conditions in Canada, Colombia, Ecuador, and Azerbaijan and areas of potential expansion, and the ability of Gran Tierra to execute its business and operational plans in the manner currently planned, such as the expected effectiveness of the EDPSA in Azerbaijan and the timing and execution of the related exploration program. Gran Tierra believes the material factors, expectations and assumptions reflected in the forward-looking statements are reasonable at this time but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
Among the important factors that could cause actual results to differ materially from those indicated by the forward-looking statements in this press release are: our operations are located in South America and unexpected problems can arise due to guerilla activity, strikes, local blockades or protests; technical difficulties and operational difficulties may arise which impact the production, transport or sale of our products; other disruptions to local operations; global health events; global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and gas, including inflation and changes resulting from a global health crisis, geopolitical events, including the ongoing conflicts in Ukraine, the Middle East and Venezuela, or from the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC and other producing countries and resulting company or third-party actions in response to such changes; changes in commodity prices, including volatility or a prolonged decline in these prices relative to historical or future expected levels; the risk that current global economic and credit conditions may impact oil and natural gas prices and oil and natural gas consumption more than we currently predict, which could cause further modification of our strategy and capital spending program; prices and markets for oil and natural gas are unpredictable and volatile; the effect of hedges; the accuracy of productive capacity of any particular field; geographic, political and weather conditions can impact the production, transport or sale of our products; our ability to execute our business plan, which may include acquisitions, and realize expected benefits from current or future initiatives; the risk that unexpected delays and difficulties in developing currently owned properties may occur; the ability to replace reserves and production and develop and manage reserves on an economically viable basis; the accuracy of testing and production results and seismic data, pricing and cost estimates (including with respect to commodity pricing and exchange rates); the risk profile of planned exploration activities; the effects of drilling down-dip; the effects of waterflood and multi-stage fracture stimulation operations; the extent and effect of delivery disruptions, equipment performance and costs; actions by third parties; the timely receipt of regulatory or other required approvals for our operating activities; the failure of exploratory drilling to result in commercial wells; unexpected delays due to the limited availability of drilling equipment and personnel; volatility or declines in the trading price of our common stock or bonds; the risk that we do not receive the anticipated benefits of government programs, including government tax refunds; our ability to comply with financial covenants in its credit agreement and indentures and make borrowings under any credit agreement; and the risk factors detailed from time to time in Gran Tierra’s periodic reports filed with the Securities and Exchange Commission, including, without limitation, under the caption “Risk Factors” in Gran Tierra’s Annual Report on Form 10-K for the year ended December 31, 2025 filed March 4, 2026 and its other filings with the SEC. These filings are available on the SEC website at http://www.sec.gov and on SEDAR+ at www.sedarplus.ca. Although the current guidance, capital spending program and long term strategy of Gran Tierra are based upon the current expectations of the management of Gran Tierra, should any one of a number of issues arise, Gran Tierra may find it necessary to alter its business strategy and/or capital spending program and there can be no assurance as at the date of this press release as to how those funds may be reallocated or strategy changed and how that would impact Gran Tierra’s results of operations and financial position. Forecasts and expectations that cover multi-year time horizons or are associated with 2P reserves inherently involve increased risks and actual results may differ materially.
All forward-looking statements are made as of the date of this press release and the fact that this press release remains available does not constitute a representation by Gran Tierra that Gran Tierra believes these forward-looking statements continue to be true as of any subsequent date. Actual results may vary materially from the expected results expressed in forward-looking statements. Gran Tierra disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as expressly required by applicable law. In addition, historical, current and forward-looking sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future.
Non-GAAP Measures
This press release includes non-GAAP financial measures as further described herein. These non-GAAP measures do not have a standardized meaning under GAAP. Investors are cautioned that these measures should not be construed as alternatives to net income or loss, cash flow from operating activities or other measures of financial performance as determined in accordance with GAAP. Gran Tierra’s method of calculating these measures may differ from other companies and, accordingly, they may not be comparable to similar measures used by other companies. Each non-GAAP financial measure is presented along with the corresponding GAAP measure so as not to imply that more emphasis should be placed on the non-GAAP measure.
Net Debt, as presented as at December 31, 2025 is comprised of $741 million (gross) of senior notes outstanding less cash and cash equivalents of $83 million, prepared in accordance with GAAP. Management believes that net debt is a useful supplemental measure for management and investors in order to evaluate the financial sustainability of the Company’s business and leverage. The most directly comparable GAAP measure is total debt.
Operating netback, as presented, is defined as gross profit less depletion and accretion related to producing assets. Operating netback per boe, as presented, is defined as operating netback over WI sales volume. Cash netback, as presented, is most directly comparable to gross profit and is calculated as gross profit adjusted for depletion and accretion related to producing assets, cash G&A expenses, transaction costs, export tax, realized foreign exchange gains or losses, cash settlement on derivative instruments, interest expense excluding amortization of debt issuance costs, interest income, other cash gains or losses, net lease payments, and current income tax expense or recovery. Cash netback per boe, as presented, is defined as cash netback over WI sales volumes. Management believes that operating netback and cash netback are useful supplemental measures for investors to analyze financial performance and provide an indication of the results generated by Gran Tierra’s principal business activities prior to the consideration of other income and expenses. See the table entitled Financial and Operational Highlights above for the components of operating netback and operating netback per boe. A reconciliation from net income or loss to cash netback is as follows:
| Year Ended | Three Months Ended | |||||||||||||||||||
| December 31, | December 31, | September 30, | ||||||||||||||||||
| Operating and Cash Netback - Non-GAAP Measure ($000s) | 2025 | 2024 | 2025 | 2024 | 2025 | |||||||||||||||
| Gross profit | $ | 66,419 | $ | 182,637 | $ | 851 | $ | 22,180 | $ | 14,670 | ||||||||||
| Adjustments to reconcile net (loss) income to operating netback | ||||||||||||||||||||
| Depletion and accretion | 264,522 | 218,417 | 68,236 | 60,061 | 61,908 | |||||||||||||||
| Operating netback (non-GAAP) | 330,941 | 401,054 | 69,087 | 82,241 | 76,578 | |||||||||||||||
| Cash G&A expenses | (56,873 | ) | (41,431 | ) | (16,817 | ) | (10,191 | ) | (13,453 | ) | ||||||||||
| Transaction costs | — | (5,907 | ) | — | (4,448 | ) | — | |||||||||||||
| Export tax | (3,287 | ) | — | (657 | ) | — | (2,630 | ) | ||||||||||||
| Realized foreign exchange (loss) gain | (7,694 | ) | 915 | (2,792 | ) | 273 | (2,149 | ) | ||||||||||||
| Cash settlement on derivative instruments | 10,292 | 1,103 | 757 | 1,103 | 7,461 | |||||||||||||||
| Interest expense, excluding amortization of debt issuance costs | (82,341 | ) | (67,548 | ) | (21,477 | ) | (20,009 | ) | (21,178 | ) | ||||||||||
| Interest income | 1,090 | 3,666 | 217 | 1,273 | 197 | |||||||||||||||
| Other cash gain | 1,645 | 1,478 | — | 1,478 | 1,268 | |||||||||||||||
| Net lease payments | (152 | ) | 888 | (114 | ) | 264 | (387 | ) | ||||||||||||
| Current income tax (expense) recovery | (15,859 | ) | (69,277 | ) | (1,377 | ) | (7,855 | ) | (4,022 | ) | ||||||||||
| Cash netback (non-GAAP) | $ | 177,762 | $ | 224,941 | $ | 26,827 | $ | 44,129 | $ | 41,685 | ||||||||||
EBITDA, as presented, is defined as net income (loss) adjusted for DD&A expenses, interest expense, and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for asset impairment, non-cash lease expense, lease payments, foreign exchange gains or losses, unrealized derivative instruments gains or losses, transaction costs, other non-cash gains or losses, and stock-based compensation expense. Management uses this supplemental measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income, and believes that this financial measure is a useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net income or loss or loss to EBITDA and adjusted EBITDA is as follows:
| Year Ended | Three Months Ended | |||||||||||||||||||
| December 31, | December 31, | September 30, | ||||||||||||||||||
| EBITDA - Non-GAAP Measure ($000s) | 2025 | 2024 | 2025 | 2024 | 2025 | |||||||||||||||
| Net (loss) income | $ | (193,119 | ) | $ | 3,216 | $ | (141,148 | ) | $ | (34,210 | ) | $ | (19,950 | ) | ||||||
| Adjustments to reconcile net (loss) income to EBITDA and Adjusted EBITDA | ||||||||||||||||||||
| DD&A expenses | 278,353 | 230,619 | 72,535 | 63,406 | 64,981 | |||||||||||||||
| Interest expense | 101,309 | 80,466 | 28,261 | 23,752 | 25,447 | |||||||||||||||
| Income tax expense | (39,753 | ) | 41,389 | (36,678 | ) | 12,299 | (11,276 | ) | ||||||||||||
| EBITDA (non-GAAP) | $ | 146,790 | $ | 355,690 | $ | (77,030 | ) | $ | 65,247 | $ | 59,202 | |||||||||
| Asset impairment | 136,261 | — | 136,261 | — | — | |||||||||||||||
| Non-cash lease expense | 5,821 | 5,923 | 1,173 | 1,759 | 1,187 | |||||||||||||||
| Lease payments | (5,973 | ) | (5,035 | ) | (1,287 | ) | (1,495 | ) | (1,574 | ) | ||||||||||
| Foreign exchange gain | 8,734 | (8,808 | ) | 896 | (496 | ) | 284 | |||||||||||||
| Unrealized derivative instruments (gain) loss | (8,633 | ) | 3,374 | (7,669 | ) | 3,374 | 9,527 | |||||||||||||
| Transaction costs | — | 5,907 | — | 4,448 | — | |||||||||||||||
| Other non-cash (gain) loss | (2,558 | ) | — | (2,913 | ) | — | 265 | |||||||||||||
| Stock-based compensation expense | 3,214 | 9,707 | 3,042 | 3,331 | 143 | |||||||||||||||
| Adjusted EBITDA (non-GAAP) | $ | 283,656 | $ | 366,758 | $ | 52,473 | $ | 76,168 | $ | 69,034 | ||||||||||
Funds flow from operations, as presented, is defined as net income (loss) adjusted for DD&A expenses, asset impairment, deferred tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, non-cash interest, non-cash lease expense, lease payments, unrealized foreign exchange gains or losses, unrealized derivative instruments gains or losses, and other non-cash gains or losses. Management uses this financial measure to analyze performance and income or loss generated by our principal business activities prior to the consideration of how non-cash items affect that income or loss, and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. Free cash flow, as presented, is defined as funds flow from operations adjusted for capital expenditures. Management uses this financial measure to analyze cash flow generated by our principal business activities after capital requirements and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net income or loss to funds flow from operations and free cash flow is as follows:
| Year Ended | Three Months Ended | |||||||||||||||||||
| December 31, | December 31, | September 30, | ||||||||||||||||||
| Funds Flow From Operations - Non-GAAP Measure ($000s) | 2025 | 2024 | 2025 | 2024 | 2025 | |||||||||||||||
| Net (loss) income | $ | (193,119 | ) | $ | 3,216 | $ | (141,148 | ) | $ | (34,210 | ) | $ | (19,950 | ) | ||||||
| Adjustments to reconcile net (loss) income to funds flow from operations | ||||||||||||||||||||
| DD&A expenses | 278,353 | 230,619 | 72,535 | 63,406 | 64,981 | |||||||||||||||
| Asset impairment | 136,261 | — | 136,261 | — | — | |||||||||||||||
| Deferred tax (recovery) expense | (55,612 | ) | (27,888 | ) | (38,055 | ) | 4,444 | (15,298 | ) | |||||||||||
| Stock-based compensation expense | 3,214 | 9,707 | 3,042 | 3,331 | 143 | |||||||||||||||
| Amortization of debt issuance costs | 16,943 | 12,918 | 4,759 | 3,743 | 4,269 | |||||||||||||||
| Non-cash interest | 2,025 | — | 2,025 | — | — | |||||||||||||||
| Non-cash lease expense | 5,821 | 5,923 | 1,173 | 1,759 | 1,187 | |||||||||||||||
| Lease payments | (5,973 | ) | (5,035 | ) | (1,287 | ) | (1,495 | ) | (1,574 | ) | ||||||||||
| Unrealized foreign exchange loss (gain) | 1,040 | (7,893 | ) | (1,896 | ) | (223 | ) | (1,865 | ) | |||||||||||
| Other non-cash (gain) loss | (2,558 | ) | — | (2,913 | ) | — | 265 | |||||||||||||
| Unrealized derivative instruments (gain) loss | (8,633 | ) | 3,374 | (7,669 | ) | 3,374 | 9,527 | |||||||||||||
| Funds flow from operations (non-GAAP) | $ | 177,762 | $ | 224,941 | $ | 26,827 | $ | 44,129 | $ | 41,685 | ||||||||||
| Capital expenditures | $ | 256,277 | $ | 248,103 | $ | 53,040 | $ | 78,579 | $ | 57,340 | ||||||||||
| Free cash flow (non-GAAP) | $ | (78,515 | ) | $ | (23,162 | ) | $ | (26,213 | ) | $ | (34,450 | ) | $ | (15,655 | ) | |||||
DISCLOSURE OF OIL AND GAS INFORMATION
Gran Tierra’s Statement of Reserves Data and Other Oil and Gas Information on Form 51-101F1 dated effective as at December 31, 2025, which includes disclosure of its 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, is available on SEDAR+ at www.sedarplus.ca. All reserves values, future net revenue and ancillary information contained in this press release as of December 31, 2025 are derived from the GTE McDaniel Reserves Report, unless expressly stated. Any reserves values or related information contained in this press release as of a date other than December 31, 2025 has an effective date of December 31 of the applicable year and is derived from a report prepared by Gran Tierra’s independent qualified reserves evaluator as of such date and have been prepared in compliance with NI 51-101 and the COGEH.
Estimates of net present value and future net revenue contained herein do not necessarily represent fair market value of reserves. 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 McDaniel in evaluating Gran Tierra’s reserves and future net revenue will be attained and variances could be material. See Gran Tierra’s press release dated January 28, 2026 for a summary of the price forecasts employed by McDaniel in the GTE McDaniel Reserves Report and other information regarding the disclosed future net revenue.
All evaluations of future net revenue contained in the GTE McDaniel Reserves Report are 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. It should not be assumed that the estimates of future net revenue presented in this press release represent the fair market value of the reserves. There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth in the GTE McDaniel Reserves Report are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided therein.
Boes have been converted on the basis of six thousand cubic feet (“Mcf”) natural gas to 1 boe of oil. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the current price of oil as compared with natural gas is significantly different from the energy equivalent of six to one, utilizing a boe conversion ratio of 6 Mcf: 1 boe would be misleading as an indication of value.
References to a formation where evidence of hydrocarbons has been encountered is not necessarily an indicator that hydrocarbons will be recoverable in commercial quantities or in any estimated volume. Gran Tierra’s reported production is a mix of light crude oil and medium, heavy crude oil, tight oil, conventional natural gas, shale gas and natural gas liquids for which there is no precise breakdown since the Company’s sales volumes typically represent blends of more than one product type. Drilling locations disclosed herein are derived from the GTE McDaniel Reserves Report and account for drilling locations that have associated Proved Undeveloped and Proved plus Probable Undeveloped reserves, as applicable. Well test results should be considered as preliminary and not necessarily indicative of long-term performance or of ultimate recovery. Well log interpretations indicating oil and gas accumulations are not necessarily indicative of future production or ultimate recovery. If it is indicated that a pressure transient analysis or well-test interpretation has not been carried out, any data disclosed in that respect should be considered preliminary until such analysis has been completed. References to thickness of “oil pay” or of a formation where evidence of hydrocarbons has been encountered is not necessarily an indicator that hydrocarbons will be recoverable in commercial quantities or in any estimated volume.
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 and taxes 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 | |||||||||||||
| 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) |
4,479 | (883 | ) | (1,443 | ) | (882 | ) | (31 | ) | 1,240 | (280 | ) | 960 |
| Remainder | 3,167 | (589 | ) | (1,413 | ) | (5 | ) | (345 | ) | 815 | (212 | ) | 603 |
| Total (Undiscounted) | 7,645 | (1,472 | ) | (2,856 | ) | (888 | ) | (376 | ) | 2,053 | (492 | ) | 1,561 |
| 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 | |||||||||
Definitions
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.
Possible reserves are those additional reserves that are less certain to be recovered than Probable reserves. It is unlikely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable plus possible reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of 3P reserves.
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.
Developed non-producing reserves are those reserves that either have not been on production or have previously been on production but are shut-in and the date of resumption of production is unknown.
Undeveloped 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 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 Metrics
This press release contains a number of oil and gas metrics, including NAV per share, operating netback, cash netback, reserves replacement, and reserve life index which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods.
- NAV per share is calculated as the applicable NPV10 (before or after-tax, as applicable) of the applicable reserves category minus estimated net debt, divided by the number of shares of Gran Tierra’s common stock issued and outstanding. Management uses NAV per share as a measure of the relative change of Gran Tierra’s net asset value over its outstanding common stock over a period of time.
- Operating netback and cash netback are calculated as described in this press release. Management believes that operating netback and cash netback are useful supplemental measures for the reasons described in this press release.
- Reserves replacement is calculated as reserves in the referenced category divided by estimated referenced production. Management uses this measure to determine the relative change of its reserves base over a period of time.
- Reserve life index is calculated as reserves in the referenced category divided by the referenced production. Management uses this measure to determine how long the booked reserves will last at current production rates if no further reserves were added.
Disclosure of Reserve Information and Cautionary Note to U.S. Investors
Unless expressly stated otherwise, all estimates of proved developed producing, proved, probable and possible reserves and related future net revenue disclosed in this press release have been prepared in accordance with NI 51-101. Estimates of reserves and future net revenue made in accordance with NI 51-101 will differ from corresponding GAAP standardized measures prepared in accordance with applicable SEC rules and disclosure requirements of the U.S. Financial Accounting Standards Board (“FASB”), and those differences may be material. NI 51-101, for example, requires disclosure of reserves and related future net revenue estimates based on forecast prices and costs, whereas SEC and FASB standards require that reserves and related future net revenue be estimated using average prices for the previous 12 months and that the standardized measure reflect discounted future net income taxes related to the Company’s operations. In addition, NI 51-101 permits the presentation of reserves estimates on a “company gross” basis, representing Gran Tierra’s working interest share before deduction of royalties, whereas SEC and FASB standards require the presentation of net reserve estimates after the deduction of royalties and similar payments. There are also differences in the technical reserves estimation standards applicable under NI 51-101 and, pursuant thereto, the COGEH, and those applicable under SEC and FASB requirements.
In addition to being a reporting issuer in certain Canadian jurisdictions, Gran Tierra is a registrant with the SEC and subject to domestic issuer reporting requirements under U.S. federal securities law, including with respect to the disclosure of reserves and other oil and gas information in accordance with U.S. federal securities law and applicable SEC rules and regulations (collectively, “SEC requirements”). Disclosure of such information in accordance with SEC requirements is included in the Company’s Annual Report on Form 10-K and in other reports and materials filed with or furnished to the SEC and, as applicable, Canadian securities regulatory authorities. The SEC permits oil and gas companies that are subject to domestic issuer reporting requirements under U.S. federal securities law, in their filings with the SEC, to disclose only estimated proved, probable and possible reserves that meet the SEC’s definitions of such terms. Gran Tierra has disclosed estimated proved, probable and possible reserves in its filings with the SEC. In addition, Gran Tierra prepares its financial statements in accordance with United States generally accepted accounting principles, which require that the notes to its annual financial statements include supplementary disclosure in respect of the Company’s oil and gas activities, including estimates of its proved oil and gas reserves and a standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. This supplementary financial statement disclosure is presented in accordance with FASB requirements, which align with corresponding SEC requirements concerning reserves estimation and reporting.
The Company believes that the presentation of NPV10 is useful to investors because it presents (i) relative monetary significance of its oil and natural gas properties regardless of tax structure and (ii) relative size and value of its reserves to other companies. The Company also uses this measure when assessing the potential return on investment related to its oil and natural gas properties. NPV10 and the standardized measure of discounted future net cash flows do not purport to present the fair value of the Company’s oil and gas reserves. The Company has not provided a reconciliation of NPV10 to the standardized measure of discounted future net cash flows because it is impracticable to do so.
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