Gran Tierra Energy Inc. Reports Second Quarter 2025 Results & Another Quarter of Record Production

Achieved Record Total Company Average Quarterly Production of 47,196 boepdFunds Flow From Operations(1) of $54 million, Adjusted EBITDA(1) of $77 million and Return to Free Cash FlowSigned Mandate Letter for Funding of Up to $200 MillionEntered into Binding Agreement to Exit the UK North Sea Achieved Company Record Total of 32 Million Hours Without a Lost Time InjuryRecorded Operating Costs per boe of $13.42 for the Quarter - the Lowest Since The First Quarter of 2022 CALGARY, Alberta, July 30, 2025 (GLOBE NEWSWIRE) -- Gran Tierra Energy Inc. (“Gran Tierra” or the “Company”) (NYSE American:GTE) (TSX:GTE) (LSE: GTE) announced the Company’s financial and operating results for the quarter ended June 30, 2025 (the “Quarter”) and provided an operational update. 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. For per boe amounts based on net after royalty (“NAR”) production, see Gran Tierra’s Quarterly Report on Form 10-Q filed July 30, 2025. Message to Shareholders Gary Guidry, President and Chief Executive Officer of Gran Tierra, commented: “Gran Tierra delivered record-setting production this quarter, reflecting the strength of our diversified portfolio and consistent operational execution across Colombia, Ecuador, and Canada. In Ecuador, we are building on the momentum of our Iguana Block discoveries with the planned drilling of two high-impact exploration wells in the Charapa Block later this year. In Colombia, the successful development drilling at Costayaco and Cohembi, along with the strong early waterflood response in Cohembi’s north area, underscores the ongoing potential of our core assets and validates our disciplined approach to reservoir management. In Acordionero, our proactive waterflood management, surface facility upgrades, pump upsizes and ongoing improvement in electrical submersible pump run lives continue to mitigate base decline. In Canada, our Montney and Clearwater assets are delivering encouraging results, with three gross-wells (1.2 net) brought on stream in the Quarter, outperforming expectations. These outcomes further reinforce our strategy of disciplined capital allocation and balanced growth as we focus on generating long-term value for our stakeholders. We continue to optimize our portfolio with the signed disposition of the UK North Sea assets, which is expected to close in the third quarter of 2025.” Operational Update: Safety: Since 2022, Gran Tierra has achieved a record of 32 million person-hours equating to more than 3 years without a lost time injury.Ecuador Building on the successful discoveries in the Iguana Block during the first quarter of 2025, civil works are currently underway to support the drilling of the final two wells under Gran Tierra’s exploration commitments in the country. These wells are planned for the Charapa Block in the Conejo prospect, with drilling expected to commence toward the end of the third quarter of 2025. Colombia Gran Tierra successfully drilled the first of three development wells planned for 2025 in the northern area of the Costayaco field. The Costayaco-63 well was perforated in four productive sands, stimulated, and placed on immediate production. The well is currently producing ~800 bbls of oil per day (“bopd”) with a 48% watercut compared to an average field watercut of 92%. In July, the second well—Costayaco-64—was drilled, stimulated and completed. The well is currently producing ~1,300 bopd with a 13% watercut. The final well, Costayaco-65, was spud on July 20, 2025 and is scheduled to be brought on production in August 2025.During the Quarter the remaining two wells of the 2025 five well Cohembi program were brought onto production. The average drilling cost of the five wells was ~$3.0 million per well, representing a 47% reduction from the prior operator’s average last five wells drilled in 2017/18. As part of the program and to support pressure, water injection began on May 30, 2025. A strong waterflood response and increase of greater than 2,600 bopd gross across the northern part of the field has been observed and continues to improve.The Cristobal well in LLA-85 was drilled below budget to total depth (“TD”) and abandoned, fulfilling all the commitments on the block.In Acordionero, production in the Quarter averaged ~14,200 bopd compared to ~13,800 bopd in the first quarter of 2025 (the “Prior Quarter”). Increases in base production were achieved by increasing total fluid production through planned electrical submersible pump upsizes, additional surface injection capacity allowing for continued growth of total fluid production and water injection. Record highs were achieved in both total fluid production (~89,400 bbls/day) and water injection (~85,000 bbls/day) during the Quarter. Canada In the Simonette, the first two (1.0 net) Lower Montney wells were completed successfully and brought on stream on April 5, 2025. Results from both wells are currently out-performing management’s current type curves. The third Montney well was spud on June 29, 2025 and reached TD on July 18, 2025. The fourth Montney well was spud on July 22, 2025 and is expected to reach total depth in the first half of August. Enhanced Liquidity: Gran Tierra is pleased to announce it has signed a mandate letter with a syndicate of banks for a $200 million prepayment facility backed by crude oil deliveries. The Company is progressing toward full documentation, with closing expected in the third quarter of 2025 and funding anticipated shortly thereafter. The facility is structured to enhance financial flexibility, support long-term capital planning, and optimize the Company’s debt maturity profile. Further details of the prepayment will be announced in due course once final terms are agreed upon.Separately, Gran Tierra recently completed the semi-annual redetermination of its Canadian credit facility, with lenders confirming an unchanged borrowing base of C$100 million. This outcome reflects the continued strength and stability of the Company’s Canadian asset base. The facility provides C$50 million in available commitments, comprised of a C$35 million syndicated facility and a C$15 million operating facility with a maturity date of October 31, 2026. The next redetermination is scheduled on or before November 30, 2025.Gran Tierra also employs a disciplined, risk-managed hedging strategy designed to protect cash flow, support capital planning, and enhance financial stability across commodity cycles. The Company utilizes a diversified mix of oil and gas hedges that provide downside protection while preserving upside exposure. This proactive approach contributed to a $14 million derivative hedging gain booked during the Quarter. The Company also maintains a rolling 12-month hedging program to further mitigate volatility: South American Oil Hedges (Brent): For the second half of 2025, Gran Tierra has hedged approximately 50% of its South American oil production with a weighted average floor of $63.16 per barrel and a ceiling of $76.50 per barrel. For the first half of 2026 the Company has hedged approximately 33% of its South American oil production with a weighted average floor of $61.67 per barrel and a ceiling of $75.58.Canadian Oil Hedges (West Texas Intermediate): For the second half of 2025, Gran Tierra has hedged approximately 60% of its Canadian oil production with a weighted average floor of $61.67 per barrel and a ceiling of $72.37 per barrel. For the first half of 2026 the Company has hedged approximately 50% of its Canadian oil production with a weighted average floor of $56.82 per barrel and a ceiling of $72.01.Canadian Gas Hedges (AECO): For the second half of 2025, Gran Tierra has hedged approximately 40% of its Canadian gas production with a weighted average floor of $2.82 per GJ and a ceiling of $2.96 per GJ.FX Hedges (COP to USD): Starting in April 2025, Gran Tierra entered into a 12-month, $10 million per month hedging program for the COP to USD exchange rate. The hedges have a floor of 4,430 and a ceiling of 4,705. Key Highlights of the Quarter: Production: Gran Tierra’s total average WI production was 47,196 boepd, which was 44% higher than the second quarter of 2024 due to the production from the Canadian operations acquired on October 31, 2024 and positive exploration well drilling results in Ecuador. Total average WI production was 1% higher than the Prior Quarter as a result of successful drilling in Simonette, Cohembi infill drilling and waterflood management, strong Acordionero performance and continued exploration success in Ecuador from the Iguana wells. Working interest sales in the Quarter decreased to 45,727 boepd primarily due to the deferral of 143,730 barrels of Ecuador oil production, which were held in inventory at the end of June and subsequently sold in July.Net Income (Loss): Gran Tierra incurred a net loss of $13 million, compared to a net loss of $19 million in the Prior Quarter and net income of $36 million in the second quarter of 2024.Adjusted EBITDA(1): Adjusted EBITDA(1) was $77 million compared to $85 million in the Prior Quarter and $103 million in the second quarter of 2024. Twelve-month trailing net debt(1) to adjusted EBITDA(1) was 2.3 times (only accounts for eight months of Canadian operations adjusted EBITDA) and the Company continues to have a long-term target ratio of 1.0 times.Funds Flow from Operations(1): Funds flow from operations(1) was $54 million ($1.53 per share), up 17% from the second quarter of 2024 and down 3% from the Prior Quarter. Brent price decreased by 11% per bbl compared to the Prior Quarter and our cash netback(1) decreased by 1% illustrating the resiliency of the portfolio.Net Cash Provided by Operating Activities: Net cash provided by operating activities was $35 million ($0.98 per share), down 53% from the Prior Quarter and down 53% from the second quarter of 2024.Cash and Debt: As of June 30, 2025, the Company had a cash balance of $61 million, total debt of $807 million and net debt(1) of $746 million. During the Quarter, the Company drew a total of $45 million on its credit facilities to fund capital expenditures. There were significant capital expenditures in the first quarter, amounting to approximately 40% of budgeted capital expenditures for the year, which were paid in the Quarter resulting in the Company drawing on its credit facilities. We currently forecast the facilities to have a zero balance by the end of the year. In addition to the $61 million cash on hand as of June 30, 2025, the Company currently has approximately $112 million in credit and lending facilities with $47 million drawn as of June 30, 2025.Share Buybacks: Gran Tierra repurchased 239,754 shares of common stock during the Quarter. From January 1, 2023, to July 28, 2025, the Company repurchased approximately 5.2 million shares, or 15% of shares issued and outstanding on January 1, 2023. Additional Key Financial Metrics: Capital Expenditures: Capital expenditures were $51 million during the Quarter which were lower than the $95 million in the Prior Quarter and lower than $61 million in the second quarter of 2024. During the Quarter the majority of capital expenditures were incurred in Colombia on Cohembi drilling and infrastructure.Oil, Natural Gas and Natural Gas Liquids (“NGL”) Sales: Gran Tierra generated sales of $152 million, down 8% from the second quarter of 2024 primarily as a result of a 22% decrease in Brent pricing, partially offset by 43% higher sales volumes due to higher production and lower Castilla, Oriente, and Vasconia oil differentials. Oil sales decreased 11% from the Prior Quarter primarily due to an 11% decrease in Brent price, partially offset by lower Castilla, Oriente, and Vasconia oil differentials.South American Quality and Transportation Discounts: The Company’s quality and transportation discounts in South America per bbl were lower during the Quarter at $10.30, compared to $11.58 in the Prior Quarter and $12.79 in the second quarter of 2024. The Castilla oil differential per bbl tightened to $4.73, down from $5.34 in the Prior Quarter and $8.21 in the second quarter of 2024 (Castilla is the benchmark for the Company’s Middle Magdalena Valley Basin oil production). The Vasconia differential per bbl tightened to $1.71, down from $2.27 in the Prior Quarter, and $4.00 in the second quarter of 2024. The Ecuadorian benchmark, Oriente, per bbl was $7.26, down from $7.65 in the Prior Quarter and $8.38 in the second quarter of 2024. The current(2) differentials are approximately $4.38 per bbl for Castilla, $1.38 per bbl for Vasconia, and $7.64 per bbl for Oriente.Operating Expenses: On a per boe basis, operating expenses decreased by 17% when compared to the second quarter of 2024 and 16% when compared to the Prior Quarter, primarily due to lower workover activities and lower lifting costs associated with inventory build-up in Ecuador, power generation, and equipment rentals. This was the lowest operating expense per boe achieved since the first quarter of 2022. Total operating expenses decreased by 17% to $56 million, compared to the Prior Quarter, largely driven by lower workover activities and reduced lifting costs related to power generation, equipment rental, and inventory fluctuation in Ecuador. Compared to the second quarter of 2024, total operating expenses increased by 19% from $47 million, primarily due to the addition of Canadian operations and the ramp-up of activity in Ecuador. The increase in total operating costs is commensurate with the 44% increase in production.Transportation Expenses: The Company’s transportation expenses increased by 10% to $8 million, compared to the Prior Quarter’s transportation expenses of $7 million as a result of incremental sales volumes transported by Canadian operations resulting in higher tolls. When compared to the second quarter of 2024 transportation expenses increased from $6 million due to new Canadian operations, higher sales volumes transported in Ecuador, partially offset by lower sales volumes transported in Colombia.Operating Netback(1)(3): The Company’s operating netback(1)(3) was $21.39 per boe, down 6% from the Prior Quarter and down 45% from the second quarter of 2024, primarily as a result of a decrease in oil pricing. The decrease from the second quarter of 2024 is a result in the change in the Company’s production mix with the addition of the Canadian assets.General and Administrative (“G&A”) Expenses: G&A expenses before stock-based compensation were $3.48 per boe, up from $2.86 per boe in the Prior Quarter, due to the timing of certain annual corporate expenses. G&A expenses before stock-based compensation were down from $3.77 per boe, compared to the second quarter of 2024 as a result of higher sales volumes from the inclusion of Canadian operations in the Quarter.Cash Netback(1): Cash netback(1) per boe decreased to $12.95, compared to $13.04 in the Prior Quarter, primarily as a result of lower operating netback(1) and were offset by lower current income tax expense and positive cash settlement on derivative instruments. Compared to one year ago, cash netback(1) per boe decreased by $2.90 from $15.85 per boe as a result of lower operating netback(1) while being offset by lower current tax expense. Financial and Operational Highlights (all amounts in $000s, except per share and boe amounts) Consolidated Financial DataThree Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, 20252024 2025 20252024 Net (Loss) Income$(12,741)$36,371 $(19,280) $(32,021)$36,293Per Share - Basic and Diluted$(0.36)$1.16 $(0.54) $(0.90)$1.15 Oil, Natural Gas and NGL Sales$152,481$165,609 $170,533 $323,014$323,186Operating Expenses(55,855)(47,035) (67,354) (123,209)(95,501)Transportation Expenses(7,618)(5,690) (6,911) (14,529)(10,274)Operating Netback (1)(3)$89,008$112,884 $96,268 $185,276$217,411 G&A Expenses Before Stock-Based Compensation$14,460$10,967 $12,143 $26,603$21,749G&A Stock-Based Compensation Expense (Recovery)5466,160 (517) 299,521G&A Expenses, Including Stock Based Compensation$15,006$17,127 $11,626 $26,632$31,270 Adjusted EBITDA (1)$76,987$103,004 $85,162 $162,149$197,796 EBITDA (1)$84,908$101,187 $79,710 $164,618$193,078 Net Cash Provided by Operating Activities$34,677$73,233 $73,230 $107,907$134,060 Funds Flow from Operations (1)$53,906$46,167 $55,344 $109,250$120,474 Capital Expenditures (Before Changes in Working Capital)$51,170$61,273 $94,727 $145,897$116,604 Free Cash Flow (1)$2,736$(15,106) $(39,383) $(36,647)$3,870 Average Daily Production (boe/d) WI Production Before Royalties47,19632,776 46,647 46,92332,509Royalties(7,396)(6,774) (8,084) (7,738)(6,586)Production NAR39,80026,002 38,563 39,18525,923Decrease (Increase) in Inventory(1,469)(811) 461 (509)(288)Sales38,33125,191 39,024 38,67625,635Royalties, % of WI Production Before Royalties16%21% 17% 16%20% Cash Netback ($/boe )(1) Average Realized Price before Royalties43.7172.24 48.55 46.1469.27Royalties(7.07)(15.31) (8.33) (7.69)(14.16)Average Realized Price36.6456.93 40.22 38.4555.11Transportation Expenses(1.83)(1.96) (1.63) (1.73)(1.75)Average Realized Price Net of Transportation Expenses34.8154.97 38.59 36.7253.36Operating Expenses(13.42)(16.17) (15.89) (14.67)(16.29)Operating Netback (1)(3)21.3938.80 22.70 22.0537.07G&A Expenses Before Stock-Based Compensation(3.48)(3.77) (2.86) (3.17)(3.71)Realized Foreign Exchange (Loss) Gain(0.14)0.37 (0.51) (0.33)(0.06)Cash Settlement on Derivative Instruments0.39— 0.10 0.25—Interest Expense, Excluding Amortization of Debt Issuance Costs(4.87)(5.38) (4.58) (4.72)(5.24)Interest Income0.060.35 0.10 0.080.29Other Gain0.09— — 0.04—Net Lease Payments0.040.02 0.04 0.040.07Current Income Tax Expense(0.53)(14.54) (1.95) (1.25)(7.88)Cash Netback (1)$12.95$15.85 $13.04 $12.99$20.54 Share Information (000s) Common Stock Outstanding, End of Period35,28931,022 35,524 35,28931,022Weighted Average Number of Shares of Common Stock Outstanding - Basic and Diluted35,33531,282 35,777 35,55531,547 South American Operational InformationThree Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, 20252024 2025 20252024Operating Netback (1)(3) Oil Sales$118,187$165,609 $138,671 $256,858$323,186Operating Expenses(42,554)(47,035) (50,827) (93,381)(95,501)Transportation Expenses(4,176)(5,690) (4,304) (8,480)(10,274)Operating Netback (1)(3)$71,457$112,884 $83,540 $154,997$217,411 Capital Expenditures (Before Changes in Working Capital)$49,327$60,806 $64,984 $114,311$116,137 Average Daily Production (boe/d) WI Production Before Royalties29,70032,776 29,686 29,69332,509Royalties(5,209)(6,774) (5,844) (5,525)(6,586)Production NAR24,49126,002 23,842 24,16825,923Decrease (Increase) in Inventory(1,469)(811) 461 (509)(288)Sales23,02225,191 24,303 23,65925,635Royalties, % of WI Production Before Royalties18%21% 20% 19%20% Operating Netback ($/boe) (1)(3) Brent$66.71$85.03 $74.98 $70.81$83.42Quality and Transportation Discount(10.30)(12.79) (11.58) (10.82)(14.15)Royalties(10.41)(15.31) (12.29) (11.36)(14.16)Average Realized Price46.0056.93 51.11 48.6355.11Transportation Expenses(1.63)(1.96) (1.59) (1.61)(1.75)Average Realized Price Net of Transportation Expenses44.3754.97 49.52 47.0253.36Operating Expenses(16.56)(16.17) (18.73) (17.68)(16.29)Operating Netback (1)(3)$27.81$38.80 $30.79 $29.34$37.07 Canadian Operational Information (4)Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, 20252024 2025 20252024Operating Netback (1)(3) Oil Sales$23,196$— $21,269 $44,465$—Natural Gas Sales6,894— 7,561 14,455—NGL Sales6,364— 7,997 14,361—Royalties(2,158)— (4,966) (7,124)—Oil, Natural Gas and NGL Sales After Royalties$34,296$— $31,861 $66,157$—Operating Expenses(13,301)— (16,527) (29,828)—Transportation Expenses(3,442)— (2,607) (6,049)—Operating Netback (1)(3)$17,553$— $12,727 $30,280$— Capital Expenditures (Before Changes in Working Capital)$1,796$— $29,360 $31,156$— Average Daily Production Crude Oil (bbl/d)4,335— 3,623 3,981—Natural Gas (mcf/d)50,124— 49,860 49,992—NGLs (bbl/d)4,807— 5,029 4,917—WI Production Before Royalties (boe/d)17,496— 16,961 17,230—Royalties (boe/d)(2,187)— (2,240) (2,213)—Production NAR (boe/d)15,309— 14,721 15,017—Sales (boe/d)15,309— 14,721 15,017—Royalties, % of WI Production Before Royalties13%—% 13% 13%—% Benchmark Prices West Texas Intermediate ($/bbl)63.8180.82 71.47 67.6078.95AECO Natural Gas Price (C$/GJ)1.601.12 2.05 1.821.74 Average Realized Price Crude Oil ($/bbl)58.80— 65.23 61.71—Natural Gas ($/mcf)1.51— 1.69 1.60—NGLs ($/bbl)14.55— 17.67 16.14— Operating Netback ($/boe) (1)(3) Average Realized Price$22.90$— $24.12 $23.50$—Royalties(1.36)— (3.25) (2.28)—Transportation Expenses(2.16)— (1.71) (1.94)—Operating Expenses(8.35)— (10.83) (9.56)—Operating Netback (1)(3)$11.03$— $8.33 $9.72$— (1) Funds flow from operations, operating netback, net debt, cash netback, earnings before interest, taxes and depletion, depreciation and accretion (“DD&A”) (“EBITDA”) and EBITDA adjusted for non-cash lease expense, lease payments, foreign exchange gains or losses, stock-based compensation expense, other gains or losses, transaction costs and financial instruments gains or losses (“Adjusted EBITDA”), cash flow and free cash flow are non-GAAP measures and do not have standardized meanings under generally accepted accounting principles in the United States of America (“GAAP”). Cash flow refers to funds flow from operations. Free cash flow refers to funds flow from operations less capital expenditures. Refer to “Non-GAAP Measures” in this press release for descriptions of these non-GAAP measures and, where applicable, reconciliations to the most directly comparable measures calculated and presented in accordance with GAAP.(2) Gran Tierra’s third quarter-to-date 2025 total average differentials and average production are for the period from July 1 to July 30, 2025.(3) Operating netback as presented is defined as oil sales less operating and transportation expenses. See the table titled Financial and Operational Highlights above for the components of consolidated operating netback and corresponding reconciliation.(4) Gran Tierra entered Canada with the acquisition of i3 Energy which closed October 31, 2024, therefore no comparative data is provided for the corresponding periods of 2024. Conference Call Information: Gran Tierra will host its second quarter 2025 results conference call on Thursday, July 31, 2025, at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time. Interested parties may access the conference call by registering at the following link: https://register-conf.media-server.com/register/BId33e377f2b494c3c95a7fbd1df59627e. The call will also be available via webcast at www.grantierra.com. Corporate Presentation: Gran Tierra’s Corporate Presentation has been updated and is available on the Company website at www.grantierra.com. Contact Information For investor and media inquiries please contact: Gary Guidry President & Chief Executive Officer Ryan Ellson Executive Vice President & Chief Financial Officer +1-403-265-3221 info@grantierra.com 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 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. 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”). All statements other than statements of historical facts included in this press release regarding our business strategy, plans and objectives of our management for future operations, capital spending plans and benefits of the changes in our capital program or expenditures, our liquidity and financial condition, and those statements preceded by, followed by or that otherwise include the words “expect,” “plan,” “can,” “will,” “should,” “guidance,” “forecast,” “budget,” “estimate,” “signal,” “progress”, “anticipates” and “believes,” derivations thereof and similar terms identify forward-looking statements. In particular, but without limiting the foregoing, this press release contains forward-looking statements regarding: : the Company’s expectations regarding committed funding (including but not limited to the signing of a mandate for prepayment structure backed by crude oil deliveries), liquidity and its leverage ratio target, the Company’s plans regarding strategic investments, acquisitions, dispositions, synergies, and growth, the Company’s drilling program and capital expenditures and the Company’s expectations of commodity prices, exploration and production trends and its positioning for 2025. 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, pricing and cost estimates (including with respect to commodity pricing and exchange rates), the general continuance of assumed operational, regulatory and industry conditions in Canada, Colombia and Ecuador, and the ability of Gran Tierra to execute its business and operational plans in the manner currently planned. Among the important factors that could cause our actual results to differ materially from the forward-looking statements in this press release include, but are not limited to: our ability to successfully integrate the assets and operations of i3 Energy Plc (“i3Energy”) and realize the anticipated benefits and operating synergies expected from the 2024 acquisition of i3 Energy; certain of 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 actual or anticipated tariffs and trade policies, global health crises, geopolitical events, including the conflicts in Ukraine and the Middle East, 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 the 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 prices and oil 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 access debt or equity capital markets from time to time to raise additional capital, increase liquidity, fund acquisitions or refinance debt; the risk that we are unable to successfully negotiate final terms and close an anticipated prepayment structure backed by crude oil deliveries, our ability to comply with financial covenants in our indentures and make borrowings under our credit agreements; 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, 2024 filed February 24, 2025 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. The forward-looking statements contained in this press release are based on certain assumptions made by Gran Tierra based on management’s experience and other factors believed to be appropriate. Gran Tierra believes these assumptions to be reasonable at this time, but the forward-looking statements are subject to risk and uncertainties, many of which are beyond Gran Tierra’s control, which may cause actual results to differ materially from those implied or expressed by the forward looking statements. The risk that the assumptions on which the 2025 outlook are based prove incorrect may increase the later the period to which the outlook relates. 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. The forecasts of expected liquidity to address bond amortization in the fourth quarter of 2026 and that Gran Tierra’s credit facilities would have a zero balance by the end of the year may be considered to be future-oriented financial information or a financial outlook for the purposes of applicable Canadian securities laws. Financial outlook and future-oriented financial information contained in this press release about prospective financial performance, financial position or cash flows are provided to give the reader a better understanding of the potential future performance of the Company in certain areas and are based on assumptions about future events, including economic conditions and proposed courses of action, based on management’s assessment of the relevant information currently available, and to become available in the future. In particular, this press release contains projected operational and financial information for the end of 2025 and the fourth quarter of 2026. These projections contain forward-looking statements and are based on a number of material assumptions and factors set out above. Actual results may differ significantly from the projections presented herein. The actual results of Gran Tierra’s operations for any period could vary from the amounts set forth in these projections, and such variations may be material. See above for a discussion of the risks that could cause actual results to vary. The future-oriented financial information and financial outlooks contained in this press release have been approved by management as of the date of this press release. Readers are cautioned that any such financial outlook and future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. The Company and its management believe that the prospective financial information has been prepared on a reasonable basis, reflecting management’s best estimates and judgments, and represent, to the best of management’s knowledge and opinion, the Company’s expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results. 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 to not imply that more emphasis should be placed on the non-GAAP measure. Operating netback, as presented, is defined as oil sales less operating and transportation expenses. See the table entitled Financial and Operational Highlights above for the components of consolidated operating netback and corresponding reconciliation. Cash netback as presented is defined as net income or loss adjusted for DD&A expenses, deferred tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss, other gain or loss and unrealized derivative instruments gain or loss. 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. A reconciliation from net income or loss to cash netback is as follows: Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30,Cash Netback - (Non-GAAP) Measure ($000s) 2025 2024 2025 2025 2024 Net (Loss) Income$(12,741)$36,371 $(19,280) $(32,021)$36,293 Adjustments to reconcile net loss or income to cash netback DD&A expenses 68,635 55,490 72,202 140,837 111,640 Deferred tax expense (recovery) 2,453 (51,361) (4,712) (2,259) (37,882)Stock-based compensation expense (recovery) 546 6,160 (517) 29 9,521 Amortization of debt issuance costs 4,082 2,760 3,833 7,915 6,066 Non-cash lease expense 1,725 1,381 1,736 3,461 2,794 Lease payments (1,545) (1,311) (1,567) (3,112) (2,369)Unrealized foreign exchange loss (gain) 3,114 (3,323) 1,687 4,801 (5,589)Other loss 38 — 52 90 — Unrealized derivative instrument (gain) loss (12,401) — 1,910 (10,491) — Cash netback$53,906 $46,167 $55,344 $109,250 $120,474 EBITDA, as presented, is defined as net income or loss adjusted for DD&A expenses, interest expense and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for non-cash lease expense, lease payments, foreign exchange gain or loss, stock-based compensation expense or recovery, other gain or loss and unrealized derivative instruments gain or loss. 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 useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net income or loss to EBITDA and adjusted EBITDA is as follows: Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, Twelve Month Trailing June 30,EBITDA - (Non-GAAP) Measure ($000s) 2025 2024 2025 2025 2024 2025 Net (Loss) Income$(12,741)$36,371 $(19,280) $(32,021)$36,293 $(65,098)Adjustments to reconcile net loss or income to EBITDA and Adjusted EBITDA DD&A expenses 68,635 55,490 72,202 140,837 111,640 259,816 Interest expense 24,366 18,398 23,235 47,601 36,822 91,245 Income tax expense (recovery) 4,648 (9,072) 3,553 8,201 8,323 41,267 EBITDA$84,908 $101,187 $79,710 $164,618 $193,078 $327,230 Non-cash lease expense 1,725 1,381 1,736 3,461 2,794 6,590 Lease payments (1,545) (1,311) (1,567) (3,112) (2,369) (5,778)Foreign exchange loss (gain) 3,716 (4,413) 3,838 7,554 (5,228) 3,974 Stock-based compensation expense (recovery) 546 6,160 (517) 29 9,521 215 Other loss 38 — 52 90 — 90 Unrealized derivative instrument (gain) loss (12,401) — 1,910 (10,491) — (7,117)Adjusted EBITDA$76,987 $103,004 $85,162 $162,149 $197,796 $325,204 Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, deferred tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss, other gain or loss and unrealized gain or loss on derivative instruments. 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 both funds flow from operations and free cash flow is as follows: Three Months Ended June 30, Three Months Ended March 31, Six Months Ended June 30, Twelve Month Trailing June 30,Funds Flow From Operations - (Non-GAAP) Measure ($000s) 2025 2024 2025 2025 2024 2025 Net (Loss) Income$(12,741)$36,371 $(19,280) $(32,021)$36,293 $(65,098)Adjustments to reconcile net loss or income to funds flow from operations DD&A expenses 68,635 55,490 72,202 140,837 111,640 259,816 Deferred tax expense (recovery) 2,453 (51,361) (4,712) (2,259) (37,882) 7,735 Stock-based compensation expense (recovery) 546 6,160 (517) 29 9,521 215 Amortization of debt issuance costs 4,082 2,760 3,833 7,915 6,066 14,767 Non-cash lease expense 1,725 1,381 1,736 3,461 2,794 6,590 Lease payments (1,545) (1,311) (1,567) (3,112) (2,369) (5,778)Unrealized foreign exchange loss (gain) 3,114 (3,323) 1,687 4,801 (5,589) 2,497 Other loss 38 — 52 90 — 90 Unrealized derivative instrument (gain) loss (12,401) — 1,910 (10,491) — (7,117)Funds flow from operations$53,906 $46,167 $55,344 $109,250 $120,474 $213,717 Capital expenditures$51,170 $61,273 $94,727 $145,897 $116,604 $285,471 Free cash flow$2,736 $(15,106) $(39,383) $(36,647)$3,870 $(71,754) Net debt as of June 30, 2025, was $746 million, calculated using the sum of the aggregate principal amount of 7.75% Senior Notes, 9.50% Senior Notes outstanding and amount drawn on credit facilities, excluding deferred financing fees, totaling $807 million, less cash and cash equivalents of $61 million. 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. Presentation of Oil and Gas Information 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. 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. This press release contains certain oil and gas metrics, including operating netback and cash netback, 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. These metrics are calculated as described in this press release and management believes that they are useful supplemental measures for the reasons described in this press release. 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.

Gran Tierra Energy Inc. Reports Second Quarter 2025 Results & Another Quarter of Record Production

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