Gran Tierra Energy Inc. Reports Third Quarter 2025 Results and Announces Further Exploration Success in Ecuador | GTE Stock News

10/30/2025 - 05:20 PM Gran Tierra Secures $200 Million Prepayment Facility Highlighting Strength of Portfolio Increase and Extension of Canadian Credit Facility Three Major Ecuador Discoveries Add to the Existing Success in Country Colombia’s Southern Putumayo Cohembi Field Achieves Highest Production in a Decade CALGARY, Alberta, Oct. 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 September30, 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 October30, 2025. Message to Shareholders “The Third Quarter showcased continued operational success across our portfolio. In Ecuador, we achieved further exploration success with the Conejo A-1 and A-2 wells and confirmed a new discovery at Chanangue-1, all of which highlight the significant potential of our acreage position. We also recently cased and cemented the Conejo A-2 well, targeting multiple prospective reservoirs including the Basal Tena and Hollin. The well discovered 41 feet of net reservoir with an average porosity of 13.8% in the Hollin formation suggesting well-connected reservoir quality over the full Conejo structural trap. In Colombia, new wells at Costayaco continued to perform well, and the Cohembi field delivered a strong waterflood response, with production reaching levels not seen in over a decade. In Canada, we successfully drilled and brought two additional Lower Montney wells onstream, both meeting or exceeding expectations. Production during the Quarter was temporarily impacted primarily by externally driven events, including a landslide in Ecuador that required the shut in of all Ecuador production for several weeks and trunk line repairs at the Moqueta field which resulted in the field being shut in for the Quarter. These volumes represent deferred bbls rather than lost production, and we are already seeing a strong recovery, with current production(2) averaging approximately 45,200 boepd. Based on the deferrals, we are forecasting the lower end of our production guidance range. The underlying assets continue to perform well, and our teams remain focused on ongoing optimization and maximizing production efficiency and cash flow with an expected exit rate of 47,000 to 50,000 boepd. We completed a number of initiatives to enhance liquidity and will be releasing our 2026 budget in mid December which will focus on free cash flow generation. The 2025 capital program was focused on fulfilling exploration commitments, which resulted in numerous material discoveries, and facility construction primarily in the Suroriente Block. With substantially all commitments behind us, the focus turns to free cash flow generation from our substantial, diversified resource base and deleveraging,” commented Gary Guidry, President and Chief Executive Officer of Gran Tierra Energy. Operational Update: Ecuador Another successful exploration well, Conejo A-1 was drilled during the Quarter on budget. The well was subsequently completed and tested the Hollin and Basal Tena sands. The Basal Tena and Hollin oil zones perforated over 19 feet (“ft”) and 40 ft of reservoir, respectively. Under natural flow conditions, the well has produced at stabilized rates over 308 hours at 1,328 bbls of oil per day (“bopd”), 26.9-degree API gravity oil, a 23.7% water cut, and a gas-oil ratio of 289 standard cubic feet per stock tank barrel. During the fourth quarter, the Company plans to re-enter the well to install the final completion and conduct selective testing of each zone to optimize total well production. The Conejo A-2 well was spud on October 4, 2025, targeting multiple prospective reservoirs including the Basal Tena and Hollin. The well included coring of key intervals to further evaluate reservoir characteristics and potential. The Conejo A-2 well discovered 41 ft of net reservoir with an average porosity of 13.8% in the Hollin formation. Of particular interest is the outstanding reservoir quality suggesting high deliverability over the full Conejo structural trap.With the delivery of the Conejo A-2 well, Gran Tierra has completed all of the Exploration commitments in Ecuador and we are now well-positioned to continue to increase production into the development phase and establish our long-term growth position in Ecuador. A new oil discovery was made in the legacy Chanangue-1 well drilled in 1990 and suspended in 1992 on the Chanangue Block. The well was re-entered to test the previously bypassed Basal Tena formation, which was subsequently perforated and brought online. The well is currently producing approximately 600 bopd on jet pump. This discovery highlights significant reserve potential and is expected to generate additional future drilling opportunities on the eastern side of the Chanangue Block. Colombia During the Quarter, Gran Tierra’s development program in the northern area of the Costayaco field continued to perform well, with all three new wells contributing to production growth. The Costayaco-63, -64, and -65 wells were drilled and brought onstream between late June to mid-August, achieving average initial 30-day oil rates ranging from approximately 600 to 1,100 bopd with water cuts between 25% and 70%. Combined production from these wells during the Quarter averaged approximately 1,700 bopd with an average water cut of around 60%, helping sustain stable field output. We are currently changing the artificial lift system from jet pump to electronic submersible pumps which is expected to add an incremental 1,000 - 1,500 bopd.Cohembi continues to deliver a strong waterflood response, with the five development wells drilled during the first half of 2025. Output from the northern area has increased by approximately 135%, rising from 2,800 to 6,700 gross bopd, with additional gains anticipated. Total field production has now exceeded 9,000 gross bopd – levels not achieved since 2014. Drilling has commenced a 6-well program which includes the Raju-1 exploration well, the 2nd well in the program, which is expected to spud in early November. The Raju-1 exploration well will be targeting a large prospective area north of the current development. We expect to have initial results from this well prior to year end 2025. Canada Two additional Lower Montney wells were drilled, completed, and brought on stream in September, bringing total 2025 activity in Simonette to 4.0 gross (2.0 net) wells. Initial production performance has been very encouraging, with one well exceeding high-case expectations and another tracking closely to the base case and still cleaning up. Capital Structure Optimization: Executed Oriente Crude Oil Agreements providing for an initial advance of up to $150 million and an additional $50 million, to be repaid through scheduled deliveries of Ecuadorian Oriente crude oil; proceeds are expected to be used to repay debt and fund select capital initiatives.Amended Colombian credit facility to align with the new prepayment structure, enhancing financial flexibility, reducing standby costs, and optimizing Gran Tierra’s overall capital structure.Subsequent to the Quarter, the Company amended and restated the existing credit agreement of Gran Tierra Canada Ltd. (“GT Canada”) pursuant to a second amended and restated credit agreement dated October 30, 2025 to, among other things, increase the total available borrowing capacity available under its credit facilities (the “Canadian Credit Facilities”) from C$50.0 million to C$75.0 million. Other key amendments to the Canadian Credit Facilities as a result of such amendment and restatement are summarized as follows: The tenor of the Canadian Credit Facilities was extended by one year and converted from a “one year revolving facility with a one year term-out period” into a “two year revolving facility” with a maturity date of October 31, 2027;GT Canada’s lender completed its semi-annual borrowing base review, which resulted in the borrowing base remaining at C$100.0 million; andThe existing uncommitted accordion feature (which contemplates a further increase of the Canadian Credit Facilities) was reduced from C$50.0 million to C$25.0 million. Key Highlights of the Quarter: Production: Gran Tierra’s total average WI production was 42,685 boepd, which was 30% higher than the third 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 10% lower than the quarter ended June 30, 2025 (the “Prior Quarter”) primarily as a result of a landslide in Ecuador that required the shut in of all Ecuador production for several weeks and trunk line repairs at the Moqueta field which resulted in the field being shut in for the Quarter. Working interest sales in the Quarter were 44,077 boepd primarily due to the recognition of 143,730 bbls of Ecuador oil production, which were held in inventory at the end of June and subsequently sold in July.Current Production: The Company’s current average production(2) has been approximately 45,200 boepd.Net Income (Loss): Gran Tierra incurred a net loss of $20 million, compared to a net loss of $13 million in the Prior Quarter and net income of $1 million in the third quarter of 2024.Adjusted EBITDA(1): Adjusted EBITDA(1) was $69 million compared to $77 million in the Prior Quarter and $93 million in the third quarter of 2024.Funds Flow from Operations(1): Funds flow from operations(1) was $42 million ($1.18 per share), down 31% from the third quarter of 2024 and down 23% from the Prior Quarter.Net Cash Provided by Operating Activities: Net cash provided by operating activities was $48 million ($1.36 per share), up 39% from the Prior Quarter and down 39% from the third quarter of 2024.Cash and Debt: As of September30, 2025, the Company had a cash balance of $49 million, total debt of $804 million and net debt(1) of $755 million. During the Quarter, the Company repaid a total of $2 million of its credit facility. In addition to the $49 million cash on hand as of September 30, 2025, the Company currently has approximately $67 million of undrawn capacity with $111 million in credit and lending facilities and $44 million drawn as of September 30, 2025. Additional Key Financial Metrics: Capital Expenditures: Capital expenditures were $57 million during the Quarter which were higher than the $51 million in the Prior Quarter and higher than $53 million in the third quarter of 2024. During the Quarter, the majority of capital expenditures incurred in Colombia and Ecuador related to planned exploration drilling and infrastructure spend in Cohembi, and in Canada for the drilling and completion of two Simonette wells (1.0 net).Oil, Natural Gas and Natural Gas Liquids (“NGL”) Sales: Gran Tierra generated sales of $149 million, down 1% from the third quarter of 2024 primarily as a result of a 13% decrease in Brent pricing, partially offset by 37% higher sales volumes due to higher production and lower Castilla, Oriente, and Vasconia oil differentials. Oil sales remained consistent when compared to the Prior Quarter primarily due to a 2% increase in Brent price and lower Oriente oil differentials, partially offset by higher Castilla and Vasconia oil differentials, and lower sales volumes.South American Quality and Transportation Discounts: The Company’s quality and transportation discounts in South America per bbl were slightly higher during the Quarter at $10.76, compared to $10.30 in the Prior Quarter and $14.10 in the third quarter of 2024. The Castilla oil differential per bbl was $4.88, up slightly from $4.73 in the Prior Quarter and down $8.83 in the third quarter of 2024 (Castilla is the benchmark for the Company’s Middle Magdalena Valley Basin oil production). The Vasconia differential per bbl was $1.88, slightly up from $1.71 in the Prior Quarter, and down from $5.07 in the third quarter of 2024. The Ecuadorian benchmark, Oriente, per bbl was $7.20, down from $7.26 in the Prior Quarter and down from $9.15 in the third quarter of 2024. The current(5) differentials are approximately $5.79 per bbl for Castilla, $2.79 per bbl for Vasconia, and $7.66 per bbl for Oriente.Operating Expenses: Total operating expenses increased by 22% to $68 million and on a per boe basis increased 26% when compared to the Prior Quarter as a result of higher workover activities and lifting costs associated with inventory fluctuations in Ecuador. When compared to the third quarter of 2024 total operating expenses increased by 48% from $46 million and on a per boe basis they increased by 9% as a result of new Canadian operations and ramp-up of operations in Ecuador.Transportation Expenses: The Company’s transportation expenses decreased by 4% to $4.3 million, compared to the Prior Quarter’s transportation expenses of $4.5 million as a result of lower sales volumes transported in Colombia. When compared to the third quarter of 2024 transportation expenses increased from $3.9 million due to the new Canadian operations, higher sales volumes transported in Ecuador partially offset by lower sales volumes transported in Colombia.Gross Profit: During the Quarter gross profit decreased 70% to $14.7 million compared to $48.8 million in the third quarter of 2024 and 36% from $23.1 million in the Prior Quarter. On a per boe basis gross profit was $3.62 compared to $16.45 in the third quarter of 2024 and $5.54 compared to the Prior Quarter.Operating Netback(1)(3): The Company’s operating netback(1)(3) was $18.89 per boe, down 12% from the Prior Quarter and primarily as a result of an increase in operating expenses and a decrease in sales volumes. Operating netback(1)(3) was down 45% when compared to the third quarter of 2024 primarily as a result of a decrease in pricing.General and Administrative (“G&A”) Expenses: G&A expenses before stock-based compensation were $3.32 per boe, down from $3.48 per boe in the Prior Quarter, due to lower business development costs. G&A expenses before stock-based compensation were up from $3.20 per boe, compared to the third quarter of 2024 as a result of higher costs in the depletable base for Ecuador and the new Canadian operations.Cash Netback(1): Cash netback(1) per boe decreased to $10.28, compared to $12.95 in the Prior Quarter, primarily as a result of lower operating netback(1) and were offset by positive cash settlement of derivative instruments. Compared to one year ago, cash netback(1) per boe decreased by $10.06 from $20.34 per boe as a result of lower operating netback(1) while being offset by lower current tax expense by positive cash settlement of derivative instruments. Financial and Operational Highlights (all amounts in $000s, except per share and boe amounts) Consolidated Financial DataThree Months Ended September 30,Three Months Ended June 30,Nine Months Ended September 30,20252024202520252024Net (Loss) Income$(19,950)$1,133$(12,741)$(51,971)$37,426Per Share – Basic and Diluted$(0.57)$0.04$(0.36)$(1.47)$1.20Gross Profit$14,670$48,803$23,061$65,568$160,457Depletion and Accretion(*)61,90852,59965,947196,286158,356Operating Netback(1)(3)$76,578$101,402$89,008$261,854$318,813Oil, Natural Gas and NGL Sales$149,254$151,373$149,357$466,784$474,559Operating Expenses(68,379)(46,060)(55,855)(191,588)(141,561)Transportation Expenses(4,297)(3,911)(4,494)(13,342)(14,185)Operating Netback(1)(3)$76,578$101,402$89,008$261,854$318,813G&A Expenses Before Stock-Based Compensation$13,453$9,491$14,460$40,056$31,240G&A Stock-Based Compensation Expense (Recovery)143(3,145)5461726,376G&A Expenses, Including Stock Based Compensation$13,596$6,346$15,006$40,228$37,616Adjusted EBITDA(1)$69,034$92,794$76,987$231,183$290,590EBITDA(1)$59,202$97,365$84,908$223,820$290,443Net Cash Provided by Operating Activities$48,149$78,654$34,677$156,056$212,714Funds Flow from Operations(1)$41,685$60,338$53,906$150,935$180,812Capital Expenditures (Before Changes in Working Capital)$57,340$52,921$51,170$203,237$169,525Free Cash Flow(1)$(15,655)$7,417$2,736$(52,302)$11,287Average Daily Production (boe/d)WI Production Before Royalties42,68532,76447,19645,49532,595Royalties(6,723)(6,776)(7,396)(7,396)(6,650)Production NAR35,96225,98839,80038,09925,945Decrease (Increase) in Inventory1,391(524)(1,469)132(367)Sales37,35325,46438,33138,23125,578Royalties, % of WI Production Before Royalties16%21%16%16%20%Cash Netback ($/boe)(1)Gross Profit3.6216.455.545.2618.17Depletion and Accretion(*)15.2717.7315.8515.7617.93Operating Netback(1)(3)18.8934.1821.3921.0236.10Average Realized Price before Royalties43.4464.6142.8244.7267.71Royalties(6.63)(13.58)(6.93)(7.25)(13.97)Average Realized Price36.8151.0335.8937.4753.74Transportation Expenses(1.06)(1.32)(1.08)(1.07)(1.61)Average Realized Price Net of Transportation Expenses35.7549.7134.8136.4052.13Operating Expenses(16.86)(15.53)(13.42)(15.38)(16.03)Operating Netback(1)(3)18.8934.1821.3921.0236.10G&A Expenses Before Stock-Based Compensation(3.32)(3.20)(3.48)(3.22)(3.54)Transaction Costs—(0.49)——(0.17)Export Tax(0.65)——(0.21)—Realized Foreign Exchange (Loss) Gain(0.53)0.34(0.14)(0.39)0.07Cash Settlement on Derivative Instruments1.84—0.390.77—Interest Expense, Excluding Amortization of Debt Issuance Costs(5.22)(5.66)(4.87)(4.89)(5.38)Interest Income0.050.230.060.070.27Other Gain0.31—0.090.13—Net Lease Payments(0.10)0.070.04—0.07Current Income Tax Expense(0.99)(5.13)(0.53)(1.16)(6.96)Cash Netback(1)$10.28$20.34$12.95$12.12$20.46Share Information (000s)Common Stock Outstanding, End of Period35,29631,02235,28935,29631,022Weighted Average Number of Shares of Common Stock Outstanding – Basic and Diluted35,29130,73335,33535,46631,274 South American Operational InformationThree Months Ended September 30,Three Months Ended June 30,Nine Months Ended September 30,20252024202520252024Operating Netback(1)(3)Gross Profit$11,096$48,803$19,210$58,351$160,457Depletion and Accretion(*)53,56052,59952,247161,302158,356Operating Netback(1)(3)$64,656$101,402$71,457$219,653$318,813Oil Sales$122,604$151,373$118,187$379,462$474,559Operating Expenses(53,976)(46,060)(42,554)(147,357)(141,561)Transportation Expenses(3,972)(3,911)(4,176)(12,452)(14,185)Operating Netback(1)(3)$64,656$101,402$71,457$219,653$318,813Capital Expenditures (Before Changes in Working Capital)$48,047$52,836$49,327$162,358$168,973Average Daily Production (boe/d)WI Production Before Royalties26,57332,76429,70028,64232,595Royalties(4,754)(6,776)(5,209)(5,265)(6,650)Production NAR21,81925,98824,49123,37725,945Decrease (Increase) in Inventory1,391(524)(1,469)132(368)Sales23,21025,46423,02223,50925,577Royalties, % of WI Production Before Royalties18%21%18%18%20%Operating Netback ($/boe)(1)(3)Brent$68.17$78.71$66.71$69.91$81.82Quality and Transportation Discount(10.76)(14.10)(10.30)(10.78)(14.11)Royalties(9.76)(13.58)(10.41)(10.82)(13.97)Average Realized Price47.6551.0346.0048.3153.74Transportation Expenses(1.54)(1.32)(1.63)(1.59)(1.61)Average Realized Price Net of Transportation Expenses46.1149.7144.3746.7252.13Operating Expenses(20.98)(15.53)(16.56)(18.76)(16.03)Operating Netback(1)(3)$25.13$34.18$27.81$27.96$36.10 Canadian Operational Information(4)Three Months Ended September 30,Three Months Ended June 30,Nine Months Ended September 30,20252024202520252024Operating Netback(1)(3)Gross Profit3,574—3,8517,217—Depletion and Accretion(*)8,348—13,70034,984—Operating Netback(1)(3)$11,922$—$17,551$42,201$—Oil Sales$21,884$—$22,276$64,984$—Natural Gas Sales3,702—5,53516,463—NGL Sales4,314—5,51916,249—Royalties(3,250)—(2,160)(10,374)—Oil, Natural Gas and NGL Sales After Royalties$26,650$—$31,170$87,322$—Operating Expenses(14,403)—(13,301)(44,231)—Transportation Expenses(325)—(318)(890)—Operating Netback(1)(3)$11,922$—$17,551$42,201$—Capital Expenditures (Before Changes in Working Capital)$9,228$—$1,796$40,384$—Average Daily ProductionCrude Oil (bbl/d)4,013—4,3353,992—Natural Gas (mcf/d)49,260—50,12449,746—NGLs (bbl/d)3,889—4,8074,571—WI Production Before Royalties (boe/d)16,112—17,49616,853—Royalties (boe/d)(1,969)—(2,187)(2,131)—Production NAR (boe/d)14,143—15,30914,722—Sales (boe/d)14,143—15,30914,722—Royalties, % of WI Production Before Royalties12%—%13%13%—%Benchmark PricesWest Texas Intermediate ($/bbl)65.0775.2863.8166.7477.71AECO Natural Gas Price (C$/GJ)0.600.651.601.421.38Average Realized PriceCrude Oil ($/bbl)59.28—56.4759.63—Natural Gas ($/mcf)0.82—1.211.21—NGLs ($/bbl)12.06—12.6213.02—Operating Netback ($/boe)(1)(3)Average Realized Price$20.17$—$20.93$21.23$—Royalties(2.19)—(1.36)(2.25)—Transportation Expenses(0.22)—(0.20)(0.19)—Operating Expenses(9.72)—(8.35)(9.61)—Operating Netback(1)(3)$8.04$—$11.02$9.18$— (*)Calculated as DD&A expenses for the three months ended September 30, 2025 and 2024 of $65.0 million and $55.6 million, less depreciation of administrative assets of $3.1 million and $3.0 million, respectively. For the nine months ended September 30, 2025 and 2024 of $205.8 million and $167.2 million, less depreciation of administrative assets of $9.5 million and $8.9 million, respectively. For the prior quarter, calculated as DD&A expenses of $68.6 million, less depreciation of administrative assets of $2.7 million. (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 current average production is for the period from October 1 to October 29, 2025.(3)Operating netback, as presented, is defined as gross profit less depletion and accretion related to producing assets. Management believes that operating netback is a useful supplemental measure for management and investors to analyze financial performance and provides an indication of the results generated by our principal business activities prior to the consideration of other income and 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.(5)Gran Tierra’s fourth quarter-to-date 2025 total average differentials for the period are from October 1 to October 29, 2025. Conference Call Information: Gran Tierra will host its third quarter 2025 results conference call on Friday, October 31, 2025, at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time, and 3:00 p.m. Greenwich Mean Time. Interested parties may access the conference call by registering at the following link: https://register-conf.media-server.com/register/BI7d7b37fa1bf446089868272e73c863d4. 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. 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. Gross profit is derived from oil, natural gas and NGL sales, net of direct production costs including operating expenses, transportation, and depletion, depreciation, and accretion (“DD&A”). Gross profit does not include general and administrative expenses, interest, taxes, or other non-operating items. Operating netback, as presented, is defined as gross profit less depletion and accretion related to producing assets. Management believes that operating netback is a useful supplemental measure for management and investors to analyze financial performance and provides an indication of the results generated by our principal business activities prior to the consideration of other income and expenses. A reconciliation from oil sales to operating netback is provided in the table below. 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, severance expenses, transaction costs, export tax, realized foreign exchange gain, cash settlement on derivative instruments, interest expense excluding amortization of debt issuance costs, interest income other cash gain, net lease payments, and current income tax. Management believes that operating netback and cash netback are useful supplemental measures for management and investors to analyze financial performance and provides an indication of the results generated by our principal business activities prior to the consideration of other income and expenses. Three Months Ended September 30,Three Months Ended June 30,Nine Months Ended September 30,Operating and Cash Netback – (Non-GAAP) Measure ($000s)20252024202520252024Gross Profit$14,670$48,803$23,061$65,568$160,457Adjustments to reconcile gross profit to operating netbackDepletion and accretion61,90852,59965,947196,286158,356Operating netback (non-GAAP)$76,578$101,402$89,008$261,854$318,813Cash G&A expenses$13,453$9,491$14,460$40,056$31,240Transaction costs$—$1,459$—$—$1,459Export Tax$2,630$—$—$2,630$—Realized foreign exchange gain (loss)$2,149$(1,003)$602$4,902$(642)Cash settlement on derivative instruments$(7,461)$—$(1,631)$(9,535)$—Interest expense, excluding amortization of debt issuance costs$21,178$16,783$20,284$60,864$47,539Interest income$(197)$(684)$(251)$(873)$(2,393)Other cash gain$(1,268)$—$(377)$(1,645)$—Net lease payments$387$(199)$(180)$38$(624)Current income tax$4,022$15,217$2,195$14,482$61,422Cash netback (non-GAAP)$41,685$60,338$53,906$150,935$180,812 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, transaction costs, 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 September 30,Three Months Ended June 30,Nine Months Ended September 30,EBITDA – (Non-GAAP) Measure ($000s)20252024202520252024Net (Loss) Income$(19,950)$1,133$(12,741)$(51,971)$37,426Adjustments to reconcile net loss or income to EBITDA and Adjusted EBITDADD&A expenses64,98155,57368,635205,818167,213Interest expense25,44719,89224,36673,04856,714Income tax (recovery) expense(11,276)20,7674,648(3,075)29,090EBITDA$59,202$97,365$84,908$223,820$290,443Non-cash lease expense1,1871,3701,7254,6484,164Lease payments(1,574)(1,171)(1,545)(4,686)(3,540)Foreign exchange loss (gain)284(3,084)3,7167,838(8,312)Stock-based compensation expense (recovery)143(3,145)5461726,376Transaction costs—1,459——1,459Other loss265—38355—Unrealized derivative instrument loss (gain)9,527—(12,401)(964)—Adjusted EBITDA$69,034$92,794$76,987$231,183$290,590 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 September 30,Three Months Ended June 30,Nine Months Ended September 30,Funds Flow From Operations – (Non-GAAP) Measure ($000s)20252024202520252024Net (Loss) Income$(19,950)$1,133$(12,741)$(51,971)$37,426Adjustments to reconcile net loss or income to funds flow from operationsDD&A expenses64,98155,57368,635205,818167,213Deferred tax (recovery) expense(15,298)5,5502,453(17,557)(32,332)Stock-based compensation expense (recovery)143(3,145)5461726,376Amortization of debt issuance costs4,2693,1094,08212,1849,175Non-cash lease expense1,1871,3701,7254,6484,164Lease payments(1,574)(1,171)(1,545)(4,686)(3,540)Unrealized foreign exchange (gain) loss(1,865)(2,081)3,1142,936(7,670)Other loss265—38355—Unrealized derivative instrument loss (gain)9,527—(12,401)(964)—Funds flow from operations$41,685$60,338$53,906$150,935$180,812Capital expenditures$57,340$52,921$51,170$203,237$169,525Free cash flow$(15,655)$7,417$2,736$(52,302)$11,287 Net debt as of September30, 2025, was $755 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 $804 million, less cash and cash equivalents of $49 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.