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

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 September 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 October 30, 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; and

The 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 September 30, 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)

(*)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.

About Gran Tierra Energy Inc.

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.

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:

Adjustments to reconcile net loss or income to EBITDA and Adjusted EBITDA

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:

Adjustments to reconcile net loss or income to funds flow from operations

Net debt as of September 30, 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

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.