Gran Tierra Energy Inc. Reports Second Quarter 2025 Results & Another Quarter of Record Production
Achieved Record Total Company Average Quarterly Production of 47,196 boepd
Funds Flow From Operations(1) of $54 million, Adjusted EBITDA(1) of $77 million and Return to Free Cash Flow
Signed Mandate Letter for Funding of Up to $200 Million
Entered into Binding Agreement to Exit the UK North Sea
Achieved Company Record Total of 32 Million Hours Without a Lost Time Injury
Recorded 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: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 Data
Three Months Ended June 30,
Three Months Ended March 31,
Six Months Ended June 30,
2025
2024
2025
2025
2024
Net (Loss) Income
$(12,741)
$36,371
$(19,280)
$(32,021)
$36,293
Per 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
$323,186
Operating 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
$21,749
G&A Stock-Based Compensation Expense (Recovery)
546
6,160
(517)
29
9,521
G&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)
$3,870
Average Daily Production (boe/d)
WI Production Before Royalties
47,196
32,776
46,647
46,923
32,509
Royalties
(7,396)
(6,774)
(8,084)
(7,738)
(6,586)
Production NAR
39,800
26,002
38,563
39,185
25,923
Decrease (Increase) in Inventory
(1,469)
(811)
461
(509)
(288)
Sales
38,331
25,191
39,024
38,676
25,635
Royalties, % of WI Production Before Royalties
16%
21%
17%
16%
20%
Cash Netback ($/boe )(1)
Average Realized Price before Royalties
43.71
72.24
48.55
46.14
69.27
Royalties
(7.07)
(15.31)
(8.33)
(7.69)
(14.16)
Average Realized Price
36.64
56.93
40.22
38.45
55.11
Transportation Expenses
(1.83)
(1.96)
(1.63)
(1.73)
(1.75)
Average Realized Price Net of Transportation Expenses
34.81
54.97
38.59
36.72
53.36
Operating Expenses
(13.42)
(16.17)
(15.89)
(14.67)
(16.29)
Operating Netback (1)(3)
21.39
38.80
22.70
22.05
37.07
G&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 Instruments
0.39
—
0.10
0.25
—
Interest Expense, Excluding Amortization of Debt Issuance Costs
(4.87)
(5.38)
(4.58)
(4.72)
(5.24)
Interest Income
0.06
0.35
0.10
0.08
0.29
Other Gain
0.09
—
—
0.04
—
Net Lease Payments
0.04
0.02
0.04
0.04
0.07
Current 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 Period
35,289
31,022
