Gran Tierra Energy Inc. (AMEX:GTE) Q2 2025 Earnings Call Transcript

Gran Tierra Energy Inc. (AMEX:GTE) Q2 2025 Earnings Call Transcript July 31, 2025

Operator: Good morning, ladies and gentlemen, and welcome to Gran Tierra Energy’s Results Conference Call for the Second Quarter 2025. My name is Michelle, and I will be your coordinator for today. I would like to remind everyone that this conference is being webcast and recorded today, Thursday, July 31, 2025, at 11:00 a.m. Eastern Time. Today’s discussion may include certain forward-looking information, oil and gas information and non-GAAP financial measures. Please refer to the earnings and operational update press release we issued yesterday for important advisories and disclaimers with regard to this information and reconciliations of any non-GAAP measures discussed on today’s call. Finally, this earnings call is the property of Gran Tierra Energy, Inc.

Any copying or rebroadcasting of this call is expressly forbidden without the written consent of Gran Tierra Energy. I will now turn the conference over to Gary Guidry, President and Chief Executive Officer of Gran Tierra. Mr. Guidry, please go ahead.

Gary Stephen Guidry: Thank you, operator. Good morning, and welcome to Gran Tierra’s Second Quarter 2025 Results Conference Call. My name is Gary Guidry, Gran Tierra’s President and Chief Executive Officer. And with me today are Ryan Ellson, our Executive Vice President and Chief Financial Officer; and Sebastien Morin, our Chief Operating Officer. On Wednesday, July 30, 2025, we issued a press release that included detailed information about our second quarter 2025 results, which is available on our website. Ryan and Sebastien will make a few brief comments, and then we will open up the line for questions. I’ll now turn the call over to Ryan to discuss some of our financial results.

Ryan Paul Ellson: Thanks, Gary. Good morning, everyone. Gran Tierra delivered another quarter of strong operational and financial performance, highlighted by record company production, the lowest per barrel operating cost since early 2022 and enhanced liquidity through a number of initiatives and credit capacity. During the quarter, we achieved record production of approximately 47,200 BOE per day, an increase of 1% from the prior quarter and 44% higher than Q2 2024. This continued growth reflects strong performance across Colombia, Ecuador and Canada, supported by successful drilling campaigns and waterflood execution. 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, which was partially offset by 43% higher sales volume due to higher production and lower South American oil differentials.

Oil sales decreased 11% from the prior quarter, primarily due to an 11% decrease in Brent price, again, partially offset by lower South American oil differentials. 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 as a result of lower workover activities and lower lifting costs associated with inventory build in Ecuador, power generation and equipment rentals. This was the lowest operating cost per BOE achieved since the first quarter of 2022. During the second quarter of 2025, Gran Tierra incurred a net loss of $13 million compared to a net loss of $19 million in the prior quarter and compared to net income of $36 million in the same quarter last year.

Funds flow from operations were $54 million or $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 barrel compared to the prior quarter, and our cash netback only decreased by 1%, illustrating the resiliency of our portfolio. The company generated adjusted EBITDA of $77 million versus $85 million in the prior quarter and $103 million in the first quarter of 2024. 12-month trailing net debt to adjusted EBITDA was 2.3x. However, this only accounts for 8 months of Canadian adjusted EBITDA, and we continue to have a long-term target of 1x. In terms of share buybacks, Gran Tierra purchased approximately 240,000 shares during the quarter. From January 1, 2023, to July 28, 2025, the company repurchased approximately 5.2 million shares or 15% of our shares issued and outstanding on January 1, 2023.

Gran Tierra’s 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. 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 on June 30, 2025. From a liquidity perspective, Gran Tierra continues to advance multiple strategic initiatives to strengthen liquidity, including potential non-core asset sales, monetization of royalty interest, optimization of free cash flow and the evaluation of prepayment structures.

All initiatives are progressing in line with our expectations. As part of these strategic initiatives, we have announced that we have signed a mandate letter with the syndicate of banks for a $200 million prepayment facility backed by crude oil deliveries. We are progressing towards full documentation with closing expected in the third quarter of 2025 and funding anticipated shortly thereafter. Also of note, as part of our — and as part of the completed semiannual redetermination process, the company received confirmation from its lenders that the borrowing base under its Canadian credit facility remains unchanged at $100 million. This outcome reflects ongoing strength and stability of the company’s Canadian asset base. The revolving credit facility continues to provide $50 million available commitments with a maturity date of October 31, 2026.

The next redetermination will be on or before November 30, 2025. Gran Tierra also employs a disciplined and risk-managed hedging strategy designed to protect cash flows, support capital planning and enhance financial stability across commodity cycles. The company utilizes a diverse mix of oil and gas hedges with structures that provide downside protection while preserving upside exposure. This proactive approach contributed to a $14 million derivative hedging gain during the quarter. The company also maintains a rolling 12-month foreign exchange hedging program to further mitigate currency volatility. Gran Tierra implemented a robust hedging program to manage price volatility across its operations. For the second half of 2025, the company has hedged approximately 50% of its South American oil production and 60% of its Canadian oil production.

For the first half of 2026, hedge coverage stands at roughly 33% for South America and 50% for Canada. The pricing levels of these hedges are in line with the company’s planning assumptions and provide downside protection while preserving upside exposure. Gran Tierra has also hedged approximately 40% of Canadian natural gas production for the second half of 2025. In addition to help manage foreign exchange risk, the company began a 12-month COP to USD hedging program in April 2025, covering approximately USD 10 million per month. We also continue to optimize our portfolio with the signed disposition of the U.K. North Sea assets for approximately $7.5 million, which is expected to close in the third quarter of 2025. Overall, Gran Tierra’s second quarter performance continues to demonstrate our commitment to capital discipline and operational excellence by delivering record production and reporting lower operating expenses per barrel while also enhancing our liquidity position through a number of initiatives to add financial flexibility heading into the second half of 2026.

I’ll now turn the call over to Sebastien to discuss some of the highlights of our current operations.

Sebastien Morin: Good morning, everyone, and thank you, Ryan. Operationally, Gran Tierra delivered another strong quarter, building on the momentum from Q1 and continuing to advance key initiatives across our core areas in Colombia, Ecuador and Canada. Starting in Colombia, total working interest production averaged approximately 25,100 barrels of oil per day during the quarter. driven by successful development drilling at Cohembi and Costayaco and continued improvements in waterflood execution in Costayaco-Cohembi and Acordionero. At Cohembi, the remaining 2 wells from our 5-well North pad program were brought on to production. Average drilling cost was approximately $3 million per well, representing a 47% reduction from the previous operator’s historical costs.

Injection of 8,000 barrels of water injected per day in the newly delivered North pad began in June. Already, we are seeing a strong waterflood response with gross production increasing by 2,600 barrels of oil per day in the northern area of the field. At Costayaco, we completed and brought on stream the Costayaco-63 and Costayaco-64 development wells. Both wells were stimulated and placed on production with initial results exceeding expectations. Costayaco-63 is currently producing 800 barrels of oil per day with a 48% water cut, and Costayaco-64 is producing 1,300 barrels of oil per day with only a 13% water cut. The final well in the program, Costayaco-65 was spud in July and is expected to be on production in August. At Acordionero, we achieved record total fluid production of 89,400 barrels per day and water injection of 85,000 barrels per day during the quarter.

Field production averaged 14,200 barrels of oil per day, up from 13,800 in Q1. This improvement reflects continued gains in pump upsizing, enhanced surface capacity and real-time waterflood surveillance. Moving to Ecuador. We continue to execute our strategy and fulfill our commitments. Civil works are underway in preparation for drilling 2 high-impact exploration wells at the Conejo prospect on the Charapa block with spud expected in late Q3. These will be the final wells under our exploration commitments in the country. The results will help guide further development plans and infrastructure alignment in the region. In Canada, the Simonette Montney program continues to outperform. The first 2 Lower Montney wells were completed and brought on stream in early April and are currently exceeding management’s type curves expectations.

The third well in the program was drilled in case successfully in July. The rig was moved to the next location on the pad and is now drilling the fourth well in the program. The well is expected to reach total depth in August. Both of these new wells are expected to be stimulated and put on stream in Q4. Across the portfolio, we remain focused on capital efficiency, reservoir optimization and unlocking further value from our diverse asset base. The success of our drilling programs, enhanced field performance and reduced operating costs position us well to deliver free cash flow and strengthen our financial position through the second half of 2025. Looking ahead, we remain focused on continuing to ramp base production at Cohembi North and Costayaco from our Q1, Q2 development programs, which are delivering very positive results.

optimizing Acordionero production with continued waterflood enhancements and facility optimizations. Initiating the high-impact Banjo exploration wells in Ecuador to unlock additional value from the Oriente Basin, completing and bringing online the third and fourth Simonette Montney wells while optimizing existing field production, maintaining capital and operational cost discipline while targeting free cash flow generation in the second half of the year. I will now turn the call back to the operator, and Gary, Ryan and I will be happy to take questions. Operator, please go ahead.

Q&A Session

Operator: [Operator Instructions] The first question will come from David Round with Stifel.

David Matthew Round: Can I start with a broad question on production, please? And I know we just touched on a few of the key highlights. I just want to dig into it a bit more, if possible. So firstly, I guess I’m interested in how production has gone so far this year versus where you thought you’d be at the start of the year? Whether there were any positive, negative surprises there? Any highlights just to bring out? And I know we just briefly mentioned sort of Costayaco, Acordionero. I suppose, are we able to just kind of elaborate on current contributions and expectations, I guess, for H2 and beyond for — I suppose the key moving parts, so Soriente, Ecuador and Simonette. I don’t know if you’re able to just elaborate on some of the specifics there.

Gary Stephen Guidry: I think at a very high level, all of our fields have been performing as expected or beyond expectations. We have the normal interruptions in Colombia and Ecuador with blockades, but we have a very good team that manage those, the impact. We’ve seen also some infrastructure issues. There’s one that’s just finishing up in Ecuador at the moment with a very heavy rains, pipeline interruption. But in general, the answer to your question is from a field and asset performance, everything has performed as expected or outperformed. And that’s both in Canada, Colombia and Ecuador. On the specifics, maybe, Sebastien, you could say a few words about rates?

Sebastien Morin: Yes. So on rates, I think we continue to be very excited. We did an ESP conversion over on Terapa B7, which is, again, highlighted the quality of the Basal Tena in Ecuador. And so that well is currently doing 1,800 barrels of oil per day and decline is extremely flat. So we’ve had some significant wins as well within the portfolio, especially as we continue to develop in Ecuador. And then at Cohembi, the pressure response that we’re seeing is really encouraging. And so we see that ramping up through Q3 and Q4.

David Matthew Round: Okay. So just then a very quick follow-up on that point. So actually, if I think about all 3 of those areas, I mentioned Simonette, Cohembi and Ecuador, I mean, should we be assuming ramp-up on all those assets over the second half of this year?

Gary Stephen Guidry: Yes.

David Matthew Round: Okay. Fine. Just a second question then, and I appreciate it’s not final, but just on the prep — can you say anything even in broad terms about how that might work or just sort of indicatively what that might cost? Or are we too early on that one?

Ryan Paul Ellson: Yes. No, at a high level, it’s — we will be committing to essentially selling oil for future prepayments. It’s going to be over about a 4-year term. So it’s quite long term in nature, not a huge grind on our cash flows. So just think of it as a loan that really amortizes over 4 years settled with oil payments. And so the terms will be very, very competitive, and we’re quite excited about it. And so it’s similar to what we’ve done in the past. It will just be a longer tenor.

Operator: And the next question will come from Anne Milne with Bank of America.

Anne Jean Milne: Congratulations on your results. I have a few questions relatively short, hopefully. The first is, could you provide us with an additional — any additional updates or your thoughts on other asset sales for this year? I believe you mentioned the U.K. North Sea, $7.5 million. I think there were a couple of others on the list there. That would be the first question.

Gary Stephen Guidry: Yes. The answer to that question is we have several things that are ongoing, and we have nondisclosure agreements in place. So we’re really not talking about those, but we are very actively looking at our portfolio to divest of non-core assets and in some other areas to dilute our interests. And so you’ll see more of that here over the third quarter.

Anne Jean Milne: Okay. Very good. And then in terms of your guidance that you had previously given, I look quickly at your presentation here versus what you had last quarter. I do see there is a comment that you’re looking to generate $20 million of free cash flow this year, but yet for your $65 a barrel assumption in terms of the guidance, there was 0 free cash flow. Could you just tell us what you’re thinking? And then since you’ve sort of front-loaded your CapEx for 2025, will some of this come from lower CapEx and this additional new production that’s coming online from a number of your fields?

Ryan Paul Ellson: Yes. Great question. The biggest driver on that Anne, is just lower CapEx. The team has done a great job of executing the program. And so — and we continue to look at how do we optimize that in the second half of the year. So the #1 driver is obviously, oil price is somewhat supportive right now at $70 and very, very tight differentials in Colombia and Ecuador. But the main driver will be on the CapEx side.

Anne Jean Milne: Okay. And then just tell me if I’m missing something, but do you break down EBITDA by country in the presentation here? I don’t think I saw it, but…

Ryan Paul Ellson: We don’t. In our press release, we have more details by country as far as netbacks and whatnot, but not EBITDA.

Anne Jean Milne: Okay. And then I guess final question would be Colombia. There have been a lot of, I guess, you could say, pipeline disruption and other types of disruptions. And I think there were some export taxes that I know they affected Ecopetrol. Do they affect Gran Tierra? Could you tell us what the operating environment in Colombia, what impact it might have had on your — either the operations or — and I know you sort of hinted at that in some of your comments or on any sort of financial metrics you have?

Ryan Paul Ellson: Yes. On the export tax, we’ve been unaffected. The main thing that’s impacted us is pipeline disruptions in Ecuador. As Sebastien mentioned, there were some significant land slides. And obviously, it’s not our pipelines, but there was some disruptions in Ecuador on the pipelines. And so that more impacted our Ecuador production in the first part of July. But all the pipelines are back in operation, and we’re in its normal operations.

Operator: And the next question will come from Josef Schachter with Schachter Energy.

Josef I. Schachter: First question for me. You’ve got a range of 47,000 to 53,000 for production this year. Your average for the first half, 47,000. What needs to happen to get to 50,000? What needs to happen to get to 53,000 in terms of your forecast?

Gary Stephen Guidry: Yes. Thank you, Joseph. I think the answer to that is we have the capacity. We have the production capacity. It’s no disruptions. And we’re working through that. We’re — yes, the answer is we’re at the lower end of our guidance, but we’re still easily within our guidance. And our target is to be at the upper end. We’re going to do our best to ramp. I think Anne asked the question or David Round asked the question. Yes, we have most of our capital deployed. We’ve had some excellent results in Cohembi, excellent results in Costayaco. The waterflood is going in the right direction in Acordionero. So all of that’s there. The exciting one as well is Ecuador. We’re just going through our field development plan approvals with the government, and these are some fantastic reservoirs.

As Sebastien alluded to, the performance is very clear that we’re going to be doing some waterflooding, quick response — so not only the second half of the year, but the next few years, we’re quite excited about where we’re going with our capital and capital allocation with some fantastic reservoirs.

Josef I. Schachter: Okay. Second question for me. In your Canadian side where you have the Central 12,500 BOEs a day, 49% working interest. How much of that do you operate? And where do you see any potential growth for you in that Central area? Does that include things like the Belly River? How do you see upside from that part of the portfolio?

Sebastien Morin: Yes. I think to go back on sort of the transaction questions that we were talking about, there’s a ton of opportunity in Central. And the nice part is we do have a lot of linking infrastructure and so the team is actively working the central portfolio. And I won’t talk to a specific formation because there’s many of them and starting from the NCIB to the [ Glock. ] And the team has been working on how do we optimize that portfolio. And so I think that’s kind of the approach that we’re taking is where it makes sense to have some synergies, especially on third-party processing fees and so on and so forth to optimize, again, on cost, but also in terms of profit.

Josef I. Schachter: And surely looking forward to Q3 and Q4 with the results.

Operator: And our next question will come from Peter Bowley with Jefferies.

Peter Bowley: First question is after recently increasing your hedges for 2026, is the strategy to continue increasing hedges even further? Or are you comfortable at this level? And the second question is just regarding some report or media that there was an MOU signed for potential entry into the Azerbaijani market. Could you share any updates there or any expected timing if you are contemplating a market entry there?

Ryan Paul Ellson: Great. Thanks. Yes. On the hedging front, yes, what we’ve been communicating is that we’re putting more of a structured plan. And so our objective is to hedge 30% to 50% 6 months out and then 20% to 30% the following 6 months on a continuous basis. So we will — as a month rolls off, we will add hedges for the following month that rolled off. And so we continue to have a continued more systematic hedging program.

Gary Stephen Guidry: Yes. On your question on Azerbaijan, yes, in fact, we did sign an MOU, and we’re working with the governments of Azerbaijan with SOCAR, the national company on progressing that to a production sharing agreement. And what I’ll say — what I will say about what we’re doing in Azerbaijan, this is the one thing in our portfolio that we’ve been trying to add for the last 5 or 6 years, looking in specific basins around the world where you have an order of magnitude opportunity greater than we have currently in terms of Colombia, Ecuador, Canada, where you can find multi-Tcf type fields, you can find a couple of hundred million barrel oil fields. And so it’s a very large block of land in a very prospective part of the country onshore, and we’re very excited about it.

You’ll hear more about it when we go to a definitive agreement with a production sharing agreement, hopefully, in the third, fourth quarter here. And so yes, we’re very excited about Azerbaijan.

Operator: And our next question will come from Garrett Fellows with J.H. Lane Partners.

Garrett Fellows: So I mean, you listed a few other ways of raising capital here, the royalties, non-core asset sales. I guess I’m curious why we felt the need to do the forward sale sort of loan agreement now if the assumption is that this was to derisk the $184 million amort payment next year, why do we need to pay a full year of interest on it? Or maybe there’s something else going on that I don’t know?

Ryan Paul Ellson: Yes. No, it’s a good question. And I think part of it is the #1 concern I think people had with the company was addressing next year’s maturity. And so we think we’re proactively addressing the maturity. In respect to the interest, the way we’ve structured things, there’s actually going to be a very low negative carry on the transaction. So again, de minimis negative carry just with investments that we can do and some tax efficiency that we have. And so we thought now would be the time to proactively address that with very minimal cost.

Garrett Fellows: Okay. Okay. Great. And then I guess just quickly on Azerbaijan. Could you walk us through the kind of cadence of how this project progresses. And let’s say you have a signed MOU or signed production sharing agreement in the back half of the year. How does this project progress from there?

Gary Stephen Guidry: Yes. It’s a 5-year first phase, very low cost in terms of the reward that’s in front of us. And so there’s no pressure in terms of timing. We have a full 5 years from the time the Congress ratifies a PSA. And so timing that we see, there are discoveries on the block — it is very close to infrastructure. Gas, there’s a very, very prolific price for both domestic and European exports. There’s room in pipelines. And so that explains our excitement about having big structures in a very prolific oil and gas basin. And it really is just applying modern technology that will apply over the next years to come. And so that is the timing. It’s a 5-year program, and we’ll disclose more about it, but a low cost of entry that we see with — in terms of the reward that’s potentially there.

Garrett Fellows: Got it. But just in terms of when you could actually start producing after the PSA is signed?

Gary Stephen Guidry: Depending on a proven discovery within that same year.

Operator: Gentlemen, there are no further questions at this time. Please continue.

Gary Stephen Guidry: I would once again like to thank everyone for joining us today. We look forward to speaking with you over the next quarter and update you on our ongoing progress. Thank you.

Operator: This concludes today’s conference call. Thank you for participating, and you may now disconnect.