Gran Tierra Energy Inc. Q2 FY2025 Earnings Call

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.

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.

Thanks, Gary. Good morning, everyone. Gran Tierra achieved another quarter of strong operational and financial results, marked by record production, the lowest operating costs per barrel since early 2022, and improved liquidity through various initiatives and credit capacity. In the quarter, we recorded a production of around 47,200 BOE per day, up 1% from the previous quarter and 44% higher than Q2 2024. This growth reflects robust performance in Colombia, Ecuador, and Canada, aided by successful drilling campaigns and effective waterflood execution. Gran Tierra generated $152 million in sales, an 8% decrease from the second quarter of 2024, mainly due to a 22% drop in Brent pricing, though it was partially offset by a 43% increase in sales volume from higher production and lower South American oil differentials. Oil sales fell 11% from the previous quarter, largely because of an 11% decrease in Brent price but were again partially offset by reduced South American differentials. Operating expenses per BOE decreased by 17% compared to the second quarter of 2024 and by 16% from the previous quarter, largely due to lower workover activities and reduced lifting costs linked to inventory build in Ecuador, power generation, and equipment rentals. This was the lowest cost per BOE since the first quarter of 2022. In the second quarter of 2025, Gran Tierra reported a net loss of $13 million, improving from a net loss of $19 million in the previous quarter but down from net income of $36 million in the same quarter last year. Funds flow from operations reached $54 million or $1.53 per share, which is up 17% from the second quarter of 2024 and down 3% from the prior quarter. Brent price fell by 11% per barrel compared to the previous quarter, but our cash netback only decreased by 1%, showcasing the resilience of our portfolio. The company achieved adjusted EBITDA of $77 million, down from $85 million in the previous quarter and $103 million in the first quarter of 2024. Our 12-month trailing net debt to adjusted EBITDA ratio was 2.3x, though this only reflects 8 months of Canadian adjusted EBITDA. Our long-term target remains at 1x. Regarding share buybacks, Gran Tierra repurchased around 240,000 shares during the quarter, bringing the total from January 1, 2023, to July 28, 2025, to approximately 5.2 million shares, or 15% of the shares outstanding as of January 1, 2023. Capital expenditures were $51 million in the quarter, lower than $95 million in the previous quarter and $61 million in the second quarter of 2024, with the majority of spending focused on drilling and infrastructure in Colombia. Alongside $61 million in cash on hand as of June 30, 2025, the company has about $112 million in credit and lending facilities, with $47 million drawn as of June 30, 2025. Gran Tierra is actively pursuing various strategic initiatives to boost liquidity, such as potential non-core asset sales, monetizing royalty interests, optimizing free cash flow, and assessing prepayment structures, all progressing as planned. We also announced a mandate letter signed with a syndicate of banks for a $200 million prepayment facility backed by crude oil deliveries, with full documentation expected soon and closing planned for the third quarter of 2025. Furthermore, as part of our completed semiannual redetermination process, lenders confirmed that the borrowing base of our Canadian credit facility remains unchanged at $100 million, reflecting the ongoing strength and stability of our Canadian asset base. Our revolving credit facility continues to provide $50 million in available commitments with a maturity date of October 31, 2026, and the next redetermination will occur by November 30, 2025. Gran Tierra implements a disciplined hedging strategy to safeguard cash flows, support capital planning, and enhance financial stability over commodity cycles. We utilize a diverse mix of oil and gas hedges that provide downside protection while preserving upside potential. This proactive strategy resulted in a $14 million derivative hedging gain during the quarter. We also maintain a rolling 12-month foreign exchange hedging program to mitigate currency fluctuations. For the second half of 2025, we have hedged about 50% of our South American oil production and 60% of Canadian production. For the first half of 2026, the hedge coverage is approximately 33% for South America and 50% for Canada, with pricing levels aligned with our planning assumptions. Additionally, Gran Tierra has hedged around 40% of Canadian natural gas production for the latter half of 2025. To manage foreign exchange risk, we initiated a 12-month COP to USD hedging program in April 2025, covering roughly USD 10 million per month. We are also optimizing our portfolio, with the signed disposition of U.K. North Sea assets for approximately $7.5 million, set to close in the third quarter of 2025. Overall, Gran Tierra's performance in the second quarter highlights our commitment to capital discipline and operational excellence, achieving record production and lower operating expenses per barrel while enhancing our liquidity through various initiatives to provide financial flexibility moving into the second half of 2026.

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 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, and 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.

The first question will come from David Round with Stifel.

Can I start with a broad question on production? I know we just touched on a few key highlights. I’d like to explore this further, if possible. Firstly, I'm interested in how production has progressed this year compared to initial expectations. Were there any positive or negative surprises? Any notable highlights to mention? I know we briefly discussed Costayaco and Acordionero. Can we elaborate on the current contributions and future expectations for the second half of the year, especially regarding the key areas like Soriente, Ecuador, and Simonette? Could you provide some specifics on those?

I think at a very high level, all of our fields have been performing as expected or beyond expectations. We have had normal interruptions in Colombia and Ecuador with blockades, but we have a very good team that manages the impact. We've seen also some infrastructure issues. There's one that's just finishing up in Ecuador at the moment with very heavy rains causing pipeline interruptions. 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?

Yes. So on rates, I think we continue to be very excited. We did an ESP conversion over at Terapa B7, which again, highlighted the quality of the Basal Tena in Ecuador. That well is currently producing 1,800 barrels of oil per day and the 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. We see that ramping up through Q3 and Q4.

Okay. So just then a very quick follow-up on that point. So actually, if I think about all three 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?

Yes.

Okay. Fine. Just a second question then, and I appreciate it's not final, but can you provide any broad information about how the preparation might work or an indicative cost? Or are we still too early for that?

Yes. No, at a high level, 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. The terms will be very competitive, and we're quite excited about it. It’s similar to what we've done in the past. It will just be a longer tenor.

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

Congratulations on your results. I have a few questions relatively short, hopefully. The first is, could you provide us with 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.

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. You will see more of that here over the third quarter.

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?

Yes, that's a great question. The primary factor contributing to this is the reduction in capital expenditures. The team has excelled in implementing the program, and we are continuously exploring ways to optimize this in the latter half of the year. Currently, oil prices are somewhat favorable at $70, along with very tight differentials in Colombia and Ecuador. However, the main influence will indeed stem from the capital expenditure aspect.

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...

We don't. In our press release, we have more details by country as far as netbacks and whatnot, but not EBITDA.

Okay, my final question is about Colombia. There have been various disruptions, including pipeline issues and export taxes that have impacted Ecopetrol. Do these also affect Gran Tierra? Could you explain the operating environment in Colombia and any potential impacts on your operations or financial metrics?

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 significant landslides. And obviously, it's not our pipelines, but there were disruptions in Ecuador on the pipelines. That more impacted our Ecuador production in the first part of July. But all the pipelines are back in operation, and we are in normal operations.

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

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?

Yes, thank you, Joseph. We do have the necessary production capacity and there are no disruptions. We are currently operating at the lower end of our guidance but still comfortably within the range, and our goal is to reach the upper end. We are committed to increasing our output. We have most of our capital invested, and we’ve seen excellent results at Cohembi and Costayaco. The waterflood in Acordionero is progressing positively. Additionally, in Ecuador, we are working on obtaining approvals for our field development plan, which involves some promising reservoirs. As Sebastien mentioned, the performance indicates that we will be implementing waterflooding. We are optimistic about the second half of the year and the coming years regarding our capital allocation and the potential of these reservoirs.

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?

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. We do have a lot of linking infrastructure and so the team is actively working on the central portfolio. I won't talk to a specific formation because there are many of them and starting from the NCIB to the Glock. The team has been working on how to optimize that portfolio. That's kind of the approach that we're taking, looking for synergies, especially on third-party processing fees and so on and so forth to optimize, again, on cost, but also in terms of profit.

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

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?

Great. Thanks. Yes. On the hedging front, yes, what we've been communicating is that we're putting more of a structured plan. Our objective is to hedge 30% to 50% 6 months out and then 20% to 30% the following 6 months on a continuous basis. As each month rolls off, we will add hedges for the following month that has rolled off. We continue to have a more systematic hedging program.

Yes. On your question on Azerbaijan, yes, in fact, we did sign an MOU, and we're working with the governments of Azerbaijan and SOCAR, the national company on progressing that to a production sharing agreement. 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. 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 or fourth quarter here. We're very excited about Azerbaijan.

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 amortization 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?

Yes. No, it's a good question. I think part of it is the number one concern people had with the company was addressing next year's maturity. 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. We thought now would be the time to proactively address that with very minimal cost.

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?

Yes, it's a five-year initial phase with very low costs compared to the potential rewards ahead. There's no urgency regarding the timeline, as we have a complete five years after Congress ratifies a production sharing agreement. We see that there are discoveries in the area, which is very close to existing infrastructure. The gas market has strong prices for both domestic use and European exports. There's capacity in the pipelines, which contributes to our enthusiasm about having significant projects in this highly productive oil and gas region. It really involves utilizing modern technology over the coming years. This is the timeline: it's a five-year program, and we'll share more details about it, but there's a low entry cost associated with the potential rewards.

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

Depending on a proven discovery within that same year.

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

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.

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