Gran Tierra Energy - Earnings Call - Q2 2025

Executive Summary

• Record production and mixed financials: WI production rose to 47,196 boe/d (+1% q/q; +44% y/y) on Canada integration and Ecuador exploration; revenue (oil, gas, NGL sales) fell to $152.5M (-11% q/q; -8% y/y) amid lower Brent, while Adjusted EBITDA was $77.0M (vs. $85.2M in Q1) and net loss was $12.7M.
• EPS beat vs. S&P Global: Q2 2025 EPS was $(0.36) vs. consensus $(0.43), a $0.07 beat; revenue consensus was not available* [GetEstimates Q2 2025]*.
• Cost/operational positives: Operating costs fell to $13.42/boe (lowest since Q1’22), operating netback was $21.39/boe, and hedging delivered a $14M gain; cash from ops declined to $34.7M (-53% q/q) as Brent fell 11% q/q and timing of vendor payments/working capital normalized.
• Liquidity/deleveraging path: Signed a mandate for up to $200M crude prepayment, confirmed C$100M Canada borrowing base; net debt ended at $746M (total debt $807M, cash $61M) with a long-term target of 1.0x net debt/Adj. EBITDA.
• Near-term catalysts: Closing of UK North Sea exit (Q3 2025), drilling of two Charapa (Conejo) exploration wells in Ecuador (starting late Q3), and continued Montney ramp can drive sentiment and estimates.

What Went Well and What Went Wrong

• What Went Well

  • Record total company average quarterly production of 47,196 boe/d as Canada and Ecuador contributions scaled; Acordionero base strengthened via waterflood management and facility upgrades (“continue to mitigate base decline”).
  • Operating efficiency: Operating costs dropped to $13.42/boe (lowest since Q1’22); South American quality/transport discounts tightened (Castilla $4.73/bbl; Vasconia $1.71/bbl; Oriente $7.26/bbl) supporting realized pricing.
  • Hedging & diversification: $14M derivative hedging gain and balanced hedge book (e.g., ~50% South American oil hedged in 2H25) buffered lower Brent; Canada Montney wells outperforming type curves.

• What Went Wrong

  • Profitability pressure: Net loss $(12.7)M as Brent fell 11% q/q; operating netback declined to $21.39/boe (-6% q/q; -45% y/y) on pricing and a heavier mix including Canada.
  • Cash flow downshift: Net cash from operating activities fell to $34.7M (-53% q/q; -53% y/y) amid lower prices and working capital timing; funds flow from ops dipped to $53.9M (-3% q/q).
  • Leverage remains elevated: Net debt $746M (total debt $807M; cash $61M); transportation expense rose with Canada volumes; some Ecuador barrels (143,730 bbl) deferred into July reduced Q2 WI sales.

Transcript

Speaker 5

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. At this time, all participants are in a listen-only mode. Following the initial remarks, we will conduct a question and answer session for securities analysts and institutions. Instructions will be provided at that time for you to queue up for questions. 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.

Speaker 8

Thank you, Operator. Good morning and welcome to Gran Tierra Energy's second quarter 2025 results conference call. My name is Gary Guidry, Gran Tierra Energy'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.

Speaker 6

Thanks, Gary. Good morning, everyone. Gran Tierra Energy 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 barrels of oil equivalent 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 Energy 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 a 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 barrel of oil equivalent 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 barrel of oil equivalent achieved since the first quarter of 2022. During the second quarter of 2025, Gran Tierra Energy incurred a net loss of $13 million compared to a net loss of $19 million in the prior quarter and compared to a 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 an adjusted EBITDA of $77 million versus $85 million in the prior quarter and $103 million in the first quarter of 2024. Twelve-month trailing net to adjusted EBITDA was 2.3 times; however, this only accounts for eight months of Canadian adjusted EBITDA and will continue to have a long-term target of one times. In terms of share buybacks, Gran Tierra Energy purchased approximately 240,000 shares during the quarter. From January 1st, 2023, to July 28th, 2025, the company repurchased approximately 5.2 million shares, or 15% of our shares issued outstanding on January 1st, 2023.

Gran Tierra Energy's capital expenditures were $51 million during the quarter, which were lower than the $95 million in the prior quarter and lower than the $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 30th, 2025, the company currently has approximately $112 million in credit and lending facilities, with $47 million drawn on June 30th, 2025. From a liquidity perspective, Gran Tierra Energy continues to advance multiple strategic initiatives to strengthen liquidity, including potential non-core asset dispositions, royalty monetization, optimization of free cash flow, and 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 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 Canadian. 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 31st, 2026. The next redetermination will be on or before November 30th, 2025.

Gran Tierra Energy 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's 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 its 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 $10 million USD per month. We also continue to optimize our portfolio with the signed disposition of the UK 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 that 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.

Speaker 1

Good morning, everyone, and thank you, Ryan. Operationally, Gran Tierra Energy 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 two wells from our five-well North Pad program were brought onto 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 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 two high-impact exploration wells at the Conejo prospect on the Chirapa 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 two lower Montney wells were completed and brought on stream in early April and are currently exceeding management's type curve expectations. The third well in the program was drilled and cased 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 phase 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 Conejo 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.

Speaker 5

Thank you, ladies and gentlemen. We will now conduct a question and answer session for securities analysts. If you have a question, please press the star key followed by 11 on your touch-tone phone. You will then hear an automated message advising that your hand is raised. Your question will be pulled in the order they are received. Please ensure you lift your handset if you're using a speaker phone before pressing any key. One moment, please, for our first question. The first question will come from David Round with Stifel. Your line is now open.

Speaker 2

Great, thank you. Thanks for making the time, guys. Can I start with a broad question on production, please? I know we just touched on a few of the key highlights. I just want to dig into it a bit more if possible. 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 or negative surprises there, and any highlights just to bring out. I know we just briefly mentioned, you know, 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 Cyrenté, Ecuador, and Simonette? I don't know if you're able to just elaborate on some of the specifics there.

Speaker 8

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

Speaker 1

Yeah, on rates, I think we continue to be very excited. We did an EST conversion over on Chirapa V7, which has, again, highlighted the quality of the Basaltena in Ecuador. That well is currently doing 1,800 barrels of oil per day, and the decline is extremely flat. We've had some significant wins as well within the portfolio, especially as we continue to develop in Ecuador. At Cohembi, the pressure response that we're seeing is really encouraging. We see that ramping up through Q3 and Q4.

Speaker 2

Okay, just a very quick follow-up on that point. If I think about all three of those areas I mentioned, Simonette, Cohembi, and Ecuador, should we be assuming ramp-up on all those assets over the second half of this year?

Speaker 8

Yes.

Speaker 2

Okay, fine. Just a second question then, and I appreciate it's not final, but just on the prepayment facility, 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?

Speaker 6

Yeah, at a high level, it's, you know, we'll be committing to essentially, you know, selling oil for, you know, future prepayments. It's going to be over about a four-year term. It's quite long-term in nature, not a huge grind on our cash flows. Just think of it as, you know, a loan that really advertises over four years settled with oil payments. The terms will be very, very competitive. We're quite excited about it. It's similar to what we've done in the past. It'll just be a longer tenor.

Speaker 2

Okay, great. Thank you. I'll hand it back.

Speaker 8

Thanks.

Speaker 5

The next question will come from Anne Milne with BofA Securities. Your line is open.

Speaker 7

Thank you. Good morning. 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 UK North Sea, $7.5 million. I think there are a couple others on the list there. That would be the first question.

Speaker 8

Yeah, the answer to that question is we have several things that are ongoing. We have non-disclosure 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 interest. You'll see more of that here over the third quarter.

Speaker 7

Okay, very good. Thank you. In terms of your guidance that you had previously given, I looked 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. Yet for your $65 a barrel assumption, in terms of the guidance, there was zero free cash flow. Could you just tell us what you're thinking? 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?

Speaker 6

Yeah, great question. The biggest driver on that end is just lower CapEx. The team's done a great job of executing the program, and we continue to look at how do we optimize that in the second half of the year. The number one driver is obviously oil price is somewhat supportive right now at $70 and very, very tight differentials in Colombia and Ecuador. The main driver will be on the CapEx side.

Speaker 7

Okay. 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 I might be missing it.

Speaker 6

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

Speaker 7

Okay. 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. 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?

Speaker 6

Yeah, 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 landslides. Obviously, it's not our pipelines, but there were some disruptions in Ecuador on the pipelines. That more impacted our Ecuador production in the first part of July. All the pipelines are back in operation and we're in its normal operations.

Speaker 7

Okay, great. Thanks very much. Thanks for answering these questions.

Speaker 6

Thanks, Ann.

Speaker 5

The next question will come from Josef Schachter with Schachter Energy Research Services. Your line is open.

Speaker 4

Morning, Gary, Ryan, and Sebastien. First question for me. You've got a range of, you know, $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?

Speaker 8

Yeah, thank you, Josef. 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. Yes, the answer is we're at the lower end of our guidance, but we're still easily within our guidance. 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. 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. 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. 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.

Speaker 4

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? Where do you see any, you know, potential growth for you in that central area? Does that, you know, include things like the Valley River? How do you see upside from that part of the portfolio?

Speaker 1

Yeah, I think to go back on sort of the transaction questions that we were talking about, there's a ton of opportunity in central. The nice part is, we do have a lot of linking infrastructure, so the team is actively working the central portfolio. I won't talk to a specific formation because there's many of them, starting from the NISQ to the GLOCK, and the team's been working on how do we optimize that portfolio. I think that's kind of the approach that we're taking, 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.

Speaker 4

Thank you for that input. I am looking forward to seeing Q3 and Q4 with the results. Thank you very much.

Speaker 8

Thanks.

Speaker 5

Our next question will come from Peter Bowley with Jefferies. Your line is open.

Speaker 3

Hi, thank you for the call and the opportunity for two questions. 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? 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? Thank you.

Speaker 6

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

Speaker 8

Yeah, and your question on Azerbaijan, yes, in fact, we did sign an MOU. We're working with the governments of Azerbaijan, with 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 five or six 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. 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. We're very excited about Azerbaijan.

Speaker 3

Thank you.

Speaker 5

Our next question will come from Garrett Fellows with J.H. Lane Partners. Your line is open.

Speaker 0

Hey guys, thanks for taking the question. 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, you know, if the assumption is that this was to de-risk the $184 million AMLR payment next year, you know, why do you need to pay a full year of interest on it? Or maybe there's something else going on that I don't know. Thanks.

Speaker 6

Yeah, it's a good question. I think part of it is that the number one concern people had with the company was addressing next year's maturity. We think we're proactively addressing the maturity. With respect to the interest, the way we've structured things, there's actually going to be a very low negative carry on the transaction. 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.

Speaker 0

Okay, great. I guess just quickly on Azerbaijan, could you walk us through the kind of cadence of how this project progresses? Let's say you have a signed memorandum of understanding or a signed production sharing agreement in the back half of the year. How does this project progress from there?

Speaker 8

Yeah, it's a five-year first phase, very low cost in terms of the reward that's in front of us. There's no pressure in terms of timing. We have a full five years from the time the Congress ratifies a PSA. The 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. That explains our excitement about having big structures in a very prolific oil and gas basin. It really is just applying modern technology that will apply over the next years to come. That is the timing. It's a five-year program. We'll disclose more about it, but a low cost of entry that we see in terms of the reward that's potentially there.

Speaker 0

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

Speaker 8

Depending on a proven discovery within that same year.

Speaker 0

Okay, great. Thank you guys very much.

Speaker 5

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

Speaker 8

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.

Speaker 5

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