Good afternoon, and thank you for joining the PetroTal Q3 webcast. Manolo Zúñiga, President and CEO, and Camilo McAllister, Executive Vice President and CFO, are your presenters. You can submit questions via the platform, and we will do our best to answer as many of these as possible in the time available. Without any further ado, I'll hand over to Manolo and Camilo.
Thank you, Mark, and good morning, everyone. Thank you for joining PetroTal's third quarter 2025 results webcast. My name is Manolo Zúñiga, and I'm the President and CEO of PetroTal. I'm joined today by Camilo McAllister, our Executive Vice President and Chief Financial Officer. Today, we're walking through the financial and operational results that we published overnight. If you access this webcast via the link included in today's press release, you should be seeing our slide presentation on your screen. Before we get started, I'd like to point out that there are disclaimers located at the end of the main presentation and also on our website. We encourage you to review those after the prepared remarks. I will now pass the microphone to Camilo to give a brief overview of our third quarter 2025 financial results.
Thank you, Manolo. Turning to slide number two, I wanted to give a quick summary of our third quarter financial results. The message may have been lost in the rest of the press releases today, but it's worth noting that our financial results were actually quite good at this quarter. Our production averaged over 18,400 bbl of oil per day in the third quarter, which was a 21% increase over the same period last year. We benefited from unusually wet weather this year, which boosted river levels compared to 2024. We were able to export essentially 100% of our production capacity during the dry season this year, which was a very good outcome.
Oil prices rebounded a little bit in the third quarter, but our net operating income fell slightly compared to the prior quarter. Even though our operating costs normalized following some expenses from pump replacements in the second quarter of 2025, our transportation costs were a bit higher this quarter. Lastly, even with a slight increase in capital spending, we still generated just over $12 million in free cash flow during the third quarter, bringing our year-end-to-date free cash flow to more than $87 million. We have already returned approximately half of that free cash flow to our investors through dividends and buyback prior to the suspension of our fourth quarter dividend, which we also announced today. I will now pass the microphone back to Manolo to walk through our operational results.
Thank you, Camilo. Moving to slide three, I would like to have an open discussion about some of the operational challenges that we are facing right now. Overall, I think our track record has been very good for the past few years, but unfortunately, we seem to be dealing with a number of headwinds at the moment. We have already disclosed a series of pump failures and tubing leaks in 2025. While I have been very happy with the swift response from our operational teams, the reality is that we need to prepare for the possibility that we may experience additional failures in 2026. Our people are preparing contingency plans right now to ensure we can minimize production next year in the event that more wells fail.
Water handling has always been an important consideration for PetroTal, but the issue has become more pressing in 2025 after we brought seven wells on stream last year. When you consider that each of our horizontal wells produces more than 10,000 bbl of fluid per day, excess water handling capacity must be built out in advance of our development wells. Otherwise, we may have to shut in existing production to accommodate new wells, which is obviously not ideal. Moving into 2026, we had originally expected our green and rig to arrive at Bretaña early in the year. However, for a variety of reasons, that timeline has now been pushed back by at least six months. With limited ability to generate organic production growth for the medium term, it seems clear now that our base production is likely to decline throughout the first half of 2026.
When we combine the impact of falling production with a weak oil price outlook, we have been faced with some difficult choices as we finalize our 2026 development program. We would like to resume development drilling as quickly as possible, but ideally, once we have sufficient water handling capacity in place. The team is working on enhancing the activity on our existing water disposal wells to bring back up to 5,000 bbl of oil per day of currently shut-in production. Turning to slide four, we have tried to summarize the range of production outcomes we are seeing in our development planning right now. The dark blue line shows our actual monthly production so far in 2025. As you can see, the general downward trajectory is expected to continue until at least the middle of 2026.
The dotted green line shows our best-case production scenario, which assumes we are able to move our rig to Bretana by the middle of 2026. In this scenario, we believe it would still be possible to drill and complete three development wells by the end of the year. Depending on production availability, it's possible PetroTal could exit 2026 with production in excess of 20,000 bbl per day. Enhancing our water disposal capacity, as mentioned before, would put us somewhere in the middle of both curves. The lower dotted blue line shows our low-case production scenario, which basically assumes we are not able to complete any drilling activities in 2026. I think this scenario is unlikely when we must acknowledge the possibility that we do not drill any wells next year.
In this case, we would likely center our capital program on investments in water handling capacity, preparing for improvements in oil pricing in 2027. I should point out that we are also considering other scenarios that are not pictured here. For example, it's still possible we could send a green rig to Block 131, where we do not have to invest in water handling capacity before drilling new development wells. We are also looking at options to secure a third-party drilling rig, which would give us more flexibility to resume drilling in the event that our own drilling rig continues to be delayed. In any case, we plan to finalize our 2026 budget in January, at which point we will provide more specific details on our development program. Please stay tuned. I will now hand the microphone back to Camilo to discuss the financial implications of our announcements today.
Thank you, Manolo. On slide five, we have prepared a summary of the initiatives we are undertaking to preserve liquidity as we navigate this period of uncertainty. Although we have a rough idea of the activities we must undertake in order to restore production capacity at Bretaña, the reality is that we won't know our true funding requirements until we have finalized our 2026 development plan. However, we do know that with production declining and considering the prevailing outlook for oil prices, we would not be able to support both a reasonable development program and a regular dividend in 2026 without substantially drawing on our available cash reserves. At our board meeting this week, when faced with a decision to let approximately $14 million out of the company in December, we felt it was in the best long-term interest of PetroTal and its shareholders to suspend the dividend immediately.
I would like to stress that dividends are not the only lever we are pulling to preserve liquidity. Our Board of Directors has given us a clear directive to cut costs so that we are better positioned to return capital to shareholders at a wide range of oil prices. We would immediately focus on OPEX, where we have a very high fixed cost base at Bretaña. We will also be targeting substantial G&A cuts, as this is a metric on which we have not compared favorably with our peers. We will provide additional color on our cost-cutting initiatives with our 2026 guidance in January. The reality is that any savings we achieve will be pale in comparison to the $55 million of dividends that we pay out annually.
The simple fact is that dividends are by far the most powerful lever that we have at our disposal to preserve liquidity. We certainly hope to resume our return capital program as soon as possible, but that would only occur once PetroTal has achieved a structural reduction in its cost base. I will now pass the microphone back to Manolo to provide some closing remarks.
Thank you, Camilo. I would like to wrap up by pointing out that although our stock is understandably not reacting well to our announcement today, my conviction in PetroTal's investment case remains strong. As shown in slide six, the challenges we're experiencing right now are entirely above ground issues. I would like to remind you that our team has resolved many big issues before, including COVID and multiple river blockades. Right now, we're working around the clock to resolve our current issues as well. Bretaña is still a great asset, and I am confident that the barrel will still be waiting for us once we have expanded our water handling capacity to resume drilling and oil prices have improved. In the meantime, we're well capitalized to wait things out while we formulate a sensible development plan for the Bretaña field.
PetroTal has drilled 19 horizontal wells at Bretaña, and we still have 16 wells left out in our 2P reserve, plus an undetermined amount of inventory in the VS1 formation. In other words, we're still very much in the middle of this volume. These new wells, especially those in the VS2 sand, will require additional water disposal investments. The first 19 wells have seen Bretana generate over $400 million of free cash flow, of which we have returned more than $155 million to shareholders, and we paid a $100 million bond. These are real tangible returns that we have generated for shareholders and which we hope to replicate again in the future. In conclusion, I would like to thank our shareholders for their ongoing support. We look forward to providing more details on our 2026 development program in January. That wraps up our prepared remarks.
I would like to now turn the call back to Mark for questions.
Thank you, Manolo, Camilo. First question, where is the new drilling rig? It's been over a year since it was supposed to arrive on site. Why didn't you rent the old rig for a longer period until the new one was in country?
The rig is in Houston, in Conroe, Texas. It was supposed to arrive about mid-year this year, so it's going to be about a year delayed. The old rig is in the commission, and the old rig, we cannot use it for the new Bretaña wells, which is why we need to commission that rig.
Thank you. Can you share the scenarios or assumptions that led the board to the conclusion that dividend had to be completely suspended? Could 2026 estimated CapEx exceed $100 million despite only two wells being drilled? Any guidance on 2027 CapEx?
Like I mentioned in the remarks just now, we shared a couple of production profiles. Let's hypothetically assume a $60 oil price next year and a 15,000 bbl a day average production. With our current cost structure and discounts to Brent, that would mean the company would have a total sources of roughly $175 million. We have a starting cash balance, say, of $100 million for next year. Our uses, and we have to pay interest, taxes, debt, amortization, CapEx at CapEx levels, say, around $130 million, that leaves our ending cash at about $16 million. We have spoken to all of you in the past that we want to maintain at least $60 million in our cash flow. That is a little bit too conservative, but to us, it's prudent because we do not really know what's going to happen to our prices next year. As we finalize our budget, we want to make sure we have enough liquidity to have a good year.
Thank you, Camilo. Is water handling capacity maxed out, and how is this level compared to expectations a year ago?
The water handling capacity, it is currently maxed out. Part of the plan is to be able to expand that on an ongoing basis. The target right now is to bring it up to $240,000 from the current 170,000 bbl per day. As we drill more wells, we're going to have to continue expanding that water handling capacity. It's part of the plans. It's just taking longer to implement all of that.
Okay, next question. Please tell us about the leakages on the five wells. Does this indicate that preventative work will have to be done on the other older wells?
The issue with the tubing that brings the oil up to the surface is that we have corrosion caused by CO2 in the oil and the water. The chemicals that we were injecting were not reaching the proper point. We understand now the issue. We have already replaced a number of pumps where we have provided the corrective measures, and the ongoing cooling campaign will do that. Of course, there are other wells that were set up in the past. Right now, we do not see any evidence of any failures. We are hoping that nothing happens next year, but we just wanted to caution our investors that maybe we have more than one well that will also fail because of the same situation. The important thing is that we now understand the issue, and we have taken the corrective measures.
Okay, thank you. What happened to expecting between 500 and 1,500 bbl a day in additional production from Los Angeles after the workover?
When we did the workovers, we noticed that the existing cement behind five was actually not completely stopping the water from below. That then has forced us to evaluate how to remediate that while we plan to bring a drilling rig to start drilling an initial development well in Los Angeles. That is why production at Los Angeles has not increased. Now we have also a good understanding of what's going on, and we plan to ideally drill a well next year.
Are you going to buy back shares at these low prices?
We will continue to evaluate. I mean, our message today was clear in suspending our return to shareholders, and this is obviously one way of doing it. Depending on what share price does, it's something we'll continue to evaluate.
Thank you, Camilo. What are the reasons behind the equipment failures? Quality of product, poor installation, etc.? Were they identified as possible risks beforehand, and how can you ensure they don't happen again?
As I mentioned before, we now understand why it is that the chemicals were not reaching the proper point. Now that we are changing the pumps and the tubings, we are actually setting up the Electro Submersible Pumps much, much higher. That also reduces the cost of these replacements. It also reduces the amount of energy that we need to lift all of the fluids as the pumps are much, much higher, and also allows us to ensure that we have the chemicals at the right entry point, and we should not have issues in the future.
Okay, what's PetroTal's all-in corporate break-even oil price, including all costs and debt finance?
From a cash perspective, it's about $60 per barrel.
Okay, thank you, Camilo. There's an exploration commitment to drill two wells in Block 107 by February 27. Will today's update affect this commitment and any update in finding a farm-out partner?
The commitment that we have, we plan to have an extension given to us so that will give us more room to maneuver. We continue to try to find a partner or partners to come in. There are a couple of companies looking at information, so we will continue looking to be able to drill a well in the future.
Can you explain delays behind the rig? You didn't explain why it was going to be delayed by at least 12 months. Can you expand at all?
Yes, we had issues during the commissioning of the rig. We ended up switching contractors, and that has delayed the process all of this time, unfortunately. When you do a change in contractors, there's always delays, as you can imagine.
Okay. Can you give any more guidance on how much CapEx you may spend on increased water handling capacity and when? Has this expectation changed over the course of the year?
The expectation doesn't change. We have a plan that we try, ideally, to have the water disposal capacity at about the same time as we drill new wells. I have explained this since I raised the initial capital eight years ago. Unfortunately, it's always difficult to have a perfect match. As I mentioned earlier, from the 170, we want to go to the 240. Eventually, we're going to go to the 300 as more wells come in.
Thank you, Manola. Next question. It sounds like the need for increased water handling facility has been a bit of a surprise. Have the recent wells been seeing higher water cut levels than you expected?
You know, the water handling facility has not been a surprise. We always knew this. We always give examples to our investors that if we have 20 wells, we're going to have to manage 200,000 of fluid. And that's at 10,000 per well. The wells produce 15,000 bbl per day. Then you're going to have 300,000. That has always been that. Our original 3P cases had a total of 20 wells. I will provide that example to the investors. Amazingly, we are now surpassing the original 3P cases. That is something I promised investors that we would do, that we are limited right now on total fluid handling of about 200,000, which, again, initially, that was my 3P goal, 200,000. Right now, if I open all of the wells fully, we will be at 300,000. We are short. We need to carry out to add more handling capacity.
We believe we can go up to 240, and that will allow us to open up oil wells to bring an additional 5,000 bbl of oil per day in the next few months. We are working on that, which is why in that graph in the presentation I mentioned, with that, we will be somewhere between the two curves shown.
Thank you, Manolo. Looking at the reserves auditor's 2P profile and future development cost at year-end 2024, how much peak water handling capacity were they assuming? How much of the $645 million of the future development cost in the 2P case was for water handling?
How much was water handling? I will need to go back and check that. I see the person that asked that question to answer that. I do not have the number exactly with me. Again, given that the wells on average produce about 10,000 bbl of fluid, on the 2P case, we have 32 wells, so we are going to need to manage 320,000 bbl of fluid per day. That being the follow-up goal. From 170, 240, 320, and then we eventually actually, on the 1P case, nowadays, it is 32 wells. The 2P is 40 wells. That will mean that we will go to 400,000 in the future and beyond. The more we can process, the more oil we can produce, and the more money we can make because here we are to add value, not only production.
Okay, thank you. How much CapEx does the low-case Fuller 26 production profile of 12,000 bbl a day assume?
We will provide that guidance in January as we finalize the budget.
Thank you, Camilo. A follow-on. In light of production and the rethink on development, how are you seeing 2P reserves directionally versus year-end 2024?
We are going to end up producing about 7 million bbl this year. Given that there has been no drilling, I imagine the reserves are going to drop accordingly. 2P reserves were a substantial number of 108 million bbl. We are going to still have a lot of oil to be produced, as mentioned in my remarks, we're in the middle of the ballgame.
Okay, thank you. Manolo, Camilo, if you want to move on to any closing remarks at this stage, thank you.
I want to thank our shareholders for all their support. As we have mentioned, we have some headwinds against us right now. As also mentioned, these are all above-ground issues that we need to tackle, and we are tackling. I have promised also investors that this project was going to be a free cash flow machine, but that requires that we complement the number of wells with the water handling capacity because it could be truly a free cash flow machine in the future. This is a hiccup that we're going to have for a year or so, and we will try to go back to paying dividends as soon as possible. With that, I want to thank everybody.
Thank you, everyone.