PetroTal Aktie

Hello, and thank you for joining PetroTal's Q2 webcast. Your presenters today are Manolo Zuniga, President and CEO; and Camilo McAllister, CFO. As usual, questions can be submitted via the platform during the webcast, and we'll do our best to answer them in the time available.

Manolo, thank you.

Thank you, Mark, and good morning, everyone, and thank you for joining PetroTal's Q2 2026 webcast, where we're going to discuss the financial and operational results we released overnight. My name is Manolo Zuniga, and I am the President and CEO of PetroTal. I am joined today by Camilo McAllister, our Executive Vice President and Chief Financial Officer. If you have clicked on the link this morning press release, you should hopefully see our slide presentation on your screen.

But before I begin, I should mention that there are some disclaimers towards the end of the main presentation on our website, which I encourage you to read after our prepared comments.

On Slide 2, before we get into the quarter's results, I want to step back and remind everyone why we believe PetroTal represents a compelling investment. Starting with the asset itself, PetroTal is the largest oil producer in Peru. We have 110 million barrels of remaining 2P reserves, representing $1.2 billion of net present value, NPV10 value against 32 million barrels produced to date. So we are still in the early innings of developing this field. Our track record speaks for itself. Since inception, we have invested $675 million in Peru, generated over $1 billion of EBITDA and returned more than $150 million to shareholders and also tripled the size of our Bretaña oil field.

Turning to the catalysts ahead of us. We're excited to restart our development drilling program in the fourth quarter of this year as we target a return to previous production levels of more than 20,000 barrels per day. Considering our production has recently been tracking around our annual guidance of 12,000 barrels per day, we expect to show significant growth in production over the next few months. We believe successful execution of this multi-well program represents a minimum meaningful rebate opportunity for the stock.

On the right-hand side of this slide, you can see our current production, financial and capital market snapshot. The first quarter -- first half of the year, production averaged 13,726 barrels per day, ahead of our 12,000 BOP annual guidance. We ended the second quarter with $137 million of total cash against just $37.5 million of total debt, a strong net cash position. As a reminder, our '26 guidance call for adjusted EBITDA of $110 million to $120 million and capital expenditures of $80 million to $90 million. 3

On Slide 3, I'd like to give an update on our operations at Bretaña and our preparation for the resumption of development drilling. In mid-July, we began a pulling campaign at Bretaña to replace producing tubing and electric submersible pumps in up to 5 wells. This work is already helping to mitigate production declines and sustain our production levels in the second half of the year.

Turning to our development drilling program. Preparations remain on track as we have increasing confidence in an early October spud. The Estrella rig, which we have contracted for an 8-well campaign is now in Peru, and we hope to have it at Bretaña by the end of this month. As you can see on this map, we have highlighted the first 2 wells in our upcoming drilling program, wells [ PT and PV ], circled in red, in the north half of the Bretaña structure. We are particularly excited about these drilling locations, which directly offset well 10H that has already produced more than 2.1 million barrels of oil. We look forward to notifying the market once the first well has spud, and we remain focused on returning PetroTal to sustainable production growth in 2027.

On Slide 4, I want to show you how we get to our 20,000 barrels per day production target for 2027, well by well. The grey shaded area of the left shows our historical product rates at Bretaña and Los Angeles going back to January of 2021. You can see the periodic step up as new wells have come online, followed by natural base declines in between drilling campaigns. That decline has continued through 2026, consistent with what we have discussed on prior calls as we pause developing drilling.

The color layers on the right-hand side of the chart shows our production recovery profile as our 8-well drilling program comes online, beginning with our first spud in October. Each color then represents one new well added sequentially to the base as our drilling completion crew move down the program. This production plot has been built using the median type curve from the 19 horizontal wells we have already drilled at Bretaña. So this reflects the actual proven productivity we have demonstrated in this field. As you can see, as each well is layered on top of the declining base, our total production builds through 2027, reaching a monthly average rate of 20,000 barrels per day by the middle of the next year.

I believe you will probably see us show daily production rates of 20,000 barrels per day by the first quarter of 2027, but it may take us until the middle of next year to sustain production at that level for a month or more. As mentioned before, the first 2 locations offset the 10H well. You may recall that this well delivered the highest initial production of any of the 19 wells we have drilled to date, a 30-day average rate of just over 9,000 barrels per day, being able to target offset locations near one of our best performing wells give us real confidence in the productivity of these first 2 new wells. However, as you can see on Slide 4, we are assuming that these new wells will average just 5,000 barrels of oil per day.

Before handing the call to Camilo, I would like to remind our investors that PetroTal's proposition is that we should be able to replicate Bretaña's success more than once, especially now using all the experience we have acquired during the past 8 years. I look forward to not only reporting on Bretaña's production revamp, but also about our future similar opportunities that some of our investors have repeatedly asked about.

With that, I will now hand the call over to Camilo to discuss our financial results.

Thank you, Manolo. Turning to Slide 5. We have laid out PetroTal's financial performance for the second quarter compared both to the prior quarter and to the same period last year. Production averaged 12,557 barrels per day in Q2, which was down 16% from Q1 2026 and down 40% from Q2 2025. As we've discussed, this reflects our natural decline in our production base during a pause in our development drilling, and it is a trend we will reverse shortly. Despite these lower volumes, our netback economics tell a much stronger story. Brent oil prices have increased $15.46 per barrel quarter-over-quarter and $24.56 per barrel year-over-year, and that flowed through to our bottom line. Net operating income per barrel has increased by $12.78 and $22.59, respectively, over those same periods. This is a really good illustration of how our business is built to capture upside when oil prices strengthen.

On costs, our operating expenses were essentially flat quarter-over-quarter in total dollar terms at $11 million. The increase you see on a per barrel basis from $8.46 to $10.11 is a function of spreading a relatively fixed cost base across fewer barrels. It is not a deterioration in our underlying cost structure.

Our adjusted EBITDA for the quarter was $43.5 million. That is up 24% from Q1 '26. On a year-over-year basis, it was down modestly, reflecting the substantially higher production base in Q2 '25. Our free funds flow came in at $32.4 million, up 26% quarter-over-quarter and 19% year-over-year.

Our net income was $4.8 million for the quarter, which reflects the impact of a $10.2 million noncash impairment charge related to the sale of the Amazonia-1 drilling rig. Excluding that item, our underlying earnings continued to strengthen alongside higher realized pricing. On a year-to-date basis, our first half 2026 adjusted EBITDA was $78.7 million, which puts us in good shape to hit our annual guidance of $110 million to $120 million.

First half 2026 capital expenditures were modest $15.6 million, with the bulk of our capital spending expected in the second half of the year as our development drilling program gets underway. We ended the quarter with $137 million of total cash, including $105 million of available cash. Available cash was up modestly from Q1 and Q2 2025 levels.

On Slide 6, we show our full year 2026 guidance summary, which you will also find in our corporate presentation. So I won't spend too much time walking you through every line, but I do want to use it to frame where our cash position is headed for the balance of the year. As we discussed on the last slide, our available cash position was largely flat throughout the first half of the year, ending Q2 at $105 million. That reflects 2 significant cash outflows in the first 6 months. First, a sizable tax payment and the retirement of a lease liability associated with our former drilling rig following its sale. We usually tend to see large cash outflows in March and April as we settle our prior year tax bill.

And also looking at the guidance summary itself, based on a 12,000 barrels of oil per day of average annual production and an $83.60 per barrel Brent assumption, we expect to generate $180 million of net operating income and about $170 million of EBITDA for the full year. And this is all after erosion control spend, G&A and realized derivative losses or gains. Against that, we are planning for an $85 million of capital expenditures. That represents a meaningfully more active back half of the year as our development drilling program ramps up, along with about $24 million of accrued tax and finance expenses. That leaves approximately $8 million of after-tax free funds flow for the year with no cash dividends contemplated in this guidance.

Now putting it all together, even accounting for that step-up in capital spending in the second half and after the tax and lease-related draws we saw in the first half, we expect to build our available cash position from approximately $105 million today to approximately $120 million by year-end. That reflects the combination of production growth, continued strength in oil prices and our disciplined cost control. And it's all a good illustration of how our cash generative power of this business even while we're funding our next leg of growth.

So with that, I will turn the call back over to Mark, and please let us know if you have any questions.

First question, does the company have any optionality to extend the new drill rig beyond the 8-well campaign?

Indeed, we do have the optionality. Let's keep in mind that the company has always drilled proved locations. And right now, we have a total of 13 proved locations. So of course, we intend to continue drilling. On a 2P basis, we have a total of 22 locations. So basically doubling the size of the field. So that gives you an idea. And the rig that has come all the way from Colombia, the owners want to keep it busy as long as possible.

When is the pulling campaign expected to be completed? And where do you see production leveling off to after that?

We should complete the campaign by the end of the month. As I mentioned in my remarks, the idea is to level off the rigs. So overcoming some of the declines. So the idea is to keep it at about the level as now.

Okay. Next question. Is the purchaser of the Amazonia 1 rig the same personal contractor doing the drilling in the fall?

No, it's not. The purchaser of the drilling rig is a company from Romania, a drilling services company from Romania. The rig is right in that country right now.

What's the status of true-up payments from Petroperu for the oil in the ONP pipeline?

Now that we have a new government in Peru led by Keiko Fujimori, the Petroperu issue is being discussed thoroughly by the government. So we will see how we can resolve that.

With flooding from El Niño predicted to start in December, will the company have to accelerate the erosion control program?

I think I mentioned in the last webcast El Niño phenomenon, it rains quite a bit in the Northwest part of Peru in the coast, in the Pacific Coast, while in the Andes and in the jungle, many times is dry. So actually, we expect the river levels to be lower, and we will manage that as we need to. We are careful to manage the erosion issues, and we expect the project to restart soon.

Okay. Given the logistical challenges in getting a rig to site, is the plan still to aim for a flat production profile around 20,000 barrels per day? Or would you be more inclined to drill at a faster pace?

The wells are drilled at the normal pace. So we cannot go faster. You have to be very careful when drilling the wells but the idea is to drill one after another. That's the idea.

Can you please talk a little about the current water processing situation, e.g., when will additional water disposal wells be required? When will more processing capacity need to be added?

You may remember that when we provided guidance at the beginning of the year, we mentioned that our water handling, we're estimating to be at 170,000 barrels of water per day. We've been able to improve that to about 180,000 now a little bit beyond that, which is one of the reasons we are able to maintain the current production levels. And the idea is then to step up those volumes as time goes by from 180,000 to 200,000 to 40,000 and so on. As we have more wells, we need to manage more fluids.

Thank you. In order to drill out remaining 2P and 3P locations at Bretaña, will additional land and/or permits be required? And if so, what's the likely time frame to obtain these?

We don't need more permits. The modified EIA that took us such a long time to get allows us to drill the entire 3P campaign that we have and additional wells. And we already bought some land just in case that the concept that we're managing now is to be able to develop fully the field with the current existing area that we have.

Okay. Next question. The tendering process for control has taken longer than expected. Any reason for this? What's the contractor market like for erosion control activities?

This is a great question. It has taken a little bit longer than we've expected. We are still on track to receiving proposals by the middle of August, evaluate them and kind of get going back in September. This is, of course, a project that had already begun. So any company that will restart the construction and the [indiscernible] wants to do visits to the sites. They want to review all the engineering work. They want to make sure that none of the learnings from the previous contractor happen again. So they are taking their time, and we're doing it very rigorously.

Are you in a position to give us a steer on the expected cost to get to water injection capacity of 320,000?

Not at this moment. This Is part of the studies that are being carried out as we speak.

When would you expect the riverbank work to be completed given the new contractor? Where would you see CapEx in 2027 incorporating the drilling campaign, the river work and water handling?

Yes, definitely. The Riverbank work will be completed by 2027. In terms of CapEx guidance for next year, it's still too early to say, but we will have an active drilling program, as Manolo mentioned, we still have 13 P1 locations to be drilled. And this initial contract with Estrella will take care of the first 8. And if you remember, each well takes about 45 to 50 days to drill, and we plan to do them back to back. So we plan to be very busy in 2027.

Okay. Next question. Some time ago, you mentioned in the conference call that you would have focused on operational cost reductions. Can you elaborate a bit more on what's been done so far and how this impacts Brent breakeven price?

Yes, absolutely. So we have been extremely focused on operational cost reductions. In fact, if you look at the quarter 2 numbers, they are down about 18% to our historical levels on an absolute basis. And in terms of year-on-year, you will see an extra 20% of savings, which is obviously tough when you have such a small facility with a fixed cost structure. But that continues to be a focus for the company despite where oil prices are. We want to make sure that when we grow our production by about 80%, which is happening soon, that all those barrels flow through the bottom line.

With Gran Tierra selling their holdings in Colombia and Ecuador, are they planning to keep that back in option [ in ] Block 107 or is that also sold?

We have not discussed this with Gran Tierra, and that project is still under evaluation. The reason they kept that option is that they really like that structure. So -- but we do not discuss anything with them.

Can you remind us what production contribution you're assuming from new wells this year? How much downtime do you assume for H2?

As mentioned in my remarks, we're assuming that the wells will come in initially at 5,000 barrels of oil per day. We usually assume a typical 1%, 2% downtime. We're not expecting any social issues like we used to have in the past as the company has done a fantastic job with social issues.

If everything goes as indicated, you mentioned that a reinstatement of dividends would be considered before year-end. Is this still the plan?

This is always under review. And given where oil prices are and how they continue to remain high and how well we're performing and hopefully, by the year-end, we will have more visibility on the result of those first wells, we will definitely continue to talk about it.

Okay. I think for now, that is all the questions that have been submitted.

Well, as always, I want to thank all of our shareholders for their support for the company. And thank you, Mark, for taking this up. Thank you.

Hello. Thank you for joining PetroTal's Q1 results webcast. Your presenters today are Manolo Zuniga, President and CEO; and Camilo McAllister, CFO. As usual, questions can be submitted via the platform during the webcast, and we'll do our best to answer them in the time available. Manolo, can I hand over to you? Thank you.

Thank you, Mark, and good morning, everyone, and thank you for joining PetroTal's Q1 2026 webcast, where we're going to discuss the financial and operational results we released overnight. My name is Manolo Zuniga, and I am the President and CEO of PetroTal. I am joined today by Camilo McAllister, our Executive Vice President and Chief Financial Officer. If you have clicked on the link in this morning's press release, you should hopefully see our slide presentation on your screen.

But before I begin, I should mention that there are some disclaimers towards the end of the main presentation on our website, which I encourage you to read after our prepared remarks. On Slide 2, we have provided a summary of our key operational and financial metrics. Starting on the left-hand side, we highlight our recent production performance.

In the first quarter of 2026, PetroTal delivered average production of approximately 14,900 barrels of oil per day, modestly lower than the prior quarter. As we will discuss later in the presentation, we remain comfortable with our full year production guidance of approximately 12,000 barrels per day. Reflecting the recent strength in oil prices, we have increased our EBITDA guidance to a range of [$10 million to $110 million], a significant increase from our prior outlook of $30 million to $40 million.

There is no change in our capital expenditure budget at this time. While we invest $7.6 million in the first quarter, we expect activity to accelerate in the second half of the year as we resume our development drilling program. Based on our updated outlook, using forward current oil prices, we plan to end the year with a cash balance roughly in line with current levels.

On Slide 3, I would like to show our oil production and water injection capacity so far this year. The blue line shows the results of our recent water injection stimulation program, which we discussed in our press release this morning. Prior to the stimulation program, our water disposal capacity had been fixed at 170,000 barrels per day for quite some time.

Following the stimulation program, our water injection capacity briefly spiked to almost 200,000 barrels per day before settling at around 180,000 to 185,000 barrels per day over the past week. Our water injection capacity is important because the more water we are able to dispose, the more oil we can produce.

Current water cuts in our field range from 90% to 96%, averaging around 93.6%. So every 10,000 barrels per day of increase in water disposal allows us to produce approximately 500 more barrels of oil per day. Of course, the new oil wells will bring down the average field water cut. Our medium-term goal is to reach 240,000 barrels per day and eventually 320,000 barrels per day of injection capacity and beyond.

We have already seen a small boost in our production as a result of the stimulation campaign, and we would expect to see additional bump when we complete pulling jobs on 3 wells in Q3 2026. I would also like to point out that we have included our budget expectation in the red line in this chart.

This is the same line we published with our Q3 2025 results back in November 2025, and I am pleased to report that we have been trending about 3% above expectations year-to-date in 2026. As we pointed out in our press release this morning, we have not made any changes to our production outlook at this point, but it's nice to be carrying a small buffer as we approach the midpoint of the year.

Thank you, Manolo. Now turning to Slide 4. We have summarized PetroTal's financial performance for the first quarter of 2026. And as Manolo noted earlier, our average production during the quarter was 14,907 barrels of oil per day, which represents a modest decline relative to Q4 2025. Despite slightly lower production, PetroTal generated an adjusted EBITDA of $35.1 million in Q1 2026, which is an increase of 90% compared to the prior quarter.

Our business model is built to capitalize on higher oil prices. And with the recent strength in Brent, a large portion of our price gains flow directly into our earnings. If you look past the one-off expenses from late last year, the underlying growth in our EBITDA is very clear. To see the resilience of our model, it is helpful to look back at Q1 2025. Back then, we were producing over 23,000 barrels a day, even though Brent prices were similar to what they are today.

Our net operating income only decreased by about $2 per barrel. Maintaining those margins despite lower production volumes really proves how well we've controlled our costs. While higher oil prices provide a great tailwind, they will not distract us from our commitment to cost discipline. Reducing costs remains a core pillar of our 2026 strategy.

We are aggressively targeting lower spending in both operations and G&A, not just on a per barrel basis, but also in total dollars. This ensures that when we return to production growth next year in 2027, we'll be doing so from a much leaner and more profitable foundation. Moving to Slide 5. We are providing an update to PetroTal's 2026 EBITDA guidance in light of the recent strength in crude oil prices.

As a reminder, our original '26 guidance issued in January was based on an assumed Brent oil price of $60 per barrel. Under that pricing scenario, PetroTal expected to generate approximately $30 million to $40 million of adjusted EBITDA for the year. And as highlighted in this morning's results, PetroTal has already generated approximately $35 million of adjusted EBITDA during the first quarter of 2026, despite benefiting from elevated oil prices for only part of the quarter.

Looking ahead, we know the market remains volatile. However, if we look at current price trends as a guide and assuming an average Brent price of $83 per barrel for the rest of the year, PetroTal is positioned for a much stronger 2026. Under this scenario, we would expect to generate roughly $180 million in net operating income, which is double our original forecast.

If these price levels hold for the remainder of the year, the resulting adjusted EBITDA would move into the $110 million to $120 million range. At that level, our operations would fully fund our $80 million to $90 million capital program, while also covering all the taxes and financing costs. To be clear, these figures reflect the change in the market, not a change in our operational plan.

We're sticking to our production target of 11,500 to 12,500 barrels per day, and we'll continue to manage our cost structure aggressively. We will provide further updates as the year progresses and the price environment becomes more certain. Wrapping up with Slide 6, I want to briefly touch on our crude oil marketing dynamics.

Given the recent divergence between the spot and the future markets, we are often asked what pricing PetroTal is currently receiving for its crude sales. And as we've discussed on our last quarterly webcast, pricing for the Brazil export route, which represents the vast majority of our sales volume is linked to the high Brent month 3 price.

Prior to the escalation of the geopolitical tensions earlier this year, the Brent curve was relatively flat, making our realized pricing fairly straightforward to estimate. However, over the past 2 months, the market has become a lot more volatile and the Brent curve has moved into backwardation, meaning future delivery months are trading below the current month. In fact, Brent month 3 pricing has recently traded approximately $5 to $10 per barrel below the near month for extended periods.

While we would obviously prefer to capture the highest possible realized price, it is important to note that even the third month of the Brent strip has at times exceeded $100 per barrel in recent weeks. Accordingly, when we reference realized oil prices in our guidance and cash flow sensitivities, those assumptions are based on a Brent month 3 pricing rather than current spot prices. With that, I will turn the call back over to Mark, and please let us know if you have any questions.

First question. Given April was one of the highest price months for oil in recent history, can you expand on why you've chosen to conduct maintenance, which has the effect of reducing production, albeit temporarily?

So as I explained in my remarks, we did not do maintenance. What we did is work on the water disposal wells to optimize the activity of those wells, which are allowing us to increase production. So what we did is very quickly allow us to be able to produce more oil to take advantage of the prices.

With the Iquitos refinery offline, it seems the Brazilian routes accounted for 98% of Q1 volumes. Could you provide an update on the refinery status and timing for normalization?

Yes. The issue is that the reason we are not delivering oil from Bretaña to Iquitos is that Petroperu and unfortunately, the state oil company is having financial issues and they're not paying on time. We cannot afford delivering oil and not getting paid. So that's why the Bretaña oil nowadays is going to the Brazilian route. We do sell a little bit from the Los Angeles field, but we try to manage very carefully how much Petroperu owes us.

Next question. Given forecast for a strong El Niño this year, is it fair to expect limited impact at current production levels?

We don't know yet. The El Niño has different patterns. Usually, it rains a lot in the coast, in the northern coast of Peru. But sometimes it could either rain or be dry on the Andes, which fit the Amazon River. So we don't know yet. It's too early. But right now, the river levels are quite high. So we should be okay, I believe.

And then on to the rig. Can you give us any general information on the jurisdiction the rig is in and the time line for its export? Are the risk provisions of the contract in terms of getting a rig to our camp and commencing drilling typical for the oil and gas industry? Are there any provisions investors should be aware of?

No, all provisions are typical. The rig is currently about to finish activities in Colombia, in the south of Colombia in an area called Putumayo, which borders with Ecuador. When it's rigged down and prepared for transportation or logistics, it will go first by railroad across the border from Colombia to Ecuador to a port in Ecuador, and it will navigate to the Napo River all the way to the Peruvian border and then to our field. This is about a 1,000-kilometer journey, and it's all on time to continue with our program of drilling in October.

And just to add, most of our production equipment, we purchased from Ecuador and we use exactly the same route, so we're very familiar with that.

If the oil pricing continues and EBITDA is as indicated for the year as per the presentation, will you issue a special dividend?

At this time, the company is not considering a special dividend. Let me remind everybody kind of our capital allocation framework. First, obviously, we want to execute our capital program. Our focus is on resumed drilling and continue to optimize our water fluid handling capacity.

Second, we would first reduce debt. And third, we could evaluate some return of capital options. But this is something we will not consider until we have stabilized our production at the levels that we want and that we are expecting to be in during 2027.

Can you please identify the source of cost savings of circa $2.5 million versus Q1 '25 and $9 million versus Q4 '25 and how sustainable these savings are?

There are 2 sources of savings. There are savings in G&A and there are savings from our operating costs. The bigger variance that you just described against the fourth quarter of 2025 has to do with the pooling jobs and the workovers that we performed at the end of last year. We did not perform any of those during the first quarter. So that is the main variance.

At this stage, there are no further questions. Let's just give it a second to see whether any others come through. Okay, can I hand it back, Manolo, Camilo for any closing remarks?

Yes. Thank you so much, Mark, and I would like to thank all of our investors for their support. We're very excited about having a drilling rig back in Bretaña drilling and increasing production once again as we guided last year. Thank you so much.

Hello. Thank you for joining PetroTal's Q4 2025 webcast. Your presenters today are Manolo Zuniga, President and CEO; and Camilo McAllister, CFO. [Operator Instructions]

So I'll now hand over to Manolo. Many thanks.

Thank you, Mark, and good morning, everyone, and thank you for joining PetroTal's year-end 2025 webcast, where we are going to discuss the financial and operational results we released overnight. My name is Manolo Zuniga and I am the President and CEO of PetroTal. I am joined today by Camilo McAllister, our Executive Vice President and Chief Financial Officer.

If you have clicked on the link in this morning's press release, you should hopefully see our slide presentation on your screen. But before I begin, I should mention that there are some disclaimers towards the end of the main presentation on our website, which I encourage you to read after our prepared comments.

On Slide 2, we have our usual summary of our key financial and operational metrics. In the left-hand column, we have highlighted key production data from 2025 and 2026.

In 2025, PetroTal delivered average production of approximately 19,500 barrels of oil per day, representing a 9% increase over 2024. However, production declined throughout the year with Q4 2025 production averaging approximately 15,300 barrels per day, reflecting operational constraints at Bretaña. As we have previously disclosed, these constraints are primarily related to water handling and reinjection capacity, which remain the key bottleneck to restoring the more than 5,000 barrels per day of shut-in oil production.

Looking at 2026, we're off to a stable start with year-to-date production averaging approximately 15,000 barrels per day, including a small contribution from the Los Angeles field.

From a financial perspective, PetroTal generated adjusted EBITDA of $166 million in 2025 and free funds flow of approximately $90 million, demonstrating the resilience of the business despite lower oil prices and reduced production in the fourth quarter. Importantly, we ended the year with a large available cash position of $112 million, which provides the flexibility required to execute our operational priorities in 2026.

On Slide 3, we have a chart summarizing our reserve growth since the company began operations in 2018. While 2025 was a transition year operationally, I am pleased to report that our reserve volumes were largely unchanged. We maintained 60 million barrels of proven reserves and 110 million barrels of 2P reserves, after having produced just over 30 million barrels of Bretaña -- from the Bretaña field to date.

Our development strategy continues to be supported by a robust technical model and a large original oil in place, which underpins our confidence in the long-term growth potential of the field. As we move into 2026, our focus is on restoring production momentum by resuming development drilling, which we believe will unlock further reserve upgrades over time.

In our press release this morning, we announced that our Board has approved the award of a contract to a third-party drilling contractor, a key step in resuming our development drilling program later this year. The Peruvian regulators have also approved our Modified Environmental Impact Assessment for the Bretaña field, which gives us permission to drill up to 23 more development wells at the field.

As shown in Slide 4, based on the 2P forecast, shown in dark blue, this will allow us to maintain a 20,000 to 25,000 barrels of oil per day plateau for several years, starting about a year from now. Water handling will of course play a key role in our ability to do so, which is something our new Chief Operating Officer is already working on.

On Slide 5, I'd like to take a moment to provide an update on our erosion control project, which remains a critical component of protecting the long-term integrity of the Bretaña field. As many of you know, this is a significant infrastructure investment for the company, designed to safeguard our river bank and ensure the long-term sustainability of our operations.

In the past week, we have made the decision to terminate our contract with the project construction consortium due to noncompliance with contractual and execution requirements. Our focus now is on moving quickly and decisively to reestablish execution momentum. We have initiated a procurement process and expect to select a replacement contractor by June 1. Once the new contractor is selected, we will be able to provide a revised project time line and cost estimate.

I would like to emphasize that this is a manageable execution issue, not a change to the strategic importance of the project. Strengthening the river bank remains essential to the long-term development of Bretaña, and we are fully committed to completing this work to a high standard.

With that, I will now hand the call over to Camilo to discuss our financial results.

Thank you, Manolo. Moving to Slide #5 (sic) [ Slide #6 ], we have summarized PetroTal's financial performance for 2025.

And as Manolo mentioned, our average production for the year was 19,473 barrels per day, while fourth quarter production averaged 15,258 barrels per day. The company generated an adjusted EBITDA of $166 million in '25, and that compares to $237 million in 2024, primarily it's reflecting the lower realized oil prices and reduced production in the fourth quarter. Our net income for the year was $44 million, and that compares to $111 million in 2024.

Now despite these headwinds, PetroTal generated free funds flow of $90 million, which represents an improvement over 2024. This was all supported by a significant reduction in our capital expenditures, which totaled approximately $75 million in 2025, compared to over $170 million in 2024. In the fourth quarter specifically, adjusted EBITDA was $18.5 million, reflecting the impact of lower production and oil prices during the period.

Finally, we ended the year with $139 million of total cash, which includes approximately $112 million of unrestricted cash, which provides a strong liquidity position heading into 2026.

Wrapping up with Slide #7, I want to briefly touch on our cash flow outlook at prevailing prices. As we have discussed in the past, PetroTal maintains a high degree of operating leverage relative to oil price fluctuations. And while the move from our $60 per barrel budget guidance to the current $100 per barrel environment is a significant tailwind, it is important to remember our realized pricing at Bretaña is linked to ICE Brent Month 3. This means there's a natural delay before these triple-digit spot prices fully flow through our top line. However, as these higher forward prices begin to settle into the 3-month look-ahead, the impact on our cash flow profile could be positive compared to the start of the year.

While our focus is to remain disciplined and realize that the market volatility can shift quickly, the current environment could boost our liquidity. Accounting for the ICE Brent Month 3 pricing, we expect that once the current $100 Brent environment is reflected in our sales cycle, our monthly cash flow could average approximately $17 million. This provides us with a robust cushion to execute our strategic priorities even if prices normalize later in the year.

But keep in mind that our production is expected to decline throughout the year from our current levels. And at our average production guidance of approximately 12,000 barrels of oil per day, we would expect to generate average monthly cash flows of approximately $12 million if we were to assume $100 Brent oil pricing. However, I would like to stress that these numbers are for illustrative purposes only. No 2 months are exactly alike.

And I would also like to add that we are not making any changes to our guidance at this point. Commodity prices are very volatile at the moment, and it should go without saying that our revenue and cash flow can be expected to fluctuate with the price of oil.

Our priority in 2026 is to execute our cost efficiencies that we provided guidance on and our capital program of $80 million to $90 million, which will result in reinvesting in the business with a focus on what Manolo has already mentioned, which is expanding our water handling capacity at Bretaña, advancing the erosion control project and resuming the development drilling by October of 2026.

Importantly, PetroTal remains in a strong financial position with no near-term capital commitments and a robust cash balance, allowing us to execute this plan while managing commodity price volatility. Over time as production growth resumes and cash flow improves, we expect to revisit our return of capital framework.

With that, I would like to now hand the call back to Mark, and please let us know if you have any questions.

Thank you very much, Camilo. Okay. First question, are there any opportunities to increase water handling in 2026 in advance of the October drilling program?

Indeed, we are actually working to try to expedite the increase in the water handling capacity from the current 170,000 barrels per day to hopefully 240,000 by year-end. So that will be fantastic.

Just to give you an idea, an extra 70,000 barrels of water handling, at a 10% oil cut, that you can have like 5,000 barrels more of handling. So that's the importance of doing this, which sort of matches the amount of oil we have now shut-in because of water handling.

Thank you, Manolo. Are you expecting a considerable or negligible upward revision in cost to complete the erosion control project? What's caused the delay? And hopefully, the $31.1 million has gone to good use.

Thank you for this question. And let me address it by probably just going back to what Manolo mentioned. We had to take the decision to terminate our contract with the consortium due to noncompliance on their contractual execution requirements. The pace was not what we expected and the safety performance as well. So we have taken decisive action to intervene this and make some tough choices, but necessary changes.

Now let's step back a minute. The erosion control project, you might all remember, was guided as an 18-month project with a range -- an investment range between $65 million to $75 million. To date, if you take the middle of the range, $70 million, we have executed about $35 million. As of the year-end, it was $31 million; as of today, it's roughly $35 million.

That investment has been well made, and it's obviously there and we've made progress. But we want to do it -- we want to finish it and we want to continue to execute on it. We need a new pair of hands to help us to do that. And we'll come back to the market when we have those details with a more precise time line and revised cost.

Thank you, Camilo. Please, can you provide an update on Block 107, which needs 2 exploration wells drilled, completed before February 2027 expiry date? Is the plan to use the drill rig that's mobilizing in Q2 this year to drill these Block 107 wells?

We're still working on the permit to be able to drill the well in Block 107. Recently, Perupetro has given us an extension given the delay on the drilling permit. So that's very good.

And about the drilling rig we're taking to Peru, that's going to be staying in Bretaña as we have a lot of oil to be developed at Bretaña. So we will need to bring somebody else, another rig for Block 107. And of course, we are looking for a partner for Block 107.

Okay. Next question. Now that the MEIA-d has been approved, are you in a position to begin construction of the new well cellars that were outlined in the original 2025 budget? And if so, has that work already begun?

Yes. We are already working on it. So we will have the cellars completed by the time we start drilling wells. And the idea is to have cellars also to continue the drilling campaign in the following year.

Thank you, Manolo. Are there any plans to drill at Block 131, which was producing 4,000 barrels a day a decade ago?

Given our focus on drilling in Bretaña, what we have decided to do is bring a partner for the Los Angeles field that will be best -- so that's what we're working on, to bring somebody to help us on that.

Next question. Can you give us an update on the approximately 1.9 million barrels still sitting in the ONP? Are there any active discussions around the sale or settlement of those volumes, particularly in light of the ProInversion process?

The oil is still sitting in the pipe. It's going to stay there for quite a while. I think in discussion with ProInversion, trying to help them, the idea and what they're trying to do is bring an international pipeline company to take over the pipe and also bring someone for Block 182, which could allow oil to start flowing again. But it's going to take some time.

Will the first well to be drilled be a new production well or is a water injection well? Is there enough surface water handling capacity to enable a new water injection well to operate at full injection capacity?

The first wells are going to be oil wells. We want increased production. So what it will force us is to shut in some of the high water cut wells. That's how, as I mentioned in my notes, we plan to be at more than 20,000 by next year.

Eventually, and as I also mentioned, we intend to increase water handling capacity before year-end. So that will also help quite a bit. Eventually, we need to increase the water handling capacity from the 170,000 currently to 240,000 that I mentioned, eventually to 500,000, even 800,000 barrels per day of water handling.

Are there any intentions to hedge at these new oil prices?

Yes, we have been hedging since December. We've executed hedges for about 1.5 million barrels of forward oil production through March of 2027, covering approximately 24% of our estimated production.

These hedges have been primarily consisting of costless collars. On average, we have a Brent floor price of $60, a ceiling of $73 and a cap of $93. We obviously continue to monitor opportunities as the Iran conflict continues to be longer than everybody expected and the forward curve continues to increase. So this is something that we are actively looking at. But so far, we've hedged about 24% to 25% of our production.

Thanks, Camilo. There appear to be no further questions at this stage. Can I hand back to you, Manolo, for any closing remarks?

Thank you, Mark. And as always, I would like to thank our investors. We are working really hard to bring production back in Bretaña, as I mentioned. We intend to be above 20,000 a year from now, and we will do that. And we will complete the erosion project as we intended. So thank you so much to everybody.

Good afternoon. Thank you for joining PetroTal's 2026 Guidance webcast. Your presenters today are Manolo Zuniga, President and CEO; and Camilo McAllister, CFO. Questions can be submitted via the platform, and we'll do our best to answer as many as possible in the available time.

I'll now hand over to Manolo and Camilo. Thank you.

Thank you, Mark, and good morning, everyone, and thank you for joining PetroTal's 2026 budget and Guidance webcast. As mentioned by Mark, my name is Manolo Zuniga, and I am the President and CEO of PetroTal. And joining me today is Camilo McAllister, our Executive Vice President and Chief Financial Officer. If you join via the link in this morning's press release, you should see our 2026 budget presentation on your screen.

Before we begin, I would note that there are customary disclaimers at the end of the presentation, which I encourage you to review after our prepared remarks. This year's webcast is a bit different from prior years. Rather than presenting a growth-oriented budget, we're outlining what we view as a disciplined reset, one that is designed to protect liquidity, structurally reset our cost base and preserve the option value of the Bretana asset while oil prices remain under pressure.

With that context, let me begin on Slide 2, where we summarize the key production and financial metrics underlying our 2026 guidance. Starting with production, our 2026 guidance assumes an annual average of approximately 12,000 barrels of oil per day, which reflects the reality that any material production additions are unlikely to occur until late in the year. For context, production averaged over 19,000 per day in 2025 and exited the year at just over 15,000 barrels per day.

Despite lower production, PetroTal expects to generate approximately $90 million of net operating income and $30 million to $40 million of adjusted EBITDA in 2026, supported by aggressive cost reductions across both operating expenses and G&A. Our Board has approved a capital expenditure budget of $80 million to $90 million, which includes ongoing erosion control spending and assumes a resumption of drilling in the fourth quarter, subject to market conditions.

Importantly, this budget is designed to preserve liquidity. We expect to exit 2026 with approximately $60 million of available cash, which we view as a minimum operating floor for the business until production and cash flow improve. Camilo will provide more detail of the -- on the financial framework later in the presentation. But at a high level, this slide highlights the key theme for 2026, protecting value today while keeping the company positioned to grow when conditions improve.

Turning to Slide 3. We have restated PetroTal's core investment thesis. PetroTal remains Peru's largest crude oil producer and Bretana is an extremely high-quality oil asset with competitive economics at $60 Brent and is still under development. Critically, Bretana can continue growing profitably without requiring external capital, something our team is committed to do. PetroTal has already returned over $150 million to shareholders, underscoring our ability to generate free cash flow and our commitment to capital discipline.

Against that backdrop, 2026 represents a deliberate reset, not a retreat. The goal is to protect liquidity and asset value during a period of low oil prices while preserving meaningful upside leverage when the cycle turns. Slide 4 outlines the 3 core objectives and repeating our 2026 budget. First, protect liquidity. Capital allocation decisions are governed by a minimum unrestricted cash balance of $60 million. The capital program is aligned with internal cash flows and the budget targets approximately $30 million of adjusted EBITDA supported by improvement to our cost structure.

Second, reset the cost base. The budget incorporates significant reductions in our OpEx, lifting costs and G&A expenses, including a material headcount reduction in our workforce. These are structural changes, not temporary deferrals, and they materially lower PetroTal's breakeven. Third, we position for growth while 2026 is not a growth year. The budget assumes the option to resume drilling by October 1, with two development wells planned to be spudded during the fourth quarter of the year with the second one to be completed early in 2027.

This is expected to be the start of an eighth well campaign that will return production and capacity to what it was in the early 2025, assuming we're able to reset our cost structure as we aim to do. Taken together, this budget is designed to bridge the company through a period of low oil prices while preserving the long-term option value of Bretana. On Slide 5, we summarize the main elements of the 2026 budget. The approved capital program totals $80 million to $90 million, with development drilling expected to resume in the second half of the year.

I say second half instead of fourth quarter as I am still hopeful that we can expect sooner than later. Approximately $30 million to $35 million relates to the remaining erosion control expenditures. The cost structure reset is significant with a targeted reduction in OpEx of more than 25% and G&A approaching 20% versus 2025 levels. At year-end, we expect to maintain approximately $60 million of available cash, assuming an average Brent price of $60 per barrel, which is the planning assumption used throughout the budget.

The production chart on the right-hand side of this slide provides important historical context. PetroTal has grown production from under 1,000 barrels per day in 2018 to nearly 20,000 per day in 2025. The decline in 2026 mainly reflects a deferral in capital spending due to delays commissioning our drilling rig. With drilling expected to resume in Q4 2026, we fully expect to restore production capacity above 20,000 barrels per day before midyear 2027. In the past, we have seen similar behavior with continued drilling. Let's not forget that according to our 2024 year-end reserve certification, we still have 16 2P wells to drill.

I will now turn the presentation over to Camilo to discuss the basis of our strategy.

Thank you, Manolo. Slide 6 lays out the strategic reserve for the Bretana field. Our first priority is balance sheet strength. We maintain a strict cash floor to ensure we can cover onetime costs without internal stress. This capital discipline allows us to protect our liquidity today so we can reaccelerate activity as soon as the market visibility improves. Second, we are optimizing operations before reaccelerating growth. This includes a shift to third-party drilling and a focus on execution certainty over aggressive time lines.

Third, we are aggressively optimizing our cost structure. We are currently stripping out inefficiencies in G&A and operating costs while renegotiating service contracts to ensure a leaner base plan. These structural changes are designed to expand our margins regardless of the price environment. Fourth, we continue to preserve and enhance long-term asset value through phased infrastructure investment, particularly around erosion control and water handling capacity.

Finally, capital is allocated to our highest return projects. The development inventory delivers strong economics even under lower oil price assumptions and growth is based to liquidity, not oil price optimism. Moving to Slide 7. I will now focus on the financial assumptions underlying the 2026 budget. First, the budget is constructed using a $60 Brent planning price and assumes no material external financing.

Despite lower production, our cost reductions will allow the company to generate approximately $30 million to $40 million of EBITDA, fund the approved capital program and most importantly, maintain the $60 million cash floor. This budget restores flexibility. By structurally lowering costs and completing the erosion control, PetroTal improves its leverage to higher oil prices in future years. From a balance sheet perspective, the company enters 2026 with over $110 million of available cash, providing a strong starting position even in lower price environment.

On Slide 8, we have a high-level bridge that ties together the operational and financial assumptions underlying our 2026 guidance. We are modeling our production of 12,000 barrels of oil per day, and our financial planning is anchored by a $60 Brent price assumption, which aligns with current market consensus and provides a robust baseline for our capital allocation strategy. At that price level, we expect to generate approximately $80 million to $90 million of net operating income. From there, you can see the key cost items that shape EBITDA in 2026.

Erosion control operating expense is expected to be approximately $18 million, reflecting the OpEx portion of the project as it moves towards completion. G&A is budgeted at approximately $30 million, which includes an allocation for severance as we proceed with headcount reductions in our Houston and Lima offices. After these items, EBITDA for the year is expected to be approximately $30 million to $40 million.

Moving down the table, total capital expenditures are budgeted at $80 million to $90 million, which includes the remaining erosion control spend and the capital framework that preserves the option to resume drilling later in the year. Accrued tax and finance expenses is expected to total approximately $19 million, resulting in after-tax free funds flow of negative $60 million to $70 million for the year.

Importantly, that cash outflow is both intentionable and manageable. No cash dividends are assumed in 2026, and the budget is structured to conclude the year with approximately $60 million of cash on hand, which we view as our minimum liquidity threshold. So the key takeaway from this slide is that 2026 is a balance sheet protection year. The budget absorbs known obligations, completes critical projects and preserves financial flexibility while keeping the company well positioned for a return to growth when conditions improve.

I will now hand the call back to Manolo for closing remarks.

Thanks, Camilo. To conclude, 2026 is about a disciplined repositioning. This budget protects liquidity, resets cost, optimizes our operations and preserves the ability to return to growth. It is designed to safeguard shareholder value today while maintaining meaningful upside tomorrow. We believe this approach differentiates PetroTal and positions the company well for the next phase of the cycle. Thank you for your time. We'll now open the line for questions.

Thank you, Manolo. Thank you, Camilo. First question, can you please bridge current circa 15,000 barrels a day production at Bretana to the average 11,500 barrels a day for 2026, especially the assumptions around field and well downtime. The second part of the question, is there sufficient water handling capacity at Bretana to return to 20,000 barrels a day sustainably given that the field is currently constrained by water handling throughput?

That's actually a very good question. The reduction from 15,000 currently to the 11,500 for the year, it shows the normal decline on the oil production of the wells. These wells are all set up with electric submersible pumps, so I was saying the flow rates are consistent. Some of the wells can pull up to 15,000 barrels of fluid per day. On average, they are about 12,000 per day. So as the water cuts go up, the oil production drops. And that's why at the end, we end up with an average of about 11,500 to 12,500 -- the 12,000 that we have mentioned.

We do have wells that are now shut in because of the water handling constraints that the second part of the question mentioned. That gives us the ability that in case we have an issue with any producing well, we can open some of the other wells that are shut in. Right now, we have about 5,000 barrels of oil per day shut-in due to water handling constraints. So when the drilling starts again, these wells come in with higher oil cuts and what we do is we shut the higher water cut wells. And that way, we can quickly go beyond 20,000 once again. So that's the -- and eventually, we have to set up additional water handling capacity to be able to have as many wells open and that way also ensure that we can produce all of the 2P reserves.

Thank you. In light of operational challenges, please can you quantify what PetroTal's estimate of 2P reserves that will be extracted before the license expires will be?

Well, we are going to be publishing the 2P reserves next month. So work has been ongoing with Netherland, Sewell that certifies our reserves. But what I mentioned earlier sort of covers the concept, is adding sufficient water handling capacity so we can maximize the recovery of each one of the wells.

As I mentioned in my remarks, we still have a total of 16 wells, 2P, 8 in the 1P category and another 8 wells on the probable category. That number may be revised and -- should revise upwards, I believe, because as we continue producing, there's much more certainty in the durability of the wells, but we will see. But the key is us being able to manage the water handling facilities in the future to be able to extract all of the oil.

Okay. Next question. You state that the Amazonia-1 rig is no longer required in the near term and that you are now seeking to negotiate an exit from the leasing arrangement. To better understand what has occurred, I would appreciate a more detailed explanation of the key lessons learned that directly informs the decision to transition to a third-party drilling contractor.

There's a couple of things. When we decided to acquire the Amazonia rig is that we could not find any similar rigs in the region. We need a 2,000-horsepower rig, and we could not find one. That's when we decided to buy the Amazonia. Now there are some rigs available in nearby countries that we are procuring at the moment. And looking at the challenges of an oil company running a drilling rig by ourselves or using a third-party rig to lower the risk, we decided to go ahead and contract a third-party rig. So that's the logic behind this.

Can you give us more detail on the financing that you mentioned in the RNS? What would be your preference?

We don't necessarily need any financing for 2026 budget, as I stated on my remarks. At the end of the day, the company has enough cash flow to undertake its program. And our objective is to obviously preserve liquidity and maintain the $60 million cash buffer that we talked about.

Thank you, Camilo. What's the sensitivity of the guidance to the oil price? For every $1 change, how much does EBITDA change?

Our EBITDA per barrel is about roughly $10. So if you take our volumes, that would mean that it's about $3 million to $4 million impact for every $1 change.

Can investors expect a resumption of dividend payments in 2027 onwards, assuming the 8-well drill campaign is executed successfully and production volumes do reestablish?

We will see. But as we're going to be deploying capital for the drilling campaign, it's probably going to be difficult. I have, in the last webcast mentioned, probably we need to see into 2028 to be able to do that unless oil prices recover.

Okay. Another question with a couple of components to it. I have a few questions on the CapEx. One, the RNS talks about potential settlement costs for the acquired rig. Are these potential costs already provisioned in the budget? If not, what's the order of magnitude? Second part, the 2026 CapEx program includes circa $45 million for wells and drilling. It looks high versus the $15 million per well cost. Is the difference associated with rig mobilization or something else?

Thank you. Good question on the first point. Yes, these costs are already provisioned in the budget. And on the second question, the $45 million goes beyond drilling. So it's the fully burdened cost of having the facilities ready, the rig mobilized and therefore, the benchmark of $15 million, which is just the well cost is obviously a lower estimate. So $45 million is all in, fully burdened well cost.

Could you please elaborate more on the capital allocation of 2027 with 2 plus 6 wells by the end of 2027, what will production be in 2028?

That -- assuming that we drill the -- all of the 8 wells, as we -- our goal has always been to be above 20,000 barrels per day. So that's what we are targeting. But we don't have yet a budget approved for 2027, just to put a caveat.

Okay. What's year-end '26 and year-end '27 expected water handling capacity?

We're going to go in 2 steps. Right now, we have about 170,000 barrels of water per day. The idea is to go to 240,000 and then 320,000, and 240,000 will probably be by year-end '27 and 320,000 by year-end '28. That's the plan right now. And just to add more color, you go from 170,000 to 320,000, that's 150,000 barrels of water. You have an plan and oil cut of 10%, that gives you the ability to produce a lot more oil, as you can imagine. So that's the reason why, the more water we can handle, the more oil we can produce.

Okay, there appears to be no further questions at this stage. So can I hand back to Manolo and Camilo for any closing remarks.

Well, yes, Mark, thank you so much. And as always, I want to thank all of our investors. The set of questions that you guys have asked today they were fantastic, allow us to explain some of the rationale for 2026 and 2027. Thank you so much.

Good afternoon, and thank you for joining the PetroTal Q3 Webcast. Manolo Zuniga, 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, and thank you for joining PetroTal's Third Quarter 2025 Results Webcast. My name is Manolo Zuniga, and I'm the President and CEO of PetroTal, and 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 #2. 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 barrels 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 3. 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. And 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 7 wells on stream last year. If you consider that each of our horizontal wells produce more than 10,000 barrels of fluid per day, the 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 drilling rig to arrive at Bretaña early in the year. However, for a variety of reasons, that time line has now been pushed back by at least 6 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 barrels of oil per day of currently shutting production.

Turning to Slide 4. We have tried to summarize the range of production outcomes we are seeing in our development plan 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 a rig to Bretana by the middle of 2026. In this scenario, we believe it would still be possible to drill and complete 3 development wells by the end of the year.

Depending on production deliverability, it's possible PetroTal would exit 2026 with production in excess of 20,000 barrels per day. Enhancing our water disposal capacity, as mentioned before, will 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 for [indiscernible] 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 drilling rig to Block 131, where we don't have to invest in water handling capacity before bringing new development wells. We are also looking at options to secure a third-party drilling rig, which will 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. So please stay tuned.

I will now hand the microphone back to Camilo to discuss the financial implication of our announcements today.

Thank you, Manolo. On Slide 5, 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 Bretana, the reality is that we won't know our through 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.

So 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 will immediately focus on OpEx, where we have a very high fixed cost base at Bretana.

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. But the reality is that any savings we achieve will be paled 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, our conviction in PetroTal's investment case remains strong. As shown in Slide 6, the challenges we're experiencing right now are entirely aboveground issues. I would like to remind you that our team have 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 barrels will still be waiting for us once we have expanded our water handling capacity, resume drilling and oil prices have improved.

In the meantime, we are 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 reserves, plus underdetermined amount of inventory in the VS-1 formation. In other words, we're still very much in the middle of this [indiscernible]. These new wells, especially those in the VS-2 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 now to turn the call back to Mark for questions.

Thank you, Manolo, Camilo. So 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 midyear this year. So it's going to be about a year delay. And the old rig is decommissioned. And the old rig, we cannot use it for the new Bretana wells, which is why we decommissioned that rig.

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 2 wells being drilled? And any guidance on 2027 CapEx?

So 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 barrel a day average production. With our current cost structure and discounts to Brent, that would mean the company would have a total source of roughly $175 million. And we have a starting cash balance, say, of $100 million for next year. Now our uses and that 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 don't really know what's going to happen to oil prices next year. So 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. And part of the plan is to be able to expand that on an ongoing basis. And the target right now is to bring it up to 240,000 from the current 170,000 barrels per day. And as we drill more wells, we're going to have to continue expanding that water handling capacity. It is part of the plans. It is just taking longer to implement all of that.

Okay. Next question. Please tell us about the leakages on the 5 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 a corrosion caused by CO2 in the oil and the water. And that's -- the chemicals that we were injecting we're not reaching the proper point. So we have now -- 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 don't see any evidence of any failures. So we're hoping that nothing happens next year, but we just wanted to caution our investors that maybe we'll have more than one well that will also fail because of the same situation. But the important thing is that we now understand the issue, and we have taken the corrective measures.

What happened to you expecting between 500 and 1,500 barrels a day in additional production from Los Angeles after the workover?

When we did the workovers, we noticed that the existing cement behind [pipe] was actually not completely stopping the water from below. And that then has forced us to evaluate how to remediate that while we plan to bring a drilling rig to start drilling an initial well -- development well in Los Angeles. So that's why production at Los Angeles has not increased. But 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. And depending on what share price does, it's something we continue to evaluate.

Thank you, Camilo. What are the reasons behind the equipment failures, quality of product, poor installation, et cetera, will they be identified as possible risks beforehand and how can you ensure they don't happen again?

As I mentioned before, we now understand why is that the chemicals were not reaching the proper point. And now that we are changing the pumps and the tubings, we are actually setting up the electric 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 breakeven oil price, including all costs and debt finance?

From a cash perspective, is about $60 per barrel.

Thank you, Camilo. There's an exploration commitment to drill 2 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. And we continue to try to find a partner or partners to come in. There's 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. So 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? And has this expectation changed over the course of the year?

The expectation, it doesn't change. We have a plan that we try ideally to have the water disposal capacity at about the same time as we have -- we drill new wells. I have explained this since I raised the initial capital 8 years ago. Unfortunately, it's always difficult to have a perfect match. And so now, 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, Manolo. 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?

The water handling facility has not been a surprise. We always knew this. I will always give examples to our investors that we have 20 wells, you're going to have to manage 200,000 barrels of fluid. And that's a 10,000 per well. If the wells produce 15,000 barrels per day, then you're going to have 300,000. So that's always been that. Our original 3P case had a total of 20 wells. So I will provide that example to the investors. Amazingly, we are now surpassing the original 3P case.

That's 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. So we're short. So we need to carry up to add more handling capacity. We believe we can go up to 240,000, and that will allow us to open up oil wells to bring an additional 5,000 barrels of oil per day in the next few months, and we're working on that, which is why in that graph in the presentation, I mentioned, with that, we will be somewhere between the 2 curves as shown.

Thank you, Manolo. Looking at the reserves auditors 2P profile and future development cost at year-end 2024, how much peak water handling capacity were they assuming? And 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 can -- I see the person that asked that question to answer that. I don't have the number exactly with me. But again, given that the wells on average produce about 10,000 barrels of fluid, on the 2P case, we have 32 wells. So we're going to need to manage 320,000 barrels of fluid per day and that is the follow-up goal. So from 170, 240, 320, and then we event -- actually, of the 1P case nowadays is 32 wells. The 2P is 40 wells. So that will mean that we will go to 400,000 in the future and beyond. And 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 full year '26 production profile of 12,000 barrels a day assume?

We will provide that guidance in January as we finalize the budget.

Thank you, Camilo. And a follow-on, in light of production and the rethink on development, how are you seeing 2P reserves directionally versus year-end 2024?

Well, we have -- we are going to end up producing about 7 million barrels this year. And given that they have been no drilling, I imagine the reserves are going to drop accordingly. So 2P reserves were a substantial number of 108 million barrels. So 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 game.

Thank you, Manolo and Camilo, if you want to move on to any closing remarks at this stage.

Well, 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 aboveground 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 that requires that we complement the number of wells with the water handling capacity because it is to be truly a water -- a free cash flow machine in the future. So 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. Well, with that, I want to thank everybody.

Thank you, everyone.