PetroTal Corp. (TAL) Earnings Call Transcript & Summary

Ladies and gentlemen, thank you for taking the time for joining PetroTal's 2025 Guidance and Budget webcast. Your presenters today will be Manolo Zuniga; Camilo McAllister and Jose Contreras. [Operator Instructions] I will now hand over to the presenters. Please take it away.

Thank you, Jamie, and good morning, everyone, and thank you for joining PetroTal's 2025 Guidance webcast, where we are going to discuss our financial and operational forecast for the coming year. My name is Manolo Zuniga, and I am the President and CEO of PetroTal. I am joined today with Camilo McAllister, our Executive Vice President and Chief Financial Officer; and Jose Contreras, our Chief Operating 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 move right into the main financial metrics, our guidance press release. At the top of the page, you can see that for 2025, we're targeting an annual average production of 21,000 to 23,000 barrels of oil per day. The midpoint of production guidance, which is 22,000 barrels per day, implies 24% annual growth. Moving down to EBITDA and cash flow. PetroTal expects to generate $240 million and $250 million of EBITDA in 2025, assuming an annual average price, Brent price of $75 per barrel. Keep in mind, our EBITDA guidance is net of approximately $30 million of nonrecurring operating expenses associated with our erosion control project, which Jose will discuss more in a bit. PetroTal's Board of Directors has approved a capital expenditure budget of $140 million, which includes a total of 4 development wells at the Bretaña and Los Angeles fields. Net of cash taxes, I would expect PetroTal to generate after-tax cash flow of approximately $200 million in 2025, which implies $60 million of free cash flow after our capital program. This free cash flow is comfortably able to support our ongoing base dividend, which has annual funding requirements of about $55 million and our modest share buyback program. As Camilo will explain, we do this while maintaining $60 million of nonrestricted cash liquidity. As we have done in the past, we are prepared to consider top-up dividends when our free cash flow is tracking above forecast and subject to Board approval, of course. Moving to Slide 3. We have summarized our growth trajectory over the past few years, which is impressive. On the right-hand side of the page, you can see the midpoint of our updated guidance implies 24% growth over our 2024 average production, which was already a 24% increase over 2023. As our peers continue to roll out 2025 guidance, I don't think you will find many companies that are able to compound a 20% growth rate while supporting a material dividend. Running through some of the key numbers again, it is worth pointing out that even with nearly $4 per barrel in nonrecurring erosion control OpEx this year, our EBITDA netbacks are still expected to top $30 per barrel under our Brent oil price assumption of $75 per barrel. I realize the year is just beginning. But as 2025 moves along, we're excited to show investors how much free cash flow PetroTal can generate. When we eventually hit 25,000 barrels of oil per day, which is entirely possible by the end of this year, I expect PetroTal to be capable of generating run rate annual EBITDA of more than $300 million. Considering we are expecting together with just 4 new wells, that leaves a lot of room for dividend increases on all other business development opportunities. I will now pass the presentation over to Jose, who will discuss some of our major projects. Jose?

Thank you, Manolo. Please flip to Slide 4. I wanted to discuss some of the infrastructure investments that PetroTal will be making over the course of 2025. As Manolo mentioned in our guidance update this morning, our budget includes approximately $60 million for infrastructure investments this year, and I will give you an idea of how we are spending this money. The main component of our infrastructure program in 2025 is the completion of the fourth train of our central processing facilities at Bretaña. When complete, this expansion will increase our installed crude oil processing capacity to up to 32,000 barrels per day. The added capacity not only gives us the ability to continue to expand output at Bretaña in the future, it also provides much needed optionality to plan maintenance activities without compromising our output. Over the past few years, we have timed our planned maintenance activities during the dry season when we tend to have higher amounts of unutilized capacity. However, with the capacity we're adding in 2025, we will have more flexibility to manage maintenance year round. The other component of our infrastructure capital program is the construction of new drilling cellars, which PetroTal will need to accommodate its developing drilling program over the next 2 years. Given that we are running low on space in the field, the new sellers will require us to expand the boundaries of our lease. As a result, we are currently going through the environmental impact assessment process, which will allow us to begin construction around midyear, pending approval. On the next few slides, we have prepared a few pictures of how the erosion control project is expected to come together this year. On Slide 5, we have shown before and after pictures of the Bretaña facility. The picture on the left shows the current situation with our facilities in front and the village of Bretaña in the upper right corner of the picture. We have circled the riverbank area that will be targeted for improvement through the erosion control project in green. The length of this box is about 250 yards to give you an idea of the scale. As you can see on the picture on the right, we plan to construct a series of 5 breakwaters or groynes with the first real lying upstream of our lease within the village of Bretaña. Given that we can't capitalize the construction of breakwaters outside the boundaries of our lease, we will be accounting for the first 3 breakwaters as operating expenses. The breakwaters will be constructed first, which is why we are -- operating expenses will be higher in 2025. The remaining 2 breakwaters will be constructed on the premises of our lease and we classified as capital expenditures. We hope that to get these last 2 breakwaters started early in 2026 to then wrap up the project in the first half of 2026. On the next slide, we have included a few photos of how the construction process will look. These pictures were taken at another project in Peru in the Southern City of La Pastora, which is the reference for our project at Bretaña. The construction process basically consists of setting up a platform on the river while using heavy machinery to drive these steel piles 40 or 50 meters deep into the riverbed. These photos also give you an idea of the height of the breakwaters, which will stand 10 to 20 meters above the river depending on water levels. The erosion control project is expected to cost a total of $65 million to $75 million, spread over 2024, 2025 and 2026. I realize that may seem like a high number, but it is relatively small in the context of our remaining development capital for the Bretaña field, which still has more than 100 million barrels of 2P reserves to produce. We are looking forward to completing the project, which we believe will represent a permanent solution to the issue of the riverbank stability around our field and the community of Bretaña. I will pass the call over to Camilo, who will run through the financial numbers in our guidance release.

Thank you, Jose and Manolo, and a warm welcome to everyone joining us on the webcast today. I want to briefly touch on the key financial points from our guidance release. And as you can see on Slide 7, you will find very important numbers to help you with your financial models. In the middle column, we've outlined our expected production trajectory for the year. And as mentioned in our press release this morning, our new drilling rig is being imported to Peru and should start operations by midyear. Consequently, we anticipate relative stable production through the first half of 2025 as we conclude our drilling at the Bretaña this month. The right-hand column provides quarterly estimates for our capital expenditures. As you can see, our budget is front loaded towards the first half of the year, mainly due to the timing of infrastructure investments at Bretaña and the costs associated with importing and commissioning our new rig in Peru. Once operational, this new rig is expected to reduce our per well costs by approximately 10% to 15%. I would also like to highlight that PetroTal will start incurring cash taxes in 2025 with an expected total of around $40 million, most payable in March and April. This will necessitate a draw on our cash reserves during the first half of the year. Now to recap, we ended 2024 with a total cash balance of $115 million, including $103 million in unrestricted funds. This strong financial position ensures we can meet our funding needs, even before considering the recent increase in oil prices. Now as Manolo mentioned, our production guidance and budget are designed to be sustainable at $75 Brent oil, while maintaining $60 million of unrestricted cash liquidity that is always good to have as a cushion. So we are optimistic about the year ahead. Now moving to Slide 8. I also wanted to share some information on how we are allocating expenses for the erosion control project, which should hopefully give you a visualization of how the project will evolve over the next 18 months. As shown in the graph at the upper right, we began expensing materials for the erosion control project in Q4 2024. That is the light blue bar on top. These expenses amounted to approximately $10 million, which started the clock on the total project costs, which we estimate will amount to $65 million to $75 million by mid-2026. As we begin construction on the first 3 breakwaters in the first half of '25, most of the project costs will be expensed as OpEx. However, as we move to construction in the last 2 breakwaters in Q4, 2025, the project cost will mostly be allocated to CapEx. Keeping in mind that our '26 budget has not been approved at this point, we hope to wrap up the project by mid-2026, at which point, our cost structure is expected to return to normal. Well, that wraps up our prepared remarks, and we would now like to hand it back to Jamie for any questions.

[Operator Instructions] Moving on to the first question. Has PetroTal been able to renegotiate with Perupetro, the royalty rate for Block 131. If not yet, are you confident that it will happen before you start drilling in the Los Angeles field?

Yes. We've been discussing with Perupetro. We have had very good conversation with them. They are very keen to allow us to -- incentivize us to do investments in Los Angeles and grow production again. We see the upside to do that. So I'm very encouraged. I'm hopeful to be able to announce something sooner than later. Hopefully, by the time we have our year-end results. So that would be very encouraging.

Could you please talk...

By the way, it will allow us to fine-tune also our development plan, as you can imagine.

Could you please talk about the first Los Angeles well? Would this be a horizontal well targeting bypassed oil pools? Or would it also target those deeper sands you talked about?

So well, our plan is to employ a new modern drilling rig that we just recently purchased to drill our first wells in Los Angeles, and they could be either horizontal or deviated wells. And about the deeper pools, yes, we are certainly looking at that, and that will be part of our future plans eventually.

You point to a further $550 million of CapEx to develop remaining 2P volumes. I think there are 12 2P wells left to drill, costing between $11 million and $16 million per well. And I believe you already more or less have sufficient water handling capacity. So can you talk to what the balance of roughly $400 million of non-drilling CapEx is allocated to?

It's something that I have explained from the time when I was raising the initial capital more than 7 years ago. And at that time, we had a 2P reserves of only 37.5 million barrels is that when you have an oil field like Bretaña with highly permeable sands that is supported by a strong aquifer, what you need to do to maximize production, maximize profits, maximize recovery is to build the larger processing plant. And the bigger the processing plant properly sized, the more you're going to be able to recover, the more money you're going to be able to make. So right now, as of last year, we had 100 million barrels of 2P reserve as of the end of 2023. However, we had already produced close to 70 million barrels. So the EUR, the estimated ultimate recovery, was 170 million barrels, which means that from the initial plants, the amount of fluids that we need to manage, it keeps growing. And the bigger the plant means that we've been finding more oil in one single field. So I'm optimistic, and I have mentioned this several times in the past, that we should be able -- at the field at Bretaña, we should be able to recover 30%, if not more, of its oil in place. That we put us at north of 130 million of EUR, which means there's a lot of oil. So I want to put that in context because I know that people will probably -- investors are probably frustrated that we're adding more facilities and it's just managing the fluids. That's all. Because when we're done with the actual drilling, it's just a few other facilities and so on. So those 400 million that was mentioned is a combination of the drilling and some additional water handling. So although right now, we probably have about 170,000 barrels of water handling capacity, that is going to be short. So sorry for a long answer, but I have gone through this math in the past. When we started the company, we had 20 wells on the 3P case. And I used to say, 10,000 barrels of fluid per well, that's 200,000 barrels of fluid we need to manage a day. Now we have on the 3P case, 36. I wonder how many wells we're going to have when we announce reserves next month, but you get to keep it simple. You have, let's say, 40 wells, that's going to be 400,000 barrels of fluid. So therefore, you have to add more facilities. It's a lot of fluids and a lot of oil that once we are done with the CapEx, it's free cash flow, even now, of course, it's free cash flow. We've been free cash flowing for the last few years. I hope that answers the question, which I understand [ confirm better ].

Can you provide some rationale for the ongoing high level of facility spend on Bretaña? Can it really be explained by capacity growth? Why spend this money when the ability to achieve in excess of 20,000 barrels a day exported annual average is also still unclear? Surely, it is better to return more capital now rather than spend CapEx for possible use at some point in the future.

Let me complement. This sort of follows what I mentioned before. We have -- we are selling our facilities to manage 32,000 barrels of oil per day. These are in four piece of equipment, and you need to do maintenance. And you see always companies saying, production is down because we're doing maintenance. The way we're going to manage things is we do maintenance in one unit, so we still have enough for 24,000 barrels of oil per day. So very smart how we do this. And then which I just mentioned, how this field continues to grow. We have yet to add the reserves on the VS1, the top sand in the Vivian. So I'm trying to guide you very elegantly that we see that this field, which is a beauty, will have much more to deliver. So by taking this decision, it was very smart of us because we think that we're going to be able to use that quite often.

And in addition to that, it will also allow us to have flexibility to capture any upside as we are also targeting to open new routes such as the ONP and OCP.