PetroTal Corp. (TAL) Earnings Call Transcript & Summary

Welcome to the PetroTal 2024 Results Webcast. Your presenters today will be Manolo Zuniga, President and CEO; and Camilo McAllister, Chief Financial Officer of PetroTal. [Operator Instructions] I will now hand over to Manolo and Camilo. Please take it away.

Thank you, Jimmy, and good morning, everyone, and thank you for joining PetroTal's year-end 2024 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 some of our key financial and operational metrics. In the left-hand column, we have highlighted key production data from 2024 and 2025. As we disclosed back in mid-January, we're targeting annual average production of 21,000 to 23,000 barrels of oil per day in 2025. I am happy to report that our production has averaged just over 23,000 barrels per day so far in 2025, including approximately 600 barrels per day from the Los Angeles field, which we acquired in late November 2024. This is already a substantial increase from Q4 2024 when our production averaged 19,142 barrels per day and 2024 average production of 17,785 barrels per day. Although [ average ] oil prices were higher, it's important to keep in mind that we set our budget on the assumption of $75 Brent oil in 2025. And that is almost exactly what we have averaged year-to-date. With that in mind, we continue to feel comfortable with our existing guidance for annual EBITDA of approximately $245 million, which is expected to comfortably support our $140 million capital program. And most importantly, our dividend payments of approximately $55 million. On Slide 3, we have a chart summarizing our reserve growth since the company began operations in 2018. We released our year-end 2024 reserve report on February 20, but as part of our year-end results, we should highlight them here. As you can see on this chart, PetroTal has shown growth in all 3 reserve categories every year since 2018. We ended 2024 with proved reserves of 67 million barrels, which represents a 40% increase compared to year-end 2023. Meanwhile, our highest value PDP reserve volumes increased by 59% over 2023. Our reserve growth is largely due to an active drilling program at Bretaña where we completed 7 development wells in 2024 and also due to extended production history from existing wells, which has improved our independent reserve or evaluators confidence in the performance of our asset base. According to our independent reserve engineering firm, the value of our improved asset base increased to $1.1 billion at the end of 2024, which is obviously a substantial premium to our current market cap of around $430 million. This year, we will start work in the Los Angeles field, which is located in Block 131 and where we plan to do what we have done in Bretaña, I mean double or triple its current certified 2P reserves. Moving to Slide 4. We have compared PetroTal reserve replacement costs to its Latin American peers in 2024. Our PDP FD&A costs were just $6.85 per barrel, while our proved FD&A costs were $7.52 per barrel. Over the past 3 years, our cumulative PDP FD&A costs just $8 per barrel, while our average proved FD&A cost is $8.75 per barrel. As you can see from the chart on the right side of this slide, we have the best reserve replacement cost in our peer group over the past 3 years, where the average FD&A cost is approximately $20 per barrel. I think it's also worth mentioning that while PetroTal has shown the best capital efficiencies in the peer group, we have also had some of the highest netbacks. For every barrel of oil we produce, we're able to fund the development of 5.4 additional barrels of new oil, which is by far the best ratio in the peer group. In my opinion, these metrics are a sign of the quality of our asset base at Bretaña. This really is one of the best assets you will find in a small cap company in Latin America, if not the world. As mentioned before, the idea is to replicate this in Los Angeles. I will now pass the call over to Camilo who will run through some of our key financial results.

Thank you, Manolo, and good morning, afternoon to everyone. On the next few slides, we have summarized some of PetroTal's key financial data from 2024 and again, looking ahead into 2025. Hopefully, you have had the time to review our results, which we published this morning, but this table provides most of the key information from the release. So on the Slide #5, as you can see, PetroTal has shown strong production growth over the past year. Annual average production increased by 25% in 2024 to 17,785 barrels of oil per day. The Brent market saw a year-over-year price reduction of $2.55 per barrel. However, thanks to the hard work of our team on the ground in Peru, our total unit costs were essentially unchanged year-over-year. And therefore, the result is that our decline in our net operating income margins were roughly in line with oil prices over the past 12 months. Our net operating income netback was $42.68 per barrel in '24 compared to $45.39 per barrel in 2023. To separate erosion control project costs from core operations, we have introduced a dedicated erosion expense line in our financial statements. The $10 million Q4 expense was the project's largest. And our core margins should return to normal, providing a clear view of our underlying business performance. In 2024, we generated a robust $74 million in free funds flow, a significant achievement that underscores our financial strength. While this is lower than the $107 million in 2023, it reflects our strategic decision to invest in a larger capital program in the past year. Additionally, our net surplus was impacted by the necessary working capital adjustments related to things like taxes, derivative liabilities and the erosion control project. As these project-related expenses normalize over the coming quarters, we anticipate further improvements in both free funds flow and net surplus. Moving to Slide #6. We have prepared a summary of our production hedges. PetroTal has continued its proactive risk management strategy by entering into production hedges whenever Brent oil prices have traded above $80 per barrel. This provides stability as we execute our planned capital program for 2025. As you can see on the right-hand side of the slide, we have now hedged approximately 40% of our forecast production volumes over the remainder of 2025. The terms of our hedges are fairly consistent and simple. They provide a floor price of $65 per barrel with a cap of around $82.50 per barrel. And then the cap is removed to around $102 per barrel, beyond which point we fully participate in price upside. As of early March, our hedge portfolio had a mark-to-market value of approximately $7.1 million. Wrapping up our presentation today and moving on to Slide #7, I just wanted to close with our dividend history. PetroTal has recently paid its eighth straight quarterly dividend bringing our total return of capital under this program to $116 million or about $0.14 per share. Including our share buyback program, PetroTal has now returned approximately $125 million to shareholders over the past 2 years. Even with the recent decline in oil prices, I want to reassure investors that PetroTal remains firmly committed to a steady return of capital program. We have designed our 2025 capital program under the assumption that we will continue to provide a stable dividend, and this remains the case today. With the completion of our third-party drilling rig contract at Bretaña field, we've gained increased flexibility in executing our capital program. We maintain a strong position to adapt our plans as needed should the market conditions shift. With that, I would now like to hand the call back to Jimmy and please let us know if you have any questions.

[Operator Instructions] I will now go to our first question. Can you please give your best estimate as to when you will be able to recommend pipeline sales and what the immediate resulting increase in group production will be?

Yes, that's a good question. As we have been indicating that the company once we go back to the pipeline -- to the O&P later this year. As you all know, the pipeline is operated and owned by Petroperu, the state oil company. We've been having a number of conversations with them. A key criteria for us is if we go back into the pipeline to be paid at Pump Station 1 without assuming any type of derivatives and that for us will be key. We're hopeful and Petroperu's attitude is to be able to do a transaction that will allow us to go into the pipeline. Our target is to go in before the dry season starts. And the reason for that, and that sort of answers the second question is that last year that we had a really dry conditions in the Amazon Jungle, we lost about 300,000 barrels of production throughout the year, about 800 barrels per day on an average. And in 2023, we actually lost 360,000. You can get a sense how the team optimize operations that even on the worst dry conditions in 2024, we were be able to only lose 300,000 instead of 360,000, which is equivalent to 1,000 barrels per day. So the answer to the question is that we should expect once we go to the [indiscernible] during the dry season is to be able to avoid losing those 800 to 1,000 barrels per day and maybe do better than that.

Considering that the company is currently exporting from Bretaña near the capacity of its barge fleet, would it make sense to use the Ecuadorian route too.

We are doing quite well with the Brazil route, and we recently -- with my team, we visited Manaus and we saw the operations and we're confident that our trading quarter could do even better than the 20,000 barrels per day that they are doing nowadays. So I'm confident now with Brazil. Ecuador was a good option to look into. We did a pilot last year under the worst dry conditions. But right now, it's something that we know we can do in the future if needed. But for now, we need to concentrate in increasing the sales via Brazil and going back to the O&P.

If the fourth oil and water handling train was already completed, what would your production range be?

By the way, I forgot to mention that I have here with us also, Jose Contreras, our Chief Operating Officer, and I will let Jose answer that question. Go ahead, Jose.

Considering -- that's a good question. Considering oil and water treatment injection constraints, we should be able to produce up to 35,000 barrels per day.

What are the expectations for the 2 new wells that are going to be drilled in Block 131, how can you achieve a production level of 4,000 barrels a day or more in that block from the current 600?

We are planning to perform workovers on our existing wells, and also to drill 2 infill wells. And with those activities, we expect that by year-end, we should be able to exit at about 4,000 barrels per day of oil production.

Has the company considered pivoting from dividends to 100% share repurchases as a more efficient way to return shareholder capital?

Thanks for that question. We have certainly consider it, but we currently believe that dividends is the best way to return capital to our shareholders. We obviously monitor this on a constant basis based on our share price and our capital program, which currently we believe is a better investment for us. Now you also have to recognize that we have to keep in mind that this year, we have cash taxes and the erosion control project and other things where being conservative on a cash flow basis is a better option.

Has PetroTal been involved in conversations with Petroperu regarding LOT 192 and will PetroTal participate in the bidding for LOT 64?

We've been talking to Petroperu about those 2 opportunities. It's something that we have done at the request of the local communities. We have invited the local leaders to come to Bretaña and see how we operate. And they are flabbergasted in a way they have now seen about a real impact, positive impact, the oil business can have in the local communities. They are extremely excited. But putting that aside, we're reviewing the Block 64, it's a tender. And we don't know yet if we're going to submit a bid or not. And Block 192, they're still going through the process. You may have seen in the local press the selected partner, Altamesa, finally was not able to secure the financing for the project. So Petroperu is probably is going to launch another process to bring a partner for Block 192. And that's one project that we would like to review carefully. For now, there's nothing else to report except the fact that we are making sure the local communities see how a well-run operation and the benefit to the communities is done.

In a typical year, how many days/week/months does the central processing facility need to be in maintenance?

On a typical year, we have an overall downtime of facilities about 1%, in which -- from which the planned maintenance is less than a week per year.

Please, can the company elaborate on the anticipated advantages behind owning a rig and you perhaps provide an estimated annual cost savings for this item?

Okay. Thanks for that question because it's not typical for oil and gas companies to own rigs. That's why there are oil services companies that provide those. But you have to remember where we operate, we operate in a very remote area, we're getting equipment in and out and mobilizations are quite complicated. So the real benefit here is twofold. First, you have the flexibility of not being stressed about standby rates when you're in a drilling campaign and you want to stop and take a pause and do maintenance. And also, you have the benefit of controlling your capital program, the pace. So whatever happens with the oil price environment, you can always start and stop or control over your destiny. So we see that as a benefit. And in terms of savings, they will actually come from more having a rig that has lower nonproductive time because it's more modern, it's got better equipment, and we estimate or we're budgeting that to be in the order of 10%.

In the annual report, you mentioned that Ucawa has $82 million of tax losses. Could you perhaps elaborate on this?

Great question, and I'm glad you saw it because if we do a little bit of history with our company, you might recall that Bretaña had the same situation when we made the deal back in the day, it had $300 million worth of tax losses, which up until now have been fully utilized. And this is why 2024 is the first year where we're actually going to have to pay taxes in Peru, with the acquisition of CEPSA, now Ucawa is a stand-alone entity, it came with $82 million of NOLs. And we can use them as soon as the company begins to turn profitable and we can use them at the Ucawa Peru entity level. So that's something that will clearly help us.

Could you please update on the schedule and cost for the erosion control project? And secondly, field operating costs were up to circa $3 million versus Q3 2024. What drove that increase as field costs are largely fixed and not variable?

So erosion control, it remains, as we have announced earlier in the year, we expect to start field activities by the second quarter of this year and the cost, it remains between $65 million and $75 million overall as a project.

Are there any plans to drill Block 107 in the near future?

As we have mentioned before, our Board has to asked us to bring a partner for Block 107, and we have actually a process ongoing right now with some companies interested. I'm hopeful that we can secure a partner to go ahead and drill that exciting prospect.

[Operator Instructions] Next question, beyond the reserves auditor forecast and incorporating balance sheet and shareholder distribution considerations, what do you think would be a sustainable plateau production for Bretaña?

That's actually a good question because it allows me to go as I usually like into the past. When we started the company 7 years go, the idea was to have a plateau at 15,000 barrels per day, and then we move that up to total of 20,000 barrels per day as we reported in this release today, we're now beyond that. So the next step for us will be 25,000. So the reserve auditors don't pay attention to those details. They just forecast for us, I think it will be good to have a nice plateau at 25,000. And then as we continue developing the field, hopefully, we can go up to 30,000 barrels per day in the future. We were always looking at our balance sheet for that.

Thank you. There are no further questions at this time. So I will now hand back over to the presenters for closing remarks.

Well, as always, we'd like to thank everybody for listening to the webcast. And then for the exciting questions you ask and hopefully, you enjoy the answers as well. Thank you so much.

Thank you.