PetroTal Corp. (TAL) Earnings Call Transcript & Summary

Hello, everyone. Thank you for joining the PetroTal 2024 Budget and Guidance webcast. Your host today will be Manolo Zuniga, CEO; and Doug Urch, CFO of PetroTal. [Operator Instructions]. I will now hand over to our presenters to start the webcast. Please take it away, Manolo and Doug.

Thank you, Jimmy, and good day, everyone, and thank you for joining the PetroTal 2024 Budget webcast, where we will provide a brief summary of our 2024 plans and guidance. My name is Manolo Zuniga, and I'm the President and CEO of PetroTal and I'm joined by my colleague, Doug Urch, Executive VP and CFO. If you have click on the link in press release, you should hopefully have signed to the webcast, so you may see the slides on your screen. But if you are having issues seeing them, please contact petrotal@celicourt.uk, and they will be able to assist you. Before I begin, I need to mention that there are certain disclaimers towards the end of the presentation, which I would urge you to read at your own leisure. In the front page, you can appreciate the beauty of the Pacaya Samiria reserve, just across the Puinahua channel. And to the left of our small footprint camp, the, Bretaña community, which is the largest of the 18 communities in our direct area of influence. Turning to Slide 2. PetroTal is an onshore Peru focused oil company with the shares listed on London's end market, in Toronto Stock Exchange and the U.S. OTC. Currently, PetroTal has a market cap of approximately $550 million and is projecting an EV over 2024 adjusted EBITDA ratio of 2.4x, when just a year ago it stood at just 1x. We have a 100% working interest in the Bretaña oil field, which we have expanded from first production in mid-2018 to over 20,000 barrels of oil per day, becoming the largest crude oil producer in Peru in just 5 years. The company is starting off the 2024 year in a position of strength, having averaged 20,000 barrels of oil per day in January thus far and currently producing around 22,000, 23,000 barrels of oil per day. We have some of very exciting plans in 2024 that Doug and I will touch on, followed by a Q&A after the formal part of the presentation. The Bretaña field is located at the Northern tip of Block 95 as you may see in the map. Currently, the 2022 year-end 2P reserves are 97 million barrels, which are half, an after-tax 2P NPV-10 per share of $1.75. The field currently has 17 producing oil wells and 3 water disposal wells capable of disposing approximately 50,000 barrels of water per day each. The company is able to deliver all of these in just a small 30 acre surface field foot print with peer-leading 6.96 kilograms per barrel of a scope 1 carbon emissions in 2022, down materially from 2021. Slide 3 summarizes our overall 2024 plans. We're planning on spending approximately $135 million in 2024, an increase of about 13% over 2023 CapEx. This will drive average production for the year to over 17,000 barrels of oil per day and deliver approximately 20% production growth on a gross basis and slightly more on a per share basis as we do share buybacks through the year. As we can see from the quarterly profile -- production profile, we are still planning conservatively for another extraordinary dry river season during Q3 and part of Q4. Though for Q1 and Q2, we plan to have exposure to our fuel capacity after accounting for typical 5% downtimes. The improvement from last year's 5.2 million barrels of production is due to increased sales optimization for the Brazil route and the activation of 2 new sales routes in 2024 that will turn recurring and commercial in the second half of the year. The dry season is less severe compared to prior years. We feel there is an excellent chance to outperform our production guidance. As I stated on Slide 4, the company will spend approximately $135 million in 2024 that can be divided into 3 components. The first component is continuous spending at Bretaña field, which will total approximately $107 million in 2024. This is roughly 10% lower versus 2023 due to no water disposal wells planned in 2024. The company plans on drilling 3 new oil wells in quarters 1 through 3, exiting with 20 oil wells by the end of the year. Interestingly, 20 oil wells was our regional 3P well count, which now stands at 36 wells after tripling all your reserves. Once the 3 new oil wells are completed by late summer, early 2024, the company will assess it's drilling rig upgrades or continued drilling depending on bring prices. The drilling portion of the 2024 budget totals approximately $50 million. The company will also allocate about $57 million to facilities in 2024 as part of the approved $107 million for the ongoing Bretaña development. This capital covers mostly carryover from projects not completed in 2023 as well as upgrades to the already installed central processing facilities including the CPF-3, debottlenecking the operating trains to allow for increased rates and is starting the CPF-4. By year-end 2024, nominal oil and water capacities are expected to be 25,000 barrels of oil per day and 140,000 barrels of water per day, respectively. And with the CPF 4, by the end of 2025, we should be able to handle 32,000 barrels per day of oil and 180,000 barrels per day of water. The second component is expanding for future sustainability and protection of the Bretaña field and nearby community from aggressive river erosion. This is a 2024 and 2025 project. This 2-year project has a CapEx portion directly benefiting our field will be around $40 million and will continue into 2025 budget at a similar spending level. As a reminder, the company spent approximately $10 million for erosion control in 2023 and completed an in-depth assessment on a long-term solution to prevent further river bank erosion with a leading international engineering firm specializing in coastal and river engineering solutions. The plan, as I mentioned before, is to carry out this 2-year project between the current year and 2025, will be giving us a permanent solution on the erosion. Lastly, the company will initiate a 2-year 2D sizing program in Block 95, South of Bretaña field, totaling approximately $30 million, of which $12 million is allocated for 2024. The [ exciting ] survey aims at validating our technical interpretation before your migration towards the structural needs map South of Bretaña. In addition, approximately $2 million will be allocated to Block 107, where require per meeting, while the company advances partnership discussions for this block. The company estimates there could be several commercial oil fields in Block 95, some of which have been internally estimated as both initially being as large as Bretaña. The slide 5 highlights the company's long-term strategy of being able to commercialize up to 70,000 barrels of oil per day. As mentioned in an earlier press release, the company continues to advance its planned dialogue of selling oil through the OCP, the heavy oil pipeline of Ecuador. We're still deciding which we report fits the company's long-term vision for this route, and we are working through the required approval processes. We will now aim to execute the OCP pilot revenue first half of 2024, with recurring sales estimated by Q4 2024. Also in 2024, we are aiming to commercialize on a recurring basis, the Yurimaguas route, which only require barge in to Yurimaguas and then track into the Port of [ Iowa ]. We're aiming to commercialize this route around Q3, 2024 and we are aiming to initially commercialize around 2,000 barrels of oil per day on each route. We eventually move to 5,000 barrels of oil per day on each one, as shown in Slide 5. I will now turn the meeting to our CFO, Doug Urch, who will provide a brief financial update.

Thanks, Manolo. On Slide 6, we now show the netbacks table for our 2 main routes and the estimated initial piolet netback estimates for the 2 new sales routes, the OCP and Yurimaguas. The right part of the table then summarizes the netback structure under a recurring optimized and longer-term commercial scenario, showcasing the strong netback comparison to our existing routes despite additional trucking pipeline, oil transfer and supervision costs needed. From an overall budget perspective and excluding some onetime expenses, the company will be able to generate an average netback of approximately $42 per barrel at $77 per barrel Brent oil prices. Slide 7 showcases the projected production and sales of approximately 6.22 million barrels and a Brent price assumption of approximately $77 per barrel in 2024. The company is expected to generate around $200 million in adjusted EBITDA, inclusive of the nonrecurring erosion and community support OpEx fees of $23 million and $7 million, respectively, in 2024. The company is assuming a Brent price assumption that is approximately $7 per barrel lower than previous year's guidance and believes in a strong macro backdrop for oil in 2024 that could provide cash flow upside in 2024. Royalties will include the 2.5% social trust allocation are in line with the previous historical run rates for this production level. From an operating expense perspective, and excluding the erosion component, the company will have OpEx per barrel of around $10, up approximately $1 per barrel from 2023. In 2024, the company is including budget amounts for trucking costs and oil transfer costs for the 2 new sales routes and inflation impacts in our fixed lifting cost contracts. The onetime erosion and community OpEx costs will equate to approximately $4.82 per barrel and are directly tax deductible. 2024 gross G&A will be roughly in line with the 2023 spend of $30 million for the year or approximately $4.82 a barrel. Included in G&A is $2.8 million of noncash compensation and $4.2 million of nonrecurring community support that when normalized, generates a per barrel of around $3.69. Free cash flow before working capital adjustments is expected to be about $25 million, this is estimated to be enhanced by $11 million to $15 million of positive net working capital cash flows during the year, taking the total to nearly $40 million due to the following: 500,000 barrel export at Bayovar, generating approximately $5 million in true-up revenue, estimated 2024 cash taxes of about $15 million, with the remaining 2024 accrued amounts of $25 million paid in 2025, upon completion of the annual tax returns, offset by accounts payable catch-up cash outflows related to 2023 erosion control costs. Exit 2024 unrestricted cash is expected to be in line with the company's return of capital policy and for every $3 per barrel increase in Brent in 2024, the company's after-tax free cash flow increases by $10 million. Finally, on Slide 8, the company expects to continue its monthly share buyback program at approximately $1 million per month, and PetroTal plans to maintain its base quarterly dividend of $0.015 per share along with dividend top-up payments to be determined at the declaration date pursuant to the company's dividend policy. Total estimated returns from the company's 2024 dividend and buyback plan represents about 12%, prior to any additional liquidity sweep enhancements based on a market capital of approximately $550 million. Note, the company returned approximately $57.5 million, 10% of existing market cap to shareholders in 2023. I thank you for your continuing investor support. I will now turn it back to Celicourt for the Q&A session.

Could you please come back to the exact benefits for the erosion management program? And what are the risks or the problems without that project? The total erosion cost amounts to $59 million, is that the overall cost of the project? Or can we expect more in 2025 and 2026? And are the total erosion costs tax deductible?

As I mentioned in the presentation, this is a 2-year project. It's starting in 2024 and ending in 2025. And this is a project to provide a permanent solution to the erosion control in our camp. As I highlighted in the initial slide, beautifully looks across the river, that's the Ucayalit river that -- when he joins the Maranon from the mighty Amazon River. So the erosion control is key. You can see in that picture, how close the facilities are next to the river. Of course, the camp was set up before us when [indiscernible] used to operate this, it made sense at this time to be very close to the river. And it's just a matter of taking care of the erosion, which now as the company has grown, we have the ability to do that. We have hired a top company that has done a similar project in Southern Peru very successfully. So we're confident that, that -- this will bring a permanent solution. It is tax deductible. And not only that, but we're also looking at the project to do work for taxes that we're working with the government to see, if we can do this through future income tax payments. And that's the way of managing this as well. But again, it's just a 2-year project, '24, '25.

One of your goals for 2023 was to reduce travel time to Manaus from 60 to 50 days. Where are you with that now?

We continue to do those efforts as you have seen in a couple of releases. We are now being able to upload the oil from the barges directly to the anchors. And that is fast-tracking things is allowing us to -- we want to move the margins faster. You may remember that last year, after the dry season, in -- at the end of December, we went back to 20,000, but the first couple of months of 2023 we had to constrain production. Now we have a much larger fleet and because of expediting the transfer of oil from maybe the barge to the tanker, allowing us to bring back departures. So this is why we are now producing today, we reported 23,000 barrels per day. So we are working hard to be able to manage the prices. We don't know what's going to -- mother nature is going to have throw to us this year, but we're confident, as we have shown in the guidance. We're increasing our production 20 years this year, and hopefully, we can do better than that and maintain that. We plan to grow production in the future. As we mentioned, we are setting our facilities to go to 30,000.

With the 2 new export routes operational by year-end '24, should we expect average production in 2025 to be at least 20,000 barrels a day, assuming oil price remains at current levels?

That's the goal and we are working really hard to be able to get that. So if you do the math, we can do the pilots at 2,000 for being on each side, eventually growing to 5,000. That will provide us 5,000. Why those routes are important is that they navigate -- we navigate it using the peruvian barges that are designed for the low river levels allowing us to move oil even in the dries part of a season. That will complement us -- what had been for years, that'd be the idea.

Can you please explain the specific rules around share buybacks and the reason why the company is sticking with the $12 million in buybacks for the year?

Well, pursuant to the Toronto Stock Exchange rules, we have in place, what's called a normal course issuer bid. And that allows our company to buy about 10% of its free float. And our free float represents about 280 million shares. Hence, we can buy about 28 million shares per year. So those are the guidelines that we're operating within for the share buyback.

Can you tell us a bit more about your upcoming exploration efforts on Blocks 95 and 107 and what we might see from these in the coming years?

We -- last year, we moved the Block 95 exploration, to the main section of the corporate presentation. It used to be in the appendix. And the reason is that we're gearing up to do the seismic survey that will allow us to see if we have closure in these leads. They are now leads. And if that is the case, we believe that the migration of the oil has continued going south. So if there's perhaps, there should be full of oil, our initial mapping of those leads show that it could be the size of Bretaña, even bigger some of them. So very excited about that. We have yet to get the final permit to carry out it safely. And that lookin at the feedback from the local communities, they're excited about the possibility given that, as you know, we were able to change the law on the kind of distribution. So they are hopeful that we find and they can develop and then they also expect their 2.5% as we have been done in Puinahua. So the communities are supportive for this. We just need to get these permit and see what this has to tell us, but we're quite optimistic. And Block 107 is mostly about getting a partner with doing the permit and fine-tuning some of the numbers. We're very excited about that prospect. That one is still we have it in the appendix because not until we have the permit to drill, there's no need to make a big press about it.

What does the full year 2024, $25 million finance cash cost relate to?

The $40 million is essentially all estimated accrued taxes. Of this amount, about $15 million will be paid in cash in 2024 and $25 million paid in cash in 2025. Note the tax amount used to be estimated is at a much higher level for 2024. However, projects like the erosion control have brought this estimate down because of their deductibility.

This question has 3 parts. So I'll just ask them one after the other. Is any of the additional spending on the field, either the additional OpEx or the CapEx likely to continue beyond 2024?

I imagine that this is referring to the erosion that I already explained before because it will go into '25, and that's it.

The statement refers to future drilling being optional beyond 2024. Given the investments in field capacity that is being made in 2024 and the rapid payback on wells, what factors would mean PetroTal did not continue drilling beyond 2024?

I believe the -- person asking the question misunderstood, if what I said. And what I said was that -- and as it is based on our budget, we are budgeting 3 new oil wells this year. That by Q3, we are done with those 3 wells. And at that time, we will assess if we go ahead and drill another oil well or a water disposal well in 2024. And then, of course, we will continue the development in 2025. We've been very cautious about the fact that oil -- our budget is based on $77 Brent. And so we provide flexibility given exactly because our oil wells pay out so fast. We see oil prices improving, we may decide just to carry on and drill another well in '24, preparing to the fact that by 2025, we're expecting to have a higher production capacity. As I mentioned, our 3 PKs as a total well count was 36, our 2 PKs has 29 wells. We just completed well #17. So we're basically about halfway in the development of this field. There's a long -- there's a lot of reserves that we are enjoying the benefit of.

And the final part to this question, is PetroTal overinvesting in the field capacity, if export routes appear to be constrained to below 20,000 barrels a day, at least while the ONP pipeline remains an unattractive route for export?

We are targeting to grow the capacity of selling oil up to 70,000 barrels per day. That sounds very right now, farfetched. That, of course, is going to require that the ONP, the pipeline owned by Petroperu goes back to full operations on a proper commercial basis like we used to have before because that will provide us that ability. But it's something important as we set up our units, their nominal capacity is 8,000 barrels per day. So by adding another 1 and going up to 32, what allows us also is to be able to do maintenance in the other ones and go from 32 to 24. We're trying to maintain production in the order of 25,000 in the future. So that extra unit will be very helpful, especially, when the new wells come in, like now that the new well came in at $7,500 per day, as you can imagine, we had to shut some other wells. I would like to be able to bring a new well and not having to shut other wells. So having that extra capacity will come very handy for us. So for maintenance, to be able to maximize production and the idea that we are going to maximize oil sales or as we expect to find other Bretañas in Block 95. So it stays a long-term plan. We go always step by step, as you guys know me.