Ladies and gentlemen, thank you for taking the time to join PetroTal's 2025 Guidance and Budget webcast. Your presenters today will be Manolo Zúñiga, Camilo McAllister, and José Contreras. If you would like to ask a question, please submit it via the platform, and the presenters will do their best to answer any questions you have in the time provided. I will now hand over to the presenters. Please take it away. Thank you, Jimmy, 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 Zúñiga, and I am the President and CEO of PetroTal. I am joined today by Camilo McAllister, our Executive Vice President and Chief Financial Officer, and José 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 two, we move right into the main financial metrics of our guidance press release. At the top of the page, you can see that for 2025, we're targeting an annual average production of 21,000-23,000 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-$250 million of EBITDA in 2025, assuming an annual average Brent price of $75 per barrel. Keep in mind our EBITDA guidance is net of approximately $30 million of non-recurring operating expenses associated with our erosion control project, which José 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 four 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 non-restricted cash liquidity. As we have done in the past, we're 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 three, 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 non-recurring erosion control OpEx this year, our EBITDA netback is 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 to get there with just four new wells, that leaves a lot of room for dividend increases or other business development opportunities. I will now pass the presentation over to José, who will discuss some of our major projects. José? Thank you, Manolo. Please flip to slide four. 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 plant 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 two years. Given that we are running low on space in the field, the new cellars 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 mid-year 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 five, 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 five breakwaters or groins, with the first three 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 three breakwaters as operating expenses. The breakwaters will be constructed first, which is why our operating expenses will be higher in 2025. The remaining two breakwaters will be constructed on the premises of our lease, and we classify it as capital expenditures. We hope to get these last two 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-$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 seven, 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 mid-year. Consequently, we anticipate relative stable production through the first half of 2025 as we conclude our drilling at 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%-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 eight, 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-$75 million by mid-2026. As we begin construction on the first three breakwaters in the first half of 2025, most of the project costs will be expensed as OpEx. However, as we move to construction on the last two breakwaters in Q4 2025, the project cost will mostly be allocated to CapEx. Keeping in mind that our 2026 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 Jimmy for any questions. Thank you very much. We will now commence the Q&A portion of the webcast. Just a reminder, if you would like to submit a question, please do so via the platform, and the presenters will do their best to answer it within the time provided. 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 conversations 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, and hopefully by the time we have our year-end results. So that'd be very encouraging. Could you please talk? And that, by the way, will allow us to fine-tune also our development plan, as you can imagine. Thank you. 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? 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. 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-$16 million a well, and I believe you already more or less have sufficient water handling capacity. Can you talk to what the balance of roughly $400 million of non-drilling CapEx is allocated to? You know, it's something that I have explained from the time I was raising the initial capital more than seven years ago. And at that time, we had 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 size, 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 estimate of recovery, was 170 million barrels. So 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're finding more oil in one single field. I'm optimistic, and I have mentioned this several times in the past, that we should be able at fields like Bretaña, we should be able to recover 30%, if not more, of its oil in place. That would put us at north of 130 million of EUR, which means there's a lot of oil. 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 once 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, you know, 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 know, keep it simple. You know, 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 you are done with the CapEx, it's free cash flow. Even now, of course, it's free cash flowing. We've been free cash flowing for the last few years. I hope that answers the question, which I understand it comes from Berner. 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. You know, let me comment then. This sort of follows what I mentioned before. We have satellite facilities to manage 32,000 barrels of oil per day. These are in four pieces 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 to do this. And then we 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. In addition to that, it will also allow us to have flexibility to capture any upside as we're also targeting to open new routes such as the ONP and the OCP. Yeah, exactly. Could you please expand on the progress of environmental permits for the 2D seismic survey in Block 95 and how a slim hole exploration drilling program in 2026 would be beneficial? If the second option is chosen, will you still need the 2D seismic survey? You know, in Peru, and companies that work in Peru, they always complain about how long the permits take to be awarded. 99.9% of the time they're given eventually, but it's really a painful process, and we expect this permit to come soon enough. We were expecting it to be awarded last year. It probably is going to be in the first half of this year, and that gave us time to think this through. When we hired an extremely experienced VP of Exploration that has experience in all of Latin America, he started looking at it with new eyes and mentioned to me. He said, "Manolo, what about we can actually fine-tune this?" We do slim holes. You know, there's all seismic. That's why we show in the presentations the leads. We are able to set up volumetrics, assuming that based on the experience that we have from Bretaña. What about we do drill some slim holes, and we actually verify if we have oil because eventually we're going to have water, and I thought that was a brilliant idea, and he actually added, and he said, "You know, your team in Lima is actually thinking the same way," and I said, "Well, let's look into this," and maybe the permit could come even at the same time as the seismic, and I thought, "Wow, this is pretty neat," so we test a few of these structures. We actually verify that there is oil underneath, then we only do the seismic where we have found that there is oil, and we save us money. At the end, I think it's going to be much better for us doing it this way. I'm happy that we had hired Max Torres, that used to be VP of exploration at Repsol, as well as in Ecopetrol, an extremely experienced person. I'm very happy with this. When this will happen, it's difficult. Again, permits, but eventually it's going to happen, and we will maximize the value now of the entire Block 95. Thank you. Is PetroTal planning to use the OCP route in Ecuador this year? And is there any progress regarding the availability of the ONP route now that Petroperú has stated that it's one of their main priorities in 2025? Regarding the OCP, as we had reported in the past, we did not finish the pilot that we started last year. So we want to finish the pilot. In fact, when we started the pilot for the OCP, it was under the worst drought conditions in the Amazon jungle. So I think it's important for us to finish that under better conditions, get a good evaluation. After that, we will evaluate if we move forward or not. Regarding the ONP, I'm very happy to say that we've been having excellent meetings with Petroperú, and they really want us to go back in. Our only condition is that we will not assume any liability like we had in the prior contract where there would be a price settlement once the oil came out at the other side of the pipeline in the port of Bayóvar. So that's the only condition that we have is on managing that. So I'm encouraged that later this year, I'll be able to give you some good news on that regard. We know the importance. We see a lot of potential in the jungle of Peru, and that pipeline is going to be needed sooner or later. Could you provide indication of your corporate tax position in 2025 compared with 2024? Will you be paying a higher percentage of tax, and/or do you have losses to carry forward into 2025? Thank you, Jimmy. We provided guidance today on cash taxes, and as you remember, we expect cash taxes to be roughly $40 million this year. Of course, the company has been very profitable over the past years, and we have used all of our tax losses at this point in Bretaña, so I can just assure you that we're always looking for ways to lower our tax bill, but the business has grown and it's been successful, especially with oil prices and EBITDA levels that we've accomplished. Tax profitability is up. You have $100 million in cash at year-end in 2024, plus expected 2025 free cash flow of $60 million. This leaves $100 million of cash headroom above the minimum of $60 million in cash you want to keep. Does this suggest that the additional $45 million could potentially be added to the 2025 distribution plan? First, yes, we have a lot of cash, but we have a few very important funding requirements in the first half of 2025, like the tax bill that we just talked about, the erosion project, and many others. But if we are capable and able to issue top-up dividends when appropriate, we will always try to do it, and it's reviewed on a quarterly basis. But it will depend on a number of factors, including oil prices and our operations. Thank you. Just a reminder, there's one more question left, but if you'd like to ask a question, please submit it, and we'll answer it. What are your plans for the new TEA areas, and how do they fit into the company's current strategy? You know, as we have mentioned, those two technical evaluation agreements that we have signed, the areas actually sort of put the Block 131 back together as it was originally, not exactly, but close enough, so all of that area was owned by CEPSA, from whom we bought the Block 131, so there are leads, as we mentioned in the note, with even prospects based on the seismic that was done in the past. So we always look at plays. The idea that what we found in Cushabatay and in the Cushabatay formation in the Los Angeles field will be replicated, we find additional oil in the deeper horizons in the Copacabana, Ene, that could be replicated as well, and then you start getting a sense of the size. Just to the south, you have Block 107, which has also the Cushabatay and the other formations as targets. Now you get a sense. We're looking at a play that in size could be the same size as Block 95. Quite excited about this. Will the company be bidding on Block 64? You know, we've been invited by Petroperú. Of course, we're the largest crude oil producer in Peru, and the way we've been executing and have cash at hand and cash flow, they would like us to go in. Even the local communities, they want us to step in. But of course, it's a tender, and I always concern about tenders because there's always someone that will offer whatever, so we're reviewing it, and we have not taken a decision yet, but we're reviewing that possibility. Just to warn investors, in size, it looks quite attractive. This was at one time owned also by GeoPark. The Situche field was discovered by Oxy with Talisman in the past, so there are social issues, and the wells are deep, so they're expensive, but it's 40 API, 45 API gravity oil suite. Fantastic, so as always, pros and cons. As you guys know, we know how to manage both. Dear all, thank you very much for your time. There are no further questions at this moment, so I'll now hand back the speakers for closing remarks. As always, I would like to thank, first of all, the team that participated with me, both Camilo and Jose, David, and that is our IR director that helped us quite a bit to be able to communicate the messages, and the entire team of PetroTal. They've done a fantastic job, as you see now that we guide for the first time production above 20,000 barrels of oil per day, and of course, our investors that have been supporting us, some of you almost from the beginning, much appreciated. We'll be in London next week, so I look forward to visiting with some of you in person. All the best. Thank you. Thank you.