Good afternoon. Thank you for joining PetroTal's 2026 Guidance Webcast. Your presenters today are Manolo Zúñiga, 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. Now I 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 Zúñiga, 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 joined 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 we prepare remarks. This year's webcast is a bit different from prior years. Rather than presenting a growth-oriented budget, we are aligning what we view as a discipline reset, one that is designed to protect liquidity, structurally reset our cost base, and preserve the option value of the Bretaña asset while oil prices remain under pressure. With that context, let me begin on slide two, 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-$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-$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 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 three, we have restated PetroTal's core investment thesis. PetroTal remains Peru's largest crude oil producer, and Bretaña is an extremely high-quality oil asset with competitive economics at $60 per Brent, and is still under development. Critically, Bretaña 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 minimum upside leverage when the cycle turns. Slide four outlines the three core objectives underpinning 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, reposition for growth, while 2026 is not a growth year. The budget assumes the option to resume drilling by October 1st, 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 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 Bretaña. On slide five, we summarize the main elements of the 2026 budget. The approved capital program totals $80 million-$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 start sooner than later. Approximately $30 million-$35 million relates to 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 expenditures 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 per day before mid-year 2027. In the past, we have seen similar behavior with continued drilling. Let's not forget that according to our 2024 year-end reserves 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 six lays out the strategic reserve for the Bretaña field. Our first priority is balance sheet strength. We maintain a strict cash flow to ensure we can cover one-time costs without internal stress. This capital discipline allows us to protect our liquidity today so we can re-accelerate activity as soon as the market visibility improves. Second, we are optimizing operations before re-accelerating growth. This includes a shift to third-party drilling and a focus on execution certainty over aggressive timelines. 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 spaced to liquidity, not oil price optimism. Moving to slide seven, 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-$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 a lower price environment. On slide eight, 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-$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-$40 million. Moving down the table, total capital expenditures are budgeted at $80 million-$90 million, which include 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-$70 million for the year. Importantly, that cash outflow is both intentional and manageable. No cash dividends are assumed in 2026, and the budget is structured to conclude the year with approximately $16 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 costs, 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 Bretaña to the average 11,500 barrels a day for 2026, especially the assumptions around field and well downtime? The second part to the question, is there sufficient water handling capacity at Bretaña to return to 20,000 barrels a day sustainably, given that the field is currently constrained by water handling throughput? Yes, that's actually a very good question. The reduction from 15,000 currently to the 11,500 for the year shows the normal decline on the oil production of the wells. These wells are all set up with electric submersible pumps, so I will say the flow rates are consistent. Some of the wells can pull up to 15,000 barrels of fluid per day. On average, they're 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 11,500-12,500, 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 mentions. 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? We are going to be publishing the 2P reserves next month. So work is being 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, eight in the 1P category and another eight wells on the probable category. That number may be revised, should revise upwards, I believe, because as we continue producing, there's much more certainty in the availability 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 informed the decision to transition to a third-party drilling contractor. You know, 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 the 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, you know, roughly $10. So if you take our volumes, that would mean that it's about $3 million-$4 million impact for every $1 change. Can investors expect a resumption of dividend payments in 2027 onwards, assuming the eight-well drill campaign is executed successfully and production volumes are reestablished? 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 that 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. Okay. Thanks. Could you please elaborate more on the capital allocation of 2027? With two plus six wells by the end of 2027, what will production be in 2028? You know, that assuming that we drill all of the eight wells, you know, as our goal has always been to be above 20,000 per day. So that's what we're targeting. But we don't have yet a budget approved for 2027, just to put a caveat. Okay. Thank you. What's year-end 2026 and year-end 2027 expected water handling capacity? We're going to go in two 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, we probably be by year-end 2027, 320,000 by year-end 2028. 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 oil cut of 10%. You know, 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 appear to be no further questions at this stage. So can I hand back to Manolo and Camilo for any closing remarks? Yes, Mark, thank you so much. As always, I want to thank all of our investors. The set of questions that you guys have asked today is fantastic. Allow us to explain, you know, some of the rationale for 2026 and 2027. Thank you so much. Thank you.