Hello, everyone. Thank you for joining the PetroTal 2024 budget and guidance webcasts. Your host today will be Manolo Zúñiga, CEO, and Doug Urch, the CFO of PetroTal. Once the presentation is concluded, there will be a question and answer session. If you would like to ask a question, please submit it via the platform, and the host will do their best to answer all the questions in the time allotted. 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 Zúñiga, 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 clicked 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 at celicourt.uk, and they will be able to assist you. Before I begin, I need to mention that there are some 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 its shares listed on London's AIM market, the Toronto Stock Exchange, and the US OTC. Currently, PetroTal has a market cap of approximately $550 million, and is projecting an EV over 2024 adjusted EBITDA ratio of 2.4, when just a year ago it stood at just 1. 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 five 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 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 three water disposal wells capable of disposing approximately 50,000 barrels of water per day each. The company is able to deliver all of this in just a small 30-acre surface field footprint, with peer-leading 6.96 kilograms per barrel of 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 you 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 average closer to our full 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 two new sales routes in 2024 that will turn it 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 stated on Slide 4, the company will spend approximately $135 million in 2024. That can be divided into three components. The first component is continuous spending at the 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 three new oil wells in quarters one through three, exiting with 20 oil wells by the end of the year. Interestingly, 20 oil wells was our original 3P well count, which now stands at 36 wells after reclassifying oil reserves. Once the three new oil wells are completed by late summer, early fall, 2024, the company will assess its drilling rig upgrades or continue drilling, depending on Brent 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 CPF3, de bottlenecking, the operating trains to allow for increased rates, and starting the CPF4. 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 CPF4, 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 spending for future sustainability and protection of the Bretaña field and nearby, nearby community from aggressive river erosion. This is a 2024 and 2025 project. This two-year project, it 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 riverbank 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, giving us a permanent solution on the erosion. Lastly, the company will initiate a 2-year 2D seismic program in Block 95, south of Bretaña field, totaling approximately $30 million, of which $12 million is allocated for 2024. The seismic survey aims at validating our technical interpretation of oil migration towards the structural leads map south of Bretaña. In addition, approximately $2 million will be allocated to Block 107, for required permitting 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 potentially being as large as Bretaña. 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 pilot of selling oil through the OCP, the heavy oil pipeline of Ecuador. We're still deciding which river port 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 over the 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 will require barging to Yurimaguas and then trucking to the Port of Ilo. We're aiming to commercialize this route around Q3 2024, and we're aiming to initially commercialize around 2,000 barrels of oil per day on each route, to eventually move to 5,000 barrels of oil per day on each one, as shown in Slide 5. I will now turn over the meeting to our CFO, Doug Urch, who will provide a brief financial update. Thanks, Manolo. On Slide 6, we now show the net backs table for our two main routes and the estimated initial pilot netback estimates for the two 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 one-time 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 non-recurring erosion and community support OpEx piece 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 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 two new sales routes and inflation impacts in our fixed lifting cost contracts. The one-time 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 non-cash compensation and $4.2 million of non-recurrent 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-$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 Bayóvar, 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 ten 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 dates 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 cap 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. Thank you. Could you please come back to the exact benefits for the erosion management program? 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? Yeah, as I mentioned in the presentation, this is a two-year project 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, how beautiful it looks across the river, but that's the Ucayali River, that when it joins the Marañón forms the mighty Amazon River. So the erosion control is key. You can see in that picture how close the facilities are, you know, next to the river. Of course, the camp was set up before us when Gran Tierra used to operate this. It made sense at the 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 a 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'll be a fantastic way of managing this as well. But again, it's just a two-year project, 2024, 2025. 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 tankers. And that is fast-tracking things, is allowing us to be able to move the barges faster. You may remember that last year, after the dry season, 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 the barge to the tanker, allowing us to bring back the barges. 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 dry season. We don't know what's gonna, Mother Nature's gonna 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 as we plan to grow production in the future. As we mentioned, we are setting up facilities to go to 30,000. With the two new export routes operational by year-end 2024, should we expect average production in 2025 to be at least 20,000 barrels a day, assuming oil price remains at current levels? That, that's the goal. And we are working really hard to be able to get that. So if you do the math, you know, we can do the pilots at 2,000 per day on each side, eventually growing to 5,000, that would provide us 5,000. Why those routes are important is that they navigate—we navigate using the Peruvian barges that are designed for the low river levels, allowing us to move oil even in the driest part of the season. That will complement what I did. So yes, that's 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 for 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. Thank you. 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? You know, if we last year we moved the Block 95 exploration to the main section of the corporate presentation. It used to be in the appendix. The reason is that we're giving up to do this seismic survey that will allow us to see if we have closure in these leads. They're now leads, and if that is the case, we believe that the migration of the oil has continued going south. So if there's traps, they should be full of oil. Our initial mapping of those leads show that it could be the size of Bretaña or even bigger, some of them, so we're excited about that. We have yet to get the final permit to carry out the seismic, but you know, looking at the feedback from local communities, they're excited about the possibility, given that, as you know, we were able to change the law on the canon distribution. So they, they're hopeful that we find and they can develop, and then they also expect their 2.5%, as we have done in Puinahua. So the communities are supportive of this, we just need to get the permit and see what the seismic tell us, but we're quite optimistic. Right. On 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 fuss 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 a much higher level for 2024. However, projects like the erosion control have brought this estimate down because of their deductibility. Thank you. This question has three 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, you know. The statement refers to future drilling being optional beyond 2024. Given the investment 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? Yeah, I believe the person asking the question misunderstood what I said. And what I said was that, and as is based on our budget, we are budgeting three new oil wells this year. That by Q3, we are done with those three 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 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, if we see oil prices improving, we may decide, I guess, to carry on and drill another well in 2024, preparing to the fact that by 2025 we're expecting to have a higher production capacity. As I mentioned, our 3P case has a total well count of 36. Our 2P case, it has 29 wells. We just completed well number 17, so we're basically about halfway in the development of the field. There's a lot. There's a lot of reserves that we are enjoying the benefit of. The final part to this question: Is PetroTal over-investing 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, you know, right now, far-fetched. That, of course, is gonna require that the ONP, the pipeline owned by PetroPerú, goes back to full operations on a proper commercial basis like we used to have before. And because that will provide us that ability. But something important, as we set up our units, their nominal capacity is 8,000 barrels per day. So by adding another one and going up to 32, what allows us also is to be able to do maintenance in any of 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, it will be very helpful. Especially when the new wells come in, like now that the new well came in at 7,500 barrels per day, we. 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 gonna maximize oil sales, as we expect to find other Bretañas in Block 95. So it's, yeah, it's a long-term plan. We go always step by step, as you guys know me. We're going to spend $34.2 million in social community projects this year. Are we going to keep the same level of social spending in future years? Well, the $34.2 million includes the OpEx portion of erosion, which we have said is a non-recurrent expense, and one time. So the other smaller amounts in G&A and OpEx will taper off as the Social Trust projects and investments become active. Thank you. Given oil price volatility, is PetroTal management considering to hedge certain production when crude pricing is on an upswing? At this point in time, we do not have any hedges in place. We do analyze that on a quarterly basis. Essentially, hedging requires either a large cash amount to cover the potential risks of the hedges, or you'd have a credit facility that would provide for that. We are working on putting a robust credit facility in place that would allow us for the flexibility, and then we may look to put some hedges in place, depending on our quarterly review and forecast of oil prices. Even with the new export routes in Q4 2024, PetroTal only expects 17,500 barrels a day in oil sales. What is the exit sales outlook for December 2024? As you can see on that Slide 3, the overview of the presentation, Q3 hit as hard as we're assuming similar dry conditions as last year that were quite critical. In last year, in the dry season, it lasted for part of Q4. Then you see that in Q4, we're projecting 17,500, and of course, as we are able to move more oil, like this year, we ended up the year with more than 20,000 barrels of production. So we will expect something like that. The key for us is to see how these pilots, and they are pilots right now, of the OCP and Yurimaguas work, so in case we have a severe dry season, we can do better than 13,000 in the Q3 and better than 17,500 in Q4. Therefore, we can do better than the guided, 17,000, average for the year. Given fuel costs have been trending down, what is the reason that barging costs have increased? Well, transportation costs now include trucking, oil transfer fees, and barging for the new routes. On a per barrel basis, and excluding erosion, the company will be around $10 per barrel in all OpEx, versus $9 per barrel in 2023, which is relatively in line. Thank you. Could you please add some further detail on the erosion costs? Why is there a requirement, and what is the process to be implemented? You know, the need is obvious. If you don't manage the erosion, eventually, it may impact your facilities, you know, so we have to take care of that ahead of time. The idea is to put some barriers that will deflect the currents out away from our camp, and actually help recoup some of the lost ground. That has been done in other places, and that's what we need to do this. We have a lot of oil reserves in Bretaña. We just need to take care of the erosion to ensure that we can develop all of them safely. What measures does PetroTal take to ensure profitability at lower Brent prices, and what is the lowest oil price that PetroTal can deliver free cash flow at? Well, as stated in our investor presentation, much of our CapEx is flexible and can be reduced should the company endure lower Brent levels for longer. Please see Slide 10 in our investor presentation for the free cash flow profiles at different Brent and production levels. Thank you. What are the likely comparative transportation costs per barrel on the Ecuadorian and Yurimaguas routes compared to costs on the Manaus route? If these two new routes to market prove successful, are the future volumes via these routes readily upscalable? Well, as shown in Slide 12 in our investor presentation, and on the slide in this current deck, you know, the pilot phase for these two projects will be around $30 per barrel netback. Once commercialized, these routes should be more in line with our other routes and be over $40 per barrel. Thank you. What is the total number of extra shares that is yet to be exercised, given that some warrants/PSUs are exchangeable for more than one share? Well, sir, we don't have any warrants outstanding. Those were all exercised back in 2022. So all we have are PSUs, which are an important part of the compensation plan for all, you know, senior employees, as well as, you know, certain employees operating in, at the levels in Peru. So we have a robust PSU plan for key players that play a role in meeting key production targets along the way, as well as other shareholder return metrics. So that being the case, we have about 21 million of those that are currently outstanding, and they'll vest over, you know, the next two-three years. And that's an important way to tie in individual performance with company performance to maximize shareholder value as well. Thank you. Just a reminder, if you'd like to ask a question, please submit it via the platform. Next question, by end of 2024, PetroTal would have spent $585 million in CapEx, total CapEx till 2041. What plans does management have to reduce the CapEx over the life of the field? The future CapEx is sort of natural to the development of the field. As I mentioned earlier, on the 2P case, we have a total well count of 29 wells, so we are now drilling well number 18. So we have to drill those wells to drain the 2P case. Of course, as you drill the wells, as you know, all of these wells, we set electro-submersible pumps. The Bretaña field is a wonderful reservoir, highly permeable, supported by strong aquifer, so we're gonna be managing a lot of fluids. So the higher the well count, the higher the volumes that we're gonna be managing, therefore, you need to bring additional water treatment facilities and also drill some additional water disposal. That's what it takes. So we will continue doing this on the oil side, you know, reaching the 32,000 level, I think, it sounds like appropriate. But on the water, as we add wells, we're gonna have to add more water treatment and water disposals. And then once all of the wells are drilled in the next two-three years, then, CapEx stops. And, you know, this is, as I have always said from the beginning, this is a free cash flow machine, and it's been for the last couple of years, and will continue until the end of the contract. Manolo, Doug, thank you. There are no further questions at this time, so I'll hand back to you for closing remarks. Well, I just want to thank everybody. I know that the erosion issue, it's not a surprise because we've been talking about erosion now for more than a year. It's been in our presentations. But you see that we are, you know, tackling this important issue to make sure that we safeguard this important investment that will provide so much cash flow and benefits for all of the stakeholders. Anyway, thank you so much for your support. I look forward to seeing some of you and talking to some of you in the near future. All the best. Thank you.