Hello, ladies and gentlemen. Thank you for taking the time to join PetroTal's 2022 Guidance and Reserves webcast. Your host today will be Manolo Zuniga, President and CEO, and Doug Urch, Executive Vice President and CFO. Manolo and Doug will go through the latest corporate presentation, and there will be a Q&A session afterwards. If you would like to ask a question, please do submit it via the webcast, and we will do our best to get these answered during the time we have today. I will now hand over to Manolo. Please take it away. Yeah. Thank you, Jimmy, and good day, everyone, and thank you for joining the 2022 Guidance and Reserves Update webcast, where we will provide a summary of our 2022 guidance, 2021 reserve report, and some exciting return of capital strategies recently supported by our board of directors. If anyone wants further information on the company, please see our website for additional materials. As mentioned before, my name is Manolo Zuniga, and I am the President and CEO of PetroTal, and I'm joined by my colleague, Doug Urch, Executive VP and CFO. You have clicked on the link in our February 22 press release. You should hopefully have signed up 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 some disclaimers towards the end of the presentation, which I would urge you to read at your own leisure. Also, all amounts referenced are in US dollars unless otherwise stated. For those that are new to the story, PetroTal is an onshore Peru-Focused oil company and Peru's largest crude oil producers nowadays. As shown in slide one, the company's listed on London's AIM market, the TSX Venture Exchange, and recently upgraded to the OTCQX in the United States. We have a market cap of approximately $467 million, with net debt of around $75 million, and trading at around 1.5 times estimated 2022 EBITDA. We have a 100% working interest in the Bretaña oil field. We had never produced when we took it over at the beginning of 2018, and it is now producing just over 20,000 barrels of oil per day for the past few weeks. Just announced last week, the Bretaña field has 2021 year-end 2P reserve of 78 million barrels, and now has 11 producing wells, with the 11th well recently on production at a record flow rate of over 10,000 barrels of oil per day. The company has over 1.2 million barrels of total storage capacity and almost $350 million and $70 million in tax loss carryforwards in Peru and Canada, respectively. In short, we have an amazing asset that is now delivering a beautiful combination of growth and yield, and that is resilient down to under $30 per barrel Brent. We also have a proven technical team in place with a track record that delivers operational excellence. With the recent uptick in our share price, I am happy to announce that we have delivered the 3x share value multiple promised to investors in late 2017 when we raised our initial capital. The theme for this webcast that I would like to convey to shareholders is that based on our robust 2022 guidance and exciting reserves upgrade, our board of directors is supportive of a return of capital policy that shareholders can be excited about. That said, we have a few steps we want to walk through, so the logic and the strategy is understood on how we think about free cash flow allocation, operations, and liquidity risk. As shown in slide 2, we estimate next year's production range to be between 17,500 and 19,500 barrels of oil per day. We obtain this range by running different scenarios with technical and ONP pipeline-related social downtime. We feel that if government and communities are aligned, as we have worked hard to support, PetroTal should be closer to the higher end of the production range. If the opposite happens, and we encounter some protesting-related disruptions during 2022, the production could be closer to the lower end of the range. Overall, the Mid-Case budgeted scenario with approximately 13% total downtime during 2022 will deliver approximately 18,250 barrels of oil per day at 100% growth over 2021 average production of 8,956 barrels of oil per day, and could reach as high as 19,500 barrels of oil per day should little or no downtime occur in 2022. As you can see in the 2022 summary, we plan on generating around $230 million in free cash flow, pre-debt service, and we expect to retire the corporate bonds early, thereby reinstating a return of capital program if economically viable, which we will detail in the coming slides. It's important that we are transparent in our downtime assumptions compared to prior years, so the market is aware of management's expectations in this area. We're very excited to update everyone on our recently approved reserve report, as prepared by Netherland, Sewell & Associates, and that was announced last week. Slide 3 summarizes the key highlights and metrics from the 2021 year-end report. It's very clear that for just 4 years into the development of this field, the recovery factor percentages are now similar to analogous fields such as those located in Block 192. I am very eager to unlock the additional immense value from this, amazing asset. To summarize, we had material year-over-year increases in all reserves categories with 1P, 2P, and 3P reserves now at 37, 78, and 147 million barrels respectively. Due to these increases, along with a more robust current price deck, we now have a 1P before tax net present value NPV10 valuation of 3 quarters of a billion dollars, with our company currently trading at approximately 65% of this value, representing uncertain. Our reserve metrics are strong with a 2P F&D per barrel under $5 and a reserve life index of 30 years, drastically extending the potential running room of the asset by double in terms of reserve life. The critical driver to these positive changes was the 2021 successful drilling program, which provided valuable well calibration data that NSAI was able to incorporate into their analysis, increasing the 2P original oil in place to 389 million barrels and the 2P recovery factor to 22%, something we had always predicted. Because of this, the corresponding 2P book well count has increased from 15 wells to 22 wells, which fits the concept of having sufficient wells to sustain a long production plateau. We can now focus on de-risking future probable and possible locations and moving them into the approved category in the coming years, just as we have done before. After all, we now show over 50 years of production above 10,000 barrels of oil per day under 3P development assumption and giving us confidence that reaching 25,000 barrels of oil per day should be our new goal. Slide 4 shows at a detailed level that we plan on drilling and completing 4 new wells in 2022 with recent completion of the prolific 10H well, which we brought on production on January 31, 2022 for 5 new wells in total. This slide outlines our well timing and estimated start dates, which could be adjusted based on economic conditions and equipment performance. I would also like to point out we have some planned rig maintenance underway right now and again in early December as we plan for our 2023 program. Overall, we will spend an estimated $75 million in drilling and completion capital through 2022. As all these wells come on production, we expect to exit 2022 at over 21,500 barrels of oil per day. We have also provided an updated location map, so you can see our focus in 2022 is in the southeastern part of the field, moving to the northwest with the 14H well. Strategically, it is important that we continue to expand the boundaries of the field to obtain as much reading data as possible for future reserves update. In slide 5 in our 2022 guidance summary, here we show the net result of the drilling plan shown on slide 4 and the division between base and new production growth. I'd like to point out that our production is high enough and flush enough in its current state that if we stop drilling, our production blow down would be impactful and quickly dial the production and cash flow back to pre-2019 levels. This is why it's important for shareholders to understand the factor of your wells concept that we emphasize in our strategy. A drilling plan of one well per 1/4 is optimal to maximize free cash flow in this current environment and to scale the past investments in infrastructure that now let the company produce for an optimal production run rate of between 24,000-26,000 barrels of oil per day. Production will largely vary in 2022, with peaks surpassing 20,000 of oil per day, followed by aggressive base declines on very flush production levels as seen in our previous wells. Overall, in 2022, we're spending $120 million in CapEx that is very evenly distributed throughout 2022. Aside from the $75 million in drilling capital, we are also investing in some important infrastructure and projects in 2022 and beyond. Some items include a new diluent tank and separators estimated at $10 million, allowing us more flexibility on how we transport and pay for diluent, as well as many small production optimization and facility add-ons to optimize and enhance our processing of fluids for another $18 million. Finally, we're spending $50 million to engineer and start the mechanical and installation work for the CPF-3 so the company could have optionality to handle the expected formation water production in 2023. Lastly, as you can see in the cash flow table, we're running our 2022 budget at $88 per bbl, the forward price sweep at February 7, 2022, and applying our current contract terms and cost structure to that top line. Based on those assumptions, we feel we can generate around $350 million in EBITDA under a Mid-Case scenario. We have also provided an EBITDA matrix that investors can calibrate to, which highlights the large expected influx of 2022 net true-up revenue expected from oil reaching by over and settlement to the final contracted price. That said, our CFO will discuss more of these and the financial details of the 2022 budget in the coming slides. Slide 6 is our way of communicating to shareholders that we're supportive of the return of capital requests, and are doing everything we can as a management team to ensure the company can pivot to a material yield generator. We would like to explain how we intend to meet this request via our 2022 financial strategy. Just to rewind, we have historically returned capital to shareholders, and this type of a strategy is not new to PetroTal. When market conditions allow in late 2019, PetroTal paid out over CAD 1.1 million in dividends, with intention of a recurring plan into 2020 and beyond. This was halted by the COVID-19 pandemic and the collapse in world oil prices. The bonds contain a restriction of any return of capital to shareholders. In order to do so, we must either eliminate our debt or try to modify bond terms. Both options have costs associated with them. We believe that the best and most cost-effective way to activate a shareholder return policy is to build cash and retire the bonds early, as soon as Q3 2022, so only 6-7 months from now. There are strategic and financial reasons why this is our recommended approach, and we will cover these topics in the coming slides. To conclude, our board is supportive of this strategy, and over the long term will allow for hundreds of millions to be repatriated back to shareholders through the life of the asset. We are excited to be able to deliver this with pricing and performance all in only 4 short years after having zero production and only a vision for the Bretaña field. Slide 7 shows that as part of our 2022 strategic plan, we have also been working hard to ensure we're maximizing sales flows to Iquitos and Brazil. The commercial team has done an amazing job of potentially expanding the Brazil route to allow sales of an estimated 12,000 barrels of oil per day. This will help minimize disruption risk and create healthy competition for our crude oil. We still intend to flow sales to the OMP pipeline, and if we were to stop doing so with little pressure support from other fields, it would essentially halt or severely slow down movements through the OMP, where we have over 2 million barrels currently forming the basis for the true-up derivatives settlement. We're also exploring other small but effective sales options which are in their commercial infancy. We wanted to touch on this slide in slide 8, as it has some really positive messages. Firstly, we now have access to over 1.2 million barrels of total storage capacity, adding up all of the available and contracted areas we have we can store oil into. Secondly, since we can readily sell over 13,000 barrels of oil per day to Brazil and Iquitos, we can now essentially continue producing oil for over a month just using our field and floating storage. Including our dedicated tankage at pump station 1 and 5, we can continue producing for over 100 days at a 25,000 barrels of oil per day run rate. This has 2 key benefits, commercial development, risk mitigation, and helping create cash flow stability, or at least deferral of cash flow into storage compared to shutting in for extended periods of time. Storing oil, especially in barges, does have a cost, which has been evident in our past quarterly transportation costs. We view this as a necessary trade compared to shutting in production, and we'll continue to optimize our operations in this area. I will now turn the presentation over to our CFO, Doug Urch. Thank you, Manolo. On to slide 9. I'm Doug Urch, PetroTal CFO, and would like to start off by echoing my enthusiasm and confidence in this 2022 guidance. As Manolo indicated, under the 18,250 barrels per day budget case, the company expects to generate free cash flow before debt service of $230 million. Considering a base carry forward from February 2022 of around $30 million in unrestricted cash, we are really describing a cash flow allocation menu of $260 million under an $88 per barrel Brent price environment. The bar chart on the right shows our recommended allocation choices for that capital. To quickly summarize, there's a $20 million bond repayment option that we recently provided payment notice on, and it will be repaid in Q1 2022. This is followed by an estimated $30 million in costs for interest, factoring our ONP sales, VAT, lease payments, and hedging collateral, and cash costs for 2022. By mid-Q3 2022, once cash balances permit, it will take $85 million to retire the $80 million in remaining bonds. We feel this is the optimal time because we'll expect to have the cash on hand to pay it out. The call premium penalty stabilizes in Q3 2022 until Mid-2023 at around $5 million, with little to no further benefit in waiting past Q3 2022. Post payout of the bond, a reasonable level of cash and working capital remain in the business, and the business saves an estimated $8 million by waiting until Q3 2022 versus paying out the bonds in Q1 2022, as outlined on the next slide. Post bond payout, if economic conditions prevail, the company requires a healthy working capital buffer until revolving debt may become available. We estimate that cash buffer level should be between $50 million and $70 million, which would fully support a prolonged period of depressed Brent prices, future derivative margin calls, and a smaller capital program with light G&A costs. Based on our Mid-Budget case and Brent assumptions, this would leave up to $50 million available for dividends and/or share buybacks in Q4 2022. Lastly, we believe that going forward, being net debt-free is prudent in the current price environment, given our capital needs at this time. Additional leverage may be considered for future M&A activity should the right asset be sourced and approved. Slide 10 summarizes why we believe Q3 2022 is the optimal time to retire the bonds. The staircase shows cash on the right and the bond balance with call premium on the left. Aligns nicely in August and September, and requires no refinancing to execute. Furthermore, the table below summarizes the incremental costs and savings retiring the bonds early would create. Management believes $8 million is an appropriate justification for waiting 5 to 6 months to retire the remaining bonds. By avoiding another refinancing, cash flow allocation to shareholders will be greater over the next 3 to 4 years, with the sacrifice of only waiting 5 to 7 more months. Slide 11 has netback analysis. I now want to touch on a few key metrics regarding our 2022 budget. Slide 22 summarizes the 2022 program Mid-Case and sales market. The royalties now include the previously announced 2.5% community trust payment, obviously prorated for downtime and our latest OpEx run rates. Of note in the table is our barging cost, which will now be broken down in more detail for investors. Barging in remote parts of the Peruvian jungle consists of 3 parts: service, standby, and fuel. PetroTal pays for barging fuel as we feel it is a more transparent way of doing business. In 2022, our total barging cost allocation will be around $3 per barrel, with the actual barging service at $1.70 per barrel. On the diluent side, which is a major OpEx item, we want to remind investors that the $4.20 per barrel reflects diluent and diluent transportation costs at $88 per barrel Brent. The diluent is sold with our sales crude at our current contract sales routes and claws back approximately $2.80 per barrel. Two dollars and eight y cents per barrel. However, this is shown in revenue and not on a net cost basis. On a net cost basis, our diluent costs the company $1.40 per barrel. Overall, a $92 per barrel Brent price generates a contracted Brent price of $88 per barrel Brent, which generates a netback of $50 per barrel, showing a $38 per barrel all-in cost structure. This equates to a 57% netback margin, which is substantial for a heavier-weighted crude oil producer. With our CapEx program of $120 million or $18 per barrel, there is substantial free cash generated on a per barrel basis. Slide 12 is an exciting slide, showing the 3-year free cash flow potential subsequent to our 2022 strategy. Assuming a 22 2P well development program and using a heavily backwardated Brent strip as at February 7, 2022, it's possible that the company builds over $600 million in cash through 2025, of which a substantial portion could be returned to equity holders under these assumptions and economic conditions. In Slide 13, we want to remind investors how the ONP contract functions and why it is still important to keep some oil flowing into the ONP. With over 2.2 million barrels in the pipeline and few other operators producing in the area, PetroTal's oil is providing the pressure needed to push its own oil through the ONP. As proof that the current commercial contracts are functioning as expected, we have provided an update on what we have actually received in terms of true-up payments. To date, we have received over $31 million in true-up payments from oil reaching Bayóvar, and its final price being substantially higher compared to what was factored to us some time ago by Petroperú. In 2022, and at current Brent prices, this variation is expected to grow to over $70 million, with some derivative losses netted in to reach the true net payment of approximately $37 million in 2022. In summary, 2022 will be an exciting time for PetroTal investors as our investment considerations are unique compared to our peers. With the following to leave you with, assuming current economic conditions, we'll be debt-free in 2022, reinstatement of a return of capital plan post-payout of the bonds, 100% year-over-year average production growth in 2022 from 2021, well over $ 1/2 a billion in distributable cash generated over the next 3-4 years, 15 years of production at a higher than 10,000 barrels per day run rate under the 3P development case, and further material recovery factor upside in the coming years. Thank you for listening to our call today. I will turn it back to the moderator for questions. Thank you, Manolo, Doug. We'll now move on to the question areas. The OMP is quite expensive today. Do you see an opportunity to lower the costs from 2023? Yes, actually, we do. Keep in mind that the OMP contract ties the pipeline tariff to Brent prices. That's why as Brent prices have gone up, the tariff has gone up some as well. The expectation, and this is something that we've been discussing with Petroperú, is that once the Talara refinery is finally working, and the oil will go through Talara, that we could have an adjustment on the transport prices. That's still to be negotiated. That would be our goal. What is the company doing to lower OpEx costs such as barging costs? We use barging not just as a transportation arm, but as a storage arm for the business. As such, there are additional costs that are factored when the barges are not moving, for instance, storing oil. In addition, when barrels are not being sold, cost per barrel increases very quickly, which has been the case in prior quarters. This year, barging service is expected to be $1.70 per barrel, plus standby and fuel. Much lower versus prior years. The company previously mentioned that it had equipment for an early start of production at a site on Block 107 for around 5,000 barrels a day. Might you be able to elaborate a little bit more on this? Yes, of course. Although we are jumping a little bit as we still need to drill the exploration wells in Block 107. What I have mentioned is that the initial equipment that we brought to Bretaña to put that initial well drilled by the private operator online we could move that one. That equipment is idle right now in the field, and we could move it to Block 107. It will allow us to produce about 2,000 barrels of oil per day. I did not say 5,000. That's about 2,000. We can always squeeze some extra production capacity. The idea, of course, is to put that initial discovery, assuming we do the discovery, on production and put the well on test as fast as we can, just like we did in Bretaña. What investments are needed to be able to drill as well as produce from some of your leads on Block 95? In Block 95, this year we are working on obtaining the environmental permit to do seismic. We feel quite positive about those leads, although Invictus is considered a prospect. The reason for that is that the Bretaña field was filled with oil to the spill point, which means that the migration of oil that comes from the north has continued, should have continued going south, southeast. Therefore, those leads, assuming that they have closure, will have oil. For that, we need the seismic to make sure that they have closure. Then if we confirm that, we will need to drill an exploration well in each one of those to confirm that and then put them on production as soon as possible. We're very confident with that. They should have oil. What does the budget increase in G&A costs in 2022 cover? Contained in that amount is $4 million for social related costs in 2022. With normalizing those costs out, our G&A represents about $270 per barrel, which is in line with peers. The Q1 and Q2 production guidance of 16,300 barrels a day and 15,000 barrels a day seems low. Please, can you talk us through how you arrived at these figures? Yes. We need to keep in mind that the Bretaña field is a typical oil field supported by a strong aquifer, and the water from the aquifer is our friend. We just need to manage it, you know? That's why I always talk about building a factory to process fluids. These wells come in very strong. The Vivian Formation is extremely permeable, 2, 3, 4 darcies of permeability. That's why these wells stand so strong. When the water finally breaks through and the water cuts start going up, the oil cuts drop. The typical decline on an oil well supported by strong aquifer is very much hyperbolic. You're gonna have some steep declines initially, especially if you have a heavier oil like ours that is 19 API, and eventually will settle down. You can see some of that in the actual slide 3, and where we have for the first time broken up the production forecast, and this is based on NSAI's report between the PDPs, the proved, probable and possible. You get a sense. At the end, you can get an idea how this is gonna be settled and be producing for a long time. Again, this is why we emphasize the concept of building a factory to process fluids that will allow us to maintain a plateau above 10,000, so we can have a strong free cash flow for years to come. Even at 5,000 barrels of oil per day, if oil prices are reasonable, we will be free cash flow for a long time. The work on CPF-3 will start in April, and it will then be ready by mid-2023. Do you expect production to exceed 24,000 barrels a day in 2023, therefore requiring the new facility? You know, again, we go back to that slide 3, the production forecast by NSAI. You see, that potentially we could surpass the 25,000 barrels of oil per day. We are confident that based on the equipment that we have available now, although in the presentation we talked about being able to manage 24,000 barrels of oil per day, we believe that we can go to 26, even, I believe, more than that. The question is gonna be: Should we put more capital on oil facilities or just try to maintain a plateau at about 26-27? That's part of the conversations that we're having internally. For me, the most important thing is to make sure we have the equipment to process and reinject the formation water. That's key. Because by law, we have to reinject the formation water, and otherwise we have to constrain production. We will see how things shape up. As you can see in the past, we always talk about reaching 20,000 barrels per day, and now we're guiding to reaching 25,000 barrels per day. When is the 11H well expected to spud? It's expected to start by mid-March, as you see in the presentation. Keep in mind that the rig is ongoing maintenance, so it's gonna be very much dependent that Petrex, the drilling contractor, feels that the equipment is ready to start drilling. You've hedged using a combination of puts and collars. How much production has been hedged with collars, and what is the ceiling price? About 750,000 barrels has been hedged in the form of synthetic puts, where PetroTal participates in Brent gains above $70 per barrel. How much production can be exported through Brazil currently, and what are the plans to increase this? Right now, we're shipping about 8,000 barrels per day through the Brazil export, and increasing to almost 13,000 barrels per day. We're currently testing a 400,000-barrel cargo shortly. A group from a local district has said they may take action against Block 95 on February 28. Please can you confirm how serious this action could be, and give a general update on the situation with indigenous people? Yeah. This is a typical, an unfortunate case where the government takes extra time to deliver on what was promised to them. That's why out of frustration, they have put out that threat. We feel like we can manage it, and to avoid that, especially given some of the initiatives that we have put forward, that the local people are looking forward to having them fully implemented, including that social fund that we have set up. Excellent. What is the status on the farm-out process of Block 107? It's just not been much progress at all. I believe that once, as we are working to get the permits to drill in Block 107, we expect to have some interest coming back. We have time to try to bring up a partner. Something that we are emphasizing is that we are again paying a lot of attention to the Osheki structure and you can see that in our main presentation that is in our website and reducing the cost of that potential well. All of that, it should enhance our chances to bring a farm partner. Has the fantastic result from the 10H well been taken into account in the reserve update? Partially. In the sense that Netherland, Sewell & Associates that does the reserves as of year-end, that's December 31, had seen the logs so they could see the quality, but they, of course, they did not have the results or the actual well production. The report was completed after we put the well on production. At least it was a check for them that their forecast on production was a good one. That made them happy and more comfortable with the numbers that they put out. Has the company used the latest results from 9H well and 10H well in its guidance for 2022, or do you believe there is room to exceed guidance? Well, the 9H well, of course, because that well was completed in early December. The 10H well, I just explained how Netherland, Sewell & Associates actually have seen the results of the well. Their models, of course, were done as of year-end, again. The room to exceed guidance, there's always room. I'm always very optimistic. I have learned my lesson that we need to manage expectations, and that's why we have made it clear how is that we came up with this guidance for this year, knowing there is some unknowns that we don't have full control upon, especially on the social side. Does the company also plan to drill water injection wells? If so, how many in the 2 P case? Yes. Of course, we need to drill more of the water injection wells. In the map that you see on slide 4, you can see actually the location of the future wells. The 4WD well is gonna play a key role. We intend to drill that well early next year, and then seeing how things develop. We will need to drill 2, 3 more wells. Again, it is all about managing fluids and ensuring that we enjoy the benefit of a long plateau of oil production and free cash flow. Assuming limited protester disruption to production in 2022, is it possible or a likelihood that the current production guidance will be beat, given the production as of today is above 20,000 barrels a day? In essence, that's sort of the message that we have given, you know, that we could be around that range of the 20,000 mark, if we have no major social disruptions. Yes. You know, we're very happy with how well the wells are behaving. I'm gonna work hard to make sure that we can exceed the 20,000 mark. Can drilling be sped up to react to higher prices? As it seems, rig maintenance costs are quite high. By the way, the rig maintenance is something that is done on a yearly basis. Since we started, at the beginning of every year, we have done rig maintenance. Keep in mind, this rig is sitting in the middle of the Amazon jungle with all of that humidity. So it needs to be maintained properly, otherwise we could have issues. We only have one platform to drill wells from. Unfortunately, we're not in West Texas, that you can bring 3, 4, 5 rigs at the same time. We can do one at a time. That's part of the issue of why you see production dropping some. We put a well on production, you know, last month, and then we do the rig maintenance, and then we drill a new well. That new well won't come on production until May. That's why you see a dip in the production, and then we The oil in place in the 3P case is 2 times the 2P case. What is driving the large uplift in the 3P case oil in place, and what needs to be done to de-risk the 3P oil in place? When might we be able to expect these de-risking activities to take place? You know, in the last couple of quarters, as we were completing these great wells in the 2021 campaign, I gave enough hints that if the oil in place will go up some, the reserve will go up, and both of them happen. I also had mentioned that I was expecting Netherland, Sewell & Associates to narrow the large spread between the 1P and the 3P oil in place numbers. This question actually targets that. As you see, go back to the slide 4 and look at the map. You can see that it has grown. Potentially, it could grow potentially to the west, so that there's additional potential reserves. That's why Netherland, Sewell & Associates have maintained that larger spread between the 1P, 2P, and 3P oil in place. One of the key wells that are gonna help us understand that is when we drill the 4WD well. You look at the position of that well, if we want to target that to be able to enter the Vivian on top of a seismic line, and that way will allow us to tie up our maps properly and give us confidence that we can continue going west. That'll be fantastic if that indicates. We need to during the drilling campaign of this year and early next year, we're gonna hopefully narrow the spread of oil in place, and hopefully we can go towards the 3P case. Although, keep in mind that we have always guided to the 2P oil in place number, and we have always guided that the key for us was to ensure that the recovery factors were gonna be higher, which, you know, based on our models, that was gonna be the case, which we have seen with the new reserve report. Management guided that it would spend $152 million in CapEx until 2023. The new CapEx plan is $120 million plus $100 million from 2021, meaning total CapEx now stands at $220 million against the earlier $152 million. What is the basis of this new change, considering that production would not top the 25,000 barrel capacity of CPF-2? Well, essentially, it ties into noticing that the reserve report has gone up. In there, we talk about the fact there are more wells, so 15-22 wells. $100 million-$120 million in 2022 would have substantially finished off the old 2P reserve case, plus some additional facilities. Now, with the larger running room, we are also starting to plan for the new 2P case with the additional investments, starting in this year. As I mentioned, we are very focused on making sure that we have the ability to process the fluids and dispose of the formation water. We're comfortable with the capacity of our oil processing facilities, as we know that we can manage more than 25,000 barrels of oil per day. It's all about the water, and the water is gonna come in as we're supported fortunately by some aquifer. With CPF-2 installed, can we expect lower decline rates in well productivity? Yeah. The CPF-2, that nothing to do with the decline rates. You know, again, we have a strong aquifer supporting this reservoir. The one thing is the facilities to manage the fluids. Again, we're building a factory to manage fluids. The other thing is the way these wells are gonna behave. Water's gonna come in, oil production, the oil cuts are gonna drop. Eventually, they're gonna follow a very much hyperbolic effect, as you can see again in the slide 3, then the decline lower and this field's gonna produce for a long, long time. Has the company received approval to increase production to 25,000 barrels a day? Not yet. We're now expecting it for later this week. Would the company be able to give an update on the current state of negotiations with the local communities? Well, yes. You know, we have actually very active with the local communities, with the indigenous federations. We actually, as you see in our budget, we were dedicating a lot of funds for that. You know, we are very optimistic that the Block 95, the Bretaña field, will become an example for other oil companies in Peru. Keep in mind that now we have become the largest crude oil producer in Peru at 20,000 barrels per day. Actually, we're I think the 1/3 largest liquids production, including the condensate from Camisea. What we do, people are taking notice. The 75% ratio of free cash flow mentioned in one of the slides, is that what investors can expect once the bond is paid back? Well, that's too early to say. However, what we're trying to do there is demonstrate that using current economic conditions and the forecast strip price of $88 per barrel Brent, and under a scenario where there are no material downtime events, that the business generates a large amount of free cash. If the company has no debt, it can be assumed that the company will do something proactive with that capital in the form of returns to investors and/or M&A. The payout ratio could include M&A from our perspective, but that is too early to predict that. We would likely keep $100 million for working capital purposes, representing about 20% of that. However, this is all subject to future pricing markets. As well, we've talked about the possibility for Block 95 and 107. Those are all things to consider going forward. What is management's expectation of the value of the existing PDP NPV10 after tax at $95 Brent? Can you repeat the question again, Mark? Sure. What is management's expectation of the value of the existing PDP NPV10 after tax at 95 Brent? Actually, I don't have those numbers at hand at the moment. I would need to provide that. As in the presentation, we only show the total 1P, not the PDP. I can get the numbers. Thank you. Can the company comment on the current share price? Well, we certainly like the direction that it's going, and nice to see getting some recognition for the success that we've had. We still think it's undervalued at 1.5x enterprise value to EBITDA versus our peers. Yeah. What is the company's best and worst case scenario forecast for 2022's production? Well, in the presentation, we made the comment, you know, that our range is between 17,500-19,500. So that's the range that we are thinking. If cash flow for 2022 comes in above guidance, will the additional cash be distributed to shareholders? Again, similar to the previous questions, we're unable to say at this point in time. We would definitely prioritize shareholder returns versus other uses of free cash flow if that will generate the largest equity returns. If the appropriate working capital and liquidity is in the business, we don't see why. It's hard not to make statements as to what will happen, but certainly return to shareholder policy is important to us. Dividends is what we've done in the past. Of course, there are also possibilities of share buybacks too. Is the company receiving more institutional requests to participate in PetroTal capital? You know, we have not. We don't need fresh capital. We like the fact that there is good volume in our shares, both in London and Toronto, even in the U.S., which helps bring the price up. We don't need capital now. Will the company potentially look at doing a reverse stock split? Well, that's certainly something to think about. We've looked at that and gathered some feedback. At this stage, the feedback we have is that investors are somewhat neutral on that. That's something that still is under review. As they say, it's just gas. Yeah. Apologies, Manolo, Doug, there are no further questions, so I'll hand back to you both, to give your closing remarks. Good work. Yeah. Hey, Mark, I see something related to Block Eight. I would like to touch on that. We read in the local press that you're interested in Block 8. Might you be able to elaborate on this a bit? Yes, I would like to. I was asked that question, you know, about Block 8. Keep in mind that Bretaña is actually a continuation of Block 8. My response was that it'd be good if what we are doing in Bretaña is replicated in Block 8. You know, that was from a technical and social point of view. That was my answer. It's not that we wanted to be there, you know, per se. You know, anyway, I think there's some confusion. Actually, locals from different people in the different blocks, they're always asking about how come PetroTal doesn't go and operate Block 92, Block 64. That they really are impressed on a company. We don't have a single expat in Peru. They're all Peruvians, extremely experienced people that have worked all over the world, and that has a lot of appeal. That's why people ask, you know, "What about this? What about that?" We always answer, "It is great. It can be replicated." For that, let's make sure that we do it right in Bretaña, and we have yet to fully set up the social fund that we're working on and things like that. That's it, you know. I just wanted to clarify that. Thank you very much for that. Now I'll hand back to you now, Manolo, for closing remarks. Well, you know, I wanna appreciate all of these wonderful questions. Hopefully we have been able to explain, you know, what we are doing, what we plan to do. I'm actually quite amazed that from the initial review that we did of Bretaña at the end of 2016, 2017, when we were raising initial capital and some of our guidance at the time, everything is coming true. We will continue managing expectations very carefully. As you know, in Peru, the social issues are a great concern. The fact that we are a team composed of all Peruvians helps quite a bit. The reputation of our team is such that I'm very hopeful that we can get things done for the benefit of all stakeholders. We are shareholders as well. The idea of returning capital to shareholders is very important. You know, I put my own capital when I set up the company in 2017. I want that as well. We're very much aligned with everybody. Thank you so much.