Good afternoon and welcome to the PetroTal Q4 and 2023 Financial and Operating Results webcast. Your presenters today will be Manolo Zúñiga, CEO, and Doug Urch, CFO. There will be a Q&A session at the end of the presentation, so if you would like to ask a question, please do submit it via the platform and the presenters will do their best to answer it in the time allotted. I will now hand over to the presenters. Please take it away, Manolo and Doug. Thank you, Jimmy. Good day everyone, and thank you for joining the PetroTal 2023 fourth quarter webcast, where we will provide a brief summary of our fourth quarter and year-end 2023 operational and financial results. If anyone wants further information on the company, please see our website for additional materials. If you have clicked on the link in last evening's 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 and in the main presentation on our website, which I would urge you to read at your own leisure. As shown in slide two, PetroTal is an onshore Peru-focused oil company that in just five years has become Peru's largest crude oil producer. The company is listed on London's AIM market, the Toronto Stock Exchange, and the US OTC, having a market cap of approximately $530 million. 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 capacity since June 2022. The fourth quarter of 2023 was another resilient quarter for the company as we navigated through a severe dry season impacting October and November production and limiting our Brazilian barge transport and tanker unloading capacity at the port of Manaus. Despite this challenge, the company delivered its guided production of 14,865 barrels of oil per day for the fourth quarter and 14,248 barrels of oil per day for the year. But first, a brief summary of our assets. The Bretaña field has certified 2023 year-end 2P reserve of 100 million barrels, which have an after-tax 2P NPV10 value of $1.80 per share. The field currently has 18 producing wells and 3 water disposal wells. The company is able to deliver all of these on just a small 30-acre surface field footprint that, as referenced in our 2022 sustainability report, during 2022 generated just 6.96 kilograms per barrel of Scope 1 carbon emissions. We would now like to cover Q4 2023 in detail and provide some updates on current production and reading. Slide 3 summarizes a few key Q4 and year-end 2023 highlights. From an operational perspective, during the fourth quarter, we delivered 14,865 barrels of oil per day with corresponding sales of 15,033 barrels of oil per day. The production level was highly constrained during the first two months of the fourth quarter as the low river levels resulting from the unusual dry season materially impacted barge transport and tanker unloading capacity at the Brazilian port of Manaus. As you can see in this slide, river levels have since returned to higher levels, supporting production in excess of 20,000 barrels of oil per day at times during the Q1 2024. During Q4 2023, we invested approximately $32 million of CAPEX focused on drilling the 16H well, as well as ongoing infrastructure projects. This resulted in total CAPEX spent during 2023 of $108 million, approximately $12 million under budget for the year, which helped push Free Funds Flow to over $90 million by the end of 2023, equating to a 16% free cash flow yield based on our year-end market capitalization. From a per barrel perspective, lifting costs were $7.24 per barrel in the quarter versus $8.45 in Q3 2023 due to volumes sold in the fourth quarter. Q4 2023 transportation costs were $3.61 per barrel versus $4.64 per barrel in Q3 2023 due to lower floating storage costs related to the Brazilian route and increased barging activity. The floating storage costs allowed the company to ramp production up very quickly and avoid longer barge normalization times when river levels increase. All in, the company delivered a total OPEX and transportation cost of $10.85 per barrel versus the prior quarter of $13.09 per barrel. The company believes that with higher sales volumes in Q1 2024, run rate OPEX per barrel should continue to trend lower, excluding the impact of the one-time erosion control cost project. Slide four summarizes our 2023 year-end reserve report matrix. Key highlights include 2P reserves are now over 100 million barrels, with 3P reserve at 200 million barrels. We achieved 1P and 2P reserve replacement ratios of 150% and 167%, respectively. With three well locations upgraded from the possible category to the probable category, the total 2P well count now stands at 32, while the 3P case well count remains at 36. The 1P and 2P after-tax net present value NPV10 per share values grew to $0.97 per share and $1.80 per share, respectively, equating to a valuation of $900 million and $1.6 billion on an after-tax NPV10 basis. The company anticipates the 2P and 3P reserve cases converging in future years with continued drilling and well history data. As I have mentioned in the past, our goal as petroleum engineers is to produce as much of the 2P original oil in place volume as possible to eventually surpass the 30% recovery factor mark. Slide 5 showcases the company has averaged 18,250 barrels of oil per day during the first quarter of 2024 as of yesterday, that we reported 20,800 barrels of oil per day. The field was shut down from March 6th until March 8th as a safety precaution after an independently operated barging incident caused a small release of oil into the Puinahua River, approximately two kilometers downstream from Bretaña. No injuries were reported, and the cleanup has been substantially completed. The field downtime constrained a total of approximately 90,000 barrels of oil, equivalent to an average of 1,000 barrels of oil per day for the quarter. Notwithstanding that, the company still expects to meet Q1 2024 production guidance of 18,500 barrels of oil per day. Well 17H was completed on March 10th, 2024, on time and within its $14 million budget. The well has averaged approximately 3,300 barrels of oil per day on natural flow. We have yet to turn on the ESP. We plan to wait a few more days before we turn the electrosubmersible pump, where we will see then higher rates. So substantially, it's performing in line with expectations. The company also commenced drilling the well 18H on March 5th, 2024, with an estimated cost of $14 million. The well will take approximately 60 days to drill and complete with fresh production estimated by mid-May 2024. Slide 6 showcases PetroTal's sales routes diversification strategy with continued advancement on the OCP pilot oil shipment, with the signing of 3 key approvals. The company is now waiting on a final letter of approval from the port subsecretariat to start the 100,000 barrel pilot. Pending success of the first pilot, the company anticipates an additional pilot in the second half of 2024, with recurring sales expected in Q4 2024. I will now turn over the meeting to our CFO, Doug Urch, who will provide a brief financial update. Thank you, Manolo. I'm Doug Urch, PetroTal CFO, and would like to start off highlighting a few select financial items from our recent press release and financial statements with visual support from slide seven. From a balance sheet standpoint, PetroTal exited the quarter with over $111 million of total cash and is in a $57 million net surplus position considering other working capital amounts. The company has no long-term debt or amounts drawn on its short-term credit facility as at the end of 2023. The company delivered strong financial metrics in the quarter on approximately 1.4 million barrels of oil sales, compared to just over 1 million barrels in Q3 2023. Following is a short summary on key P&L line items. Net revenue of $84 million, representing $60.77 per barrel. Contracted at Brent in the quarter was $81 per barrel, compared to $84 per barrel in Q3 2023, with the Brazilian transportation differentials and backwardation reconciling the realized net revenue per barrel amounts. Royalties for the quarter were $9.7 million or $7.24 per barrel and include social trust provisions. This was up slightly on a per barrel basis from Q3 2023 due to a one-time royalty-related valuation adjustment that occurred in Q4 2023. Total gross OPEX and transportation costs in the quarter were $15 million, representing $10.85 per barrel, compared to approximately $14 million or $13 per barrel in Q3 2023, driven largely by higher sales volumes sold in Q4 versus Q3. Q4 2023 net operating income of $59.4 million or $43 per barrel, compared to $49.4 million or $46 per barrel in Q3 2023 as a result of the lower Brent oil price. Q3 2023 free funds flow was $8.1 million, down from $36.9 million in the prior quarter due to the lower Brent prices and higher Q4 capital expenditures. Total free funds flow for the year was over $90 million and equated to a 16% yield on the company's year-end market capitalization. Net income for the quarter of approximately $21.5 million, representing $0.02 per share, was realized, compared to $25.4 million or $0.03 per share in Q3, making it the 16th consecutive quarter of net income for the company. As shown on slide eight, the company is reiterating its overall 2024 guidance. Average 2024 production is still estimated between 16,500-17,500 barrels of oil per day, with around $200 million in EBITDA backstopping a $135 million capital expenditure program, weighed heavily to the first half of the year. Note that year-to-date 2024 Brent prices have trended above our $77 per barrel budget expectation and will aid in supporting increased free funds flow levels in Q1 2024. On slide nine, the company is also reiterating its estimated 2024 cash level with an exit 2024 liquidity range of around $60-$70 million, leaving a small buffer for unexpected working capital needs. We encourage investors to view our free cash flow matrix on slide nine of our March investor presentation for the latest annualized production and Brent free cash flow sensitivity. Slide 10 summarizes our return of capital policy and amounts paid to date. During Q4 2023, PetroTal was very pleased to announce and approve the dividend of $0.02 per share based on Q3 2023 results, which was paid in Q4 2023. That represented an additional $0.005 per share over the base of $0.015 per share as per the company's cash use policies. The company was also pleased to recently finalize and pay its Q1 2024 dividend on March 15th, 2024. Based on Q4 2023 results and cash balances, PetroTal approved another $0.02 per share dividend that was paid on March 15th, representing an estimated 14% annualized dividend yield based on the prevailing share price. This represents an additional $0.005 per share amount over the base $0.015 per share due to available cash and short-term future working capital needs early in Q1 2024. Through the existing share buyback program, year-to-date in 2024, the company has purchased approximately 4.7 million shares, representing $2.7 million. PetroTal expects to renew its normal course issuer bid share buyback program this spring, subject to any trading constraints imposed by the TSX. I thank you for your continuing investor support. I will now turn it back to Celicourt Communications for the Q&A session. Thank you, Manolo. Doug, the first question: I'm curious about sales capacity. How does the company value the flexibility of raising sales capacity against the cost of various transport-increasing methods? You know, the company will always give priority to the ability to move oil and sell additional barrels. If new routes are available at a higher cost compared to current routes, the company is okay with this, and there will be the ability to optimize costs in the future. If we have to shut in barrels due to lack of sales route, the company receives zero revenue, so this is the worst option. Keep in mind that, as you have seen in our certification and we have it in our corporate presentation, at the end of the contract, there's still a lot of production. So the more we produce now, the better for the company. You have seen also in our corporate presentation, we give you the netback for the different routes. They're all about the same, except the one via Yurimaguas that requires trucking. Even the OCP via Ecuador has similar netback, and we are always, always optimizing things. The company's 2024 guidance shows $5 million in derivative true-up payments targeted for Q1 2024. Is there any update on that? Yes. The batch now is at the port of Bayóvar, and it's going through a tender at the moment. So we should get more information in the following month. Will the new relief package offered by the Peruvian government to Petroperú, consisting of a state-guaranteed $800 million loan as well as a state-backed $500 million credit line, make a difference in the ONP becoming a viable option this year for PetroTal? It will have a positive impact, although that money is mostly for Petroperú to be able to manage the purchase of crude oil for the newly new Talara refinery and continue also to supply the local market with fuels. However, with the expectation that Block 192 comes to life later this year, then the pipeline is to work. So we have now Petroperú, you know, fully aligned with the other producers because they're going to depend on that ONP. Considering the relatively low average production numbers thus far from 17H, how much can we expect it to increase when the cleaning of drilling fluids is complete? Well, in my remarks, I made emphasis that this well was initially put on natural flow. It doesn't, the pump that is always installed when we complete the wells has yet to be turned on. The reason for that, we wanted to make sure that the well clean itself naturally. So a well that naturally produces 3,300 barrels of oil is a big well, you know? So we will see much higher rates once the pump is turned on. We see all of the indication on the productivity index being like all of the other big wells that we have there. When is there to be exploration further to the southeast of Block 95? We are now finalizing the tender process for the 2D seismic survey, and we are also waiting for the final environmental permit. So if everything works out, we should start the survey in the second half of the year. With PetroTal's significant market cap, why is the company not listed on the LSE main market instead of AIM? And are you considering to list on the LSE's main market? We do take a look at which markets we should be listed on. Investors will recall that a year ago, we upgraded our listing in Canada to the TSX from the TSXV. Considering the movement from AIM to LSE, we'll still continue to look at that. There are no current plans, but we believe that the liquidity that we see on AIM and on the TSX exchange is working well for us. If more routes to market become available, like the ONP in Ecuador, would this result in PetroTal increasing its output to higher than the 16,500-17,500 barrel a day guidance? We have in our guidance already included a couple of the pilots for the OCP of Ecuador. So that's already incorporated in the guidance. As I mentioned also in my remarks, the idea is by year-end to have this on an ongoing basis. So you will see the impact more the following year. We did not include the ONP in this year's guidance, not knowing when it was going to come back. But that could have a positive impact on our guidance, given that we are always constraining production. What led to the lower-than-planned Q4 spending? Capital spending was lower than planned due to some facility projects that were delayed and deemed appropriate to push into 2024 or beyond. Our 2024 budget does contemplate these carry-forward amounts. With diluent no longer required, netback for the ONP has improved drastically. Is your goal to use the ONP this year? As Manolo mentioned, we have assumed no ONP sales in our 2024 budget. However, under the approved conditions and liquidity payment terms, we would consider it. This is the first part of a two-part question. Have the last two wells, 16H and 17H, performed in line with expectations? 16H seems on track to deliver payback in around three months, but 17H appears to be delivering only circa half the initial production rate of well 16H, although this is still only on natural flow. Yeah. Actually, as I mentioned, the 17H is meeting our expectations. Should also pay out in 90 days or something like that. And the 16H, as mentioned here, is performing just as expected. So we have now Bretaña well model, so there's no surprises. $20.4 million of receivables has been reclassified from current to non-current assets. Yet this is despite the ONP pipeline likely to deliver that oil in calendar 2024. Is this your auditor's taking conservative view, or is it now less likely that the oil is delivered in 2024? Well, I guess just thinking about the ONP, it's not functioning in a major way at this point in time. Without new oil going through, there's no guarantee of when the other oil will come out. So on a conservative basis and it's not just driven by the auditors, but the conservative basis of us as a company, we don't anticipate that volume of oil to be sold until after 12 months. So hence the recategorization to long term. Thank you. Just a reminder, if you'd like to ask a question, please submit it via the platform. Next question: Why the lower actual oil price relative to Brent in Q4 2023 versus prior 2023? Can you repeat the question? It's not appearing here. Sorry. Why the lower actual oil price relative to Brent in Q4 2023 versus prior 2023? Well, we have to keep in mind how the exports are priced. It's based on future Brent pricing. So with respect to Brazil exports, it's tied to pricing the forward three-month price, whereas sales to Iquitos are priced at the current price. So hence you do see some variance as compared to the actual Brent for any particular time. How is the erosion work going? Is it within the substantial budget? It was still in completing the final detailed engineering. We've done some of the procurement of the materials that are going to be needed. So it's going well. And just to emphasize again, it's a one-time project that will allow us to control the erosion in the future. Thank you. How are community relations at present? They're going well. You know, with this recent incident, we could see the impact of our social programs as the communities reacted well to all of the support that we've been providing. Thank you. There are no further questions at this time, so I'll now hand back over to Manolo and Doug for closing remarks. Well, I want to thank all of our investors that listened to this webcast. We continue to work hard to maximize the value of PetroTal. We're looking forward to starting the seismic survey in the rest of the Block 95. We see the possibility of finding additional Bretañas, which is why we have this strategy to diversify our oil sale routes to be able to manage all of that production in the future. And of course, for that, eventually, we're going to have to go back to the ONP. It's something that every time I go to Lima, I usually visit the people at Petroperú to encourage them to get all of that online. So we're very optimistic about the future for the company. Thank you so much.