Good day, everyone, and welcome to 3R Petroleum fourth quarter and full year 2023 earnings conference call. The presentation and comments about the results will be presented by the CEO, Matheus Dias, by the CFO and Investor Relations Officer, Rodrigo Pizarro, and by the Exploration and Production Officer, Maurício Diniz. We inform that the simultaneous translation tool is available on the platform. To access it, simply click the interpretation button at the bottom of the screen and choose your preferred language. This conference is being recorded and will be available on the company's Investor Relations website, ri.3rpetroleum.com.br, as well as the presentation that we will show here. Be advised that all participants will be in listen-only mode during the presentation, and then we will begin the question-and-answer session when further instructions will be provided. Before proceeding, we take this opportunity to stress that forward-looking statements are based on the beliefs and assumptions of 3R's management and on current information available to the company. Forward-looking statements may involve risks and uncertainties because they relate to future events and, therefore, depend on circumstances that may or may not occur. Investors, analysts, and journalists should understand that events related to the macroeconomic environment, the industry, and other factors may cause results to differ materially from those expressed in such forward-looking statements. Good afternoon, everyone. Welcome to 3R Petroleum conference call to discuss fourth quarter and full year 2023 earnings results. The presentation will be made by myself, by Maurício Diniz, Chief Operations Officer, and Rodrigo Pizarro, Chief Financial and Investor Relations Officer. We begin on page three with some highlights that provide an overview of the robustness of 3R's portfolio and the main achievements not only in the fourth quarter but also in the full year 2023. Firstly, this year marked the consolidation of the company's asset portfolio with emphasis on the latest deal completed, Potiguar Cluster, which brings, in addition to the aspects and relevance in production and reserves for 3R, its infrastructure, which promotes integration of practically the entire production chain between upstream and midstream, a strong point of comparative advantage, capillarity, and operational and commercial flexibility. The company ended 2023 with daily average production of 47,000 barrels of oil equivalent and with significant organic growth. If we disregard the Potiguar Cluster, which was the latest deal completed, we had an increase of approximately 40%, the result of well-executed planning for workovers in existing wells, both onshore and Papa-Terra, and the start of drilling at Macau and Areia Branca, as well as numerous maintenance projects and the expansion of the capacity of surface systems and equipment. I would also like to underscore the fast-track projects carried out in the industrial assets of the mid-downstream in the Potiguar Complex, both in the refining and gas processing units and in the tank farm. In terms of financial performance, the company reached approximately BRL 700 million of adjusted EBITDA in Q4 and BRL 1.9 billion in the full year. This is a very important milestone in the growth and development path of the company's portfolio. It is worth noting that, considering the second half of 2023 on an annualized basis, and that in this period we already had this entire portfolio under operation by 3R, a leverage of 2.2x. We would also highlight the start of the dilution of fixed costs in the composition of the company's lifting costs, driven largely by the upward production curve, bringing more scale over the period. In figures, we ended the year with $18 per barrel. Finally, regarding our capital structure, since 2023, the company has been making a great effort to improve interest rate conditions, covenants, and amortization profile and balance of the duration of our consolidated debt. And in this context, 3R had its first bond issuance, as well as the issuance of two local debenture instruments. With this introduction, we move on to the next slide with graphs showing the company's operating and financial performance. In general terms, on the operational side, the result for the fourth quarter was an average production of 45,900 barrels of oil equivalent per day, with a positive trend seen in each quarter, not only because of the conclusion of deals but also, as I mentioned earlier, because of significant organic growth, the result of execution in line with the planning of facilities projects, workovers in existing wells, and successful drilling. Regarding financial performance at the bottom of the slide, we have the same observation with important marks in the fourth quarter and in the full year, both in terms of revenue, EBITDA, and lifting costs. Now, let's move on to the next part when we will look at commercial and operational aspects. On page six, we have an overview of the Potiguar Complex with emphasis on what can be easily seen in the highlighted graph, i.e., the integration of the production and logistics chain. Again, a few observations to clarify this element of strength in our chain. A large part of the production from the fields in Rio Grande do Norte is connected via pipelines, which are extremely advantageous when compared to others in terms of operational risks and costs. So, it is connected via pipelines to the Guamaré Industrial Complex where all the production is offloaded, both oil and gas. In Guamaré Asset, which includes primary oil processing units, effluent treatment, refining, and natural gas processing units, there is the processing and specification for the market of oil products and treated gas. There is also a terminal for private use, which, together with a significant tankage farm, provides ample business flexibility for products, whether byproducts or crude oil itself, enables inbound and outbound operations, i.e., for the domestic market or exports via two monobuoys for mooring vessels. In fact, once again, this integration brings not only commercial flexibility and greater control and management of costs in the chain but also a great deal of independence for 3R's operations, as well as a leading role in the region's logistics flows. On the next slide, still on the subject of the relevance of the Rio Grande do Norte assets to 3R's portfolio, there are some additional highlights. As regards our commercial aspects, and given what has already been said, the infrastructure also represents an advantageous solution for other companies operating in the region. In this context, 3R provides services and/or acquires oil and gas from third parties for processing, basing the prices charged on the costs of the infrastructure and market conditions. Still on the commercial side, but regarding sale of the products marketed post-processing, in other words, oil products, 3R also operates within market pricing policies. I would just like to highlight the off-taker agreement signed in January 2024 for bunker fuel, which accounts for 50% of the refinery's total production with a term of 36 months and the fixed price modality. From the 13th month of the contract, in addition to the fixed price, there will also be a profit sharing relating to the operation with our partner. With regard to the structural aspects of the cluster and the vision of the future of upstream, a large part of the company's total reserves are concentrated in the Rio Grande do Norte region, with a significant proportion of 1P Reserves compared to the total of proved and probable reserves, which, at the end of the day, basically translates into a great prospect and potential for organic growth. On the next page, we present the quarterly evolution of the monetization of crude oil and processed gas molecule. In oil, we are still at around 90% of the unit value compared to the Brent. This slight decrease compared to the last quarter is basically justified by maintenance carried out at the refinery in Potiguar, so that we necessarily had to market crude oil directly, and that the first cargo offloads generally have a slightly higher discount until the oil is better known in the market. In our case, we carried out operations not only in the domestic market through cabotage but also exporting this cargo to refineries outside the country. As for gas, we had an improvement and reached 12% of the reference value, which is the Brent. I will now hand over to Maurício Diniz, our Chief Operations Officer, so that he can explain the operational aspects. Thank you very much. Thank you, Matheus. Let us now talk about our operation and upstream information in the four clusters where we operate, and they are: Potiguar Complex, which is made up of assets in the states of Rio Grande do Norte and Ceará, a merger of those assets from the start of the company, and the others integrated in June 2023: the Bahia Cluster, Espírito Santo, basically Peroá Field, and Rio de Janeiro, Papa-Terra Field. Starting with the Potiguar Cluster, I'd like to highlight our first and iconic field, Macau. As we have often mentioned, with greater knowledge of each area, both in the subsurface, in the reservoirs, and in improving the integrity and adaptation of these surface facilities, we have proven the great potential of our assets. Macau is a great example. After those initial problems, mainly carrying out works and difficulties in contracting rigs, in 2023, we had a large number of workovers and drilling at the field and adjustments to its facilities, mainly construction works at the two collecting stations. The field's production, as shown in the graph, rose by 80% over the year, now reaching, in January 2024, 7,300 barrels of oil equivalent daily, more than 80% of which being oil. In addition, we have achieved significant reduction in our lifting costs, reaching single-digit figures at Macau Field over the last few months. In the following graph, we can see the progress of our production at the entire Potiguar Complex, highlighting the closing of Potiguar Cluster at the beginning of June 2023. To make all of these activities possible, 13 rigs worked at the field in Q4, carrying out workovers, reactivations, and equipment changes, and we had two rigs in charge of drilling, with a total of 219 wells that underwent some kind of intervention in Q4 2023. I would note the drilling of 38 new wells in the area. CapEx was distributed between work on wells and facilities, which is really paying off, as shown in the production indicators. I would also like to point out that eight months of operation have elapsed at this latest complex closing in Canto do Amaro, Canto do Amaro, and Alto Rodrigues fields, with no significant safety or environmental events, as has been the case throughout the company. Another highlight in the area is the steam injection project in Estreito and Alto Rodrigues. We recall that due to the high costs, we terminated the steam supply contract with a thermoelectric plant at the time of the closing. An internal 3R project was then set up, divided into four phases. The first of these is the overhaul of the GVs that were not in operation at the time of the closing. This project is underway, and some GVs are already in operation. The second phase is the revitalization of four steam stations, the first of which consisting of four generators is ready and awaiting an operating license in March. The third phase is the purchase of three steam generators, with 45% of their manufacturing process already concluded, and the final phase is the purchase of three other generators already manufactured that are in the process of having the purchase agreement signed. In short, we started the operation with an injection rate of 1,800 tons daily. Today, we are already injecting around 3,000 tons, and we will reach, by the end of the last quarter, 7,500 tons per day required for this phase of the project. Moving on to the next slide, we will talk about the Recôncavo Complex where, in December, we reached the ninth quarter of continuous production increase at the Bahia Fields and the highest oil production since the start of our activities in the area. In the Bahia Fields, we are working with seven workover rigs that worked in 53 wells in Q4 and two more rigs that are completing assembly, one of them already licensed to operate, operation should start next month, and the other awaiting an operating license to start its activities. At Recôncavo, we are also carrying out an important CapEx program for revitalization with the aim of preparing the facilities for the increase in production that lies ahead. On the next slide, we'll talk Papa-Terra, where we can clearly see in the first two graphs an increase to production and operating efficiency of the field's two platforms. Total daily production of the field, including our partner's stake, reached 16,400 barrels of oil in the last quarter, a significant increase compared to the beginning of the year. In the graph on the right, we can see production efficiency. This is an indicator that shows what has been produced in relation to the potential of the wells. In other words, those problems that we have already talked about on several occasions over the past year are being resolved satisfactorily, and there has been a substantial improvement in operating efficiency since the closing. I would like to highlight an average efficiency of 22% in the last 12 months of the previous operator, and now, at the end of the year, we are reaching 93% operating efficiency Papa-Terra. several of those works that were mentioned have already been carried out, and we are now completing inspection and maintenance of the second boiler, one of the power generators with overhaul reaching the final stages, transfer pumps repaired, and the main offload system in its final stage of maintenance. Another important integrity program at the FPSO 3R-3 will now begin in the second quarter with the hiring of a maintenance unit working for 90-120 days, with a 15-day production stoppage in Q3. Another important point at Papa-Terra, which has been reflected in production now in these early months of the year, is the workover at some wells to exchange the pumps after three to four years of operation. One of the rigs that can work on a W et Christmas tree has already carried out two successful workovers on Papa-Terra 22 and Papa-Terra 12, exchanging the ESPs, and is now working on Papa-Terra 37. Another point that also caused a lot of concern in the past was having a rig available to operate in the TLWP, which has achieved by setting up a structure that allowed this rig to be placed on top of the 3R-2 itself. The rig is much cheaper than the old TAD tender assisted that operated alongside the 3R-2, allowing the workover in the main wells of the field. We have already started the workover Papa-Terra 17 and Papa-Terra 50. These three Papa-Terra 37, 17, and 50, will resume production during the second quarter. We also plan to drill a new well in the second quarter, which is only waiting for the environmental license. This license is not similar to that of a new well, as it will use the same subsea line of an existing well in the same field where several wells have already been drilled, and it is adjacent to a well that produced around 5,000 barrels a day, but it has been inactive due to mechanical problems by the former operator. Finally, we have the Peroá Cluster, where production remains stable in line with a sales contract. We should highlight the improved monetization of gas over the quarter due to the new contract price with consumers. In the next slide, the two charts show an overview of production with 3R's working interest. In the upper chart, we have oil and gas, and in the lower one, only oil. Since the startup of 3R's operation, we've always had a quarter-on-quarter increase in production. In the fourth quarter of 2023, oil production accounted for almost 80% of total production, and 55% comes from Potiguar. We reached 45,900 barrels a day, and now, in January, we will continue to increase with 47,200 barrels a day, of which more than 37,000 refers to oil production. In our view, the synergies between onshore and offshore are quite significant. There is a great exchange of knowledge and experience between the technical areas, and on the other hand, there is a production aspect. While onshore production continues to grow at a steady pace, we were able to activate peaks of increasing offshore production and cushion ourselves when there is a drop in production. In this last slide, in terms of operating, we put the organic growth throughout 2023. As Matheus mentioned before, our production was up 43%, not including the conclusion of new transactions. The knowledge that has been acquired, the quality of our assets, workovers carried out, production optimizations, improved integrity, and management have resulted in 43% growth in 2023, one of the best operating results among operators in Latin America. We now hand over the floor to Pizarro, who will present our main financial KPIs. Good afternoon, everyone. We will now initiate the part related to financial highlights for 2023. On slide 16, we show the company's net revenues. We ended 2023 with around BRL 5.6 billion in net revenues, of which BRL 1.85 billion in the last quarter alone. Due to the scheduled maintenance of the refining units and the NGPU, Natural Gas Processing Unit, in Rio Grande do Norte, revenues from the midstream and downstream segments were lower, but upstream revenues increased by 7% compared to the third quarter. On the next slide, we detail the evolution of upstream revenues by basin and the breakdown of the fourth quarter by type of product. Of the BRL 1.6 billion in net upstream revenues, around BRL 1.25 billion came from onshore basins and the rest from offshore assets. 87% are oil revenues and 13% gas, again reinforcing the importance of having a portfolio anchored in oil. On slide 18, we show the company's EBITDA evolution. Even considering the scheduled maintenance of the refining units, adjusted EBITDA totaled around $140 million in the fourth quarter and more than $300 million considering the second half of 2023. This means the first half of the year in which the company operates its entire portfolio. Moving to the next slide, a further highlight in the company's lifting cost. Once again, we managed to reduce our lifting cost, averaging $18 per barrel of oil equivalent in the fourth quarter. Lifting costs for onshore assets were close to $16.70 per barrel, bearing in mind that our lifting cost includes logistics via our own pipelines until the product is sold or transferred to the midstream and downstream segments, which is often not taken into account by other Latin American onshore operators precisely because they don't have their own logistics capacity. In practice, for these operators, logistics costs are not allocated to lifting costs, but they do have an impact on the sale price of the product or are allocated as a service paid to third parties apart from the lifting cost. Offshore, the intense work to improve the facilities and increase production Papa-Terra has contributed to the dilution of costs, reaching $21.8 per barrel of oil equivalent, both Papa-Terra and Peroá on a consolidated basis. As we often point out, we are still working on recovering the integrity of the FPSO, mobilizing the main suppliers on board, and this phase should be completed by the end of the third quarter. On slide 20, we show the evolution of the company's investments. In 2023, we allocated around $283 million to CapEx projects, including the onshore drilling campaign, infrastructure, and corporate investments in IT systems, and around $42 million for future CapEx, mainly in the last quarter, to invest in drilling projects, first workovers of offshore wells, and the revitalization of facilities throughout 2024, totaling $325 million in 2023. The following slide shows the company's capital structure. We ended 2023 with a robust cash position compatible with our investment plan after an intense commitment to liability management. We have extended our debts, reduced costs, and made our obligations and covenants more flexible with the latest issues. We no longer have coverage ratio covenant, for example, and we have maintained the company's net debt close to $1 billion considering financial debts and around $1.4 billion if we also consider obligations related to acquisitions. The level of leverage remains quite under control, close to 2.2x considering the adjusted EBITDA for the second half of 2023. Even with the recent issue of the seven-year bond and the new institutional debenture at the beginning of 2024, as the amounts were fully used to repay debt instruments of equal amount, no changes are expected in the company's net debt position at the beginning of the year. On the next slide, we summarize the effects of the $500 million bond issue made at the beginning of 2024 and the prepayment of a private debt in the same amount higher for the acquisition of the Potiguar Cluster. It is worth noting that the bond market has not seen a new Latin American issue since early 2022, which is once again the result of the company's intense efforts to present our investment thesis to the international market and look for ways to diversify funding sources and optimize our capital structure. With our cash position and the reprofiling of the payment flow of the principal amount, we are in a comfortable position to proceed with the investment projects, even considering oil curves that are more conservative than the current ones. On slide 23, we show our hedge position, totaling around 7,800,000 barrels contracted in line with our hedge policy. The NDF contracts are close to $80.4, and the zero-cost collar contracts have a floor of $55 and a ceiling close to $95 per barrel on average. In the next session, we present the ESG initiatives, and we revisit the fundamentals of the 3R thesis, and as usual, we reinforce the management's priorities for 2024. On slide 25, in what concerns the ESG aspects, it's worth noting that in 2023, the company published its first sustainability report. We coordinated the Reflorescer Project in Rio Grande do Norte for the restoration of 60 hectares of preservation land. We launched the 3R Capacita project in partnership with SENAI in Rio Grande do Norte that offers more than 380 seats for technical training courses. In addition to the Clean Company seal, we also joined a select list of 84 companies recognized by the Federal Comptroller General's Office for their commitment to preventing corruption and fraud, for which around 300 organizations have applied. On the next slide, we reinforce the pillars of 3R's investment thesis, with the acquisition Papa-Terra Cluster in December of 2022 and Potiguar in June of 2023. We then became one of the largest independent companies in Latin America. Fortunately, as the largest assets were recently acquired, we still have a lot of low-hanging fruits, both onshore and offshore, with opportunities for cost reduction, increased efficiency of surface systems, and dozens of reactivations of onshore wells. Another important aspect is that we are a company whose growth does not depend on new acquisitions. It does not depend on exploration or third parties. We have a portfolio of more than 500 million barrels of 2P Reserves, a low recovery factor of assets, and we have already demonstrated in 2023 that the efficient use of CapEx brings relatively quick results. We have a very efficient operating cost, bearing in mind that our lifting cost includes logistics, as we recently mentioned, and is calculated in a very conservative way. In a comparative analysis, it's important to consider logistics and processing costs for both gas and oil. Precisely because we have an integrated portfolio, we have a very competitive total operating cost. It's worth noting that at the end of 2023, we received a SUDENE benefit for all the assets in Rio Grande do Norte, Bahia, and Espírito Santo, including a reduction in the income tax rate that also contributed to a better free cash flow per barrel. Finally, with the liability management effort, which we implemented in a very intense and dedicated way between the end of 2023 and the beginning of 2024, we are prepared for the company's investment plan with any major concerns regarding the covenants. On the last slide, as a management priority for 2024, we can highlight the plan to increase the efficiency of onshore and offshore surface systems, which contemplates the integrity recovery plan for Papa-Terra FPSO and the expansion of the water processing and steam injection systems in the Potiguar Basin. Another important aspect is the intensification of onshore and offshore drilling and workover campaigns, which have already shown excellent results in 2023. Another priority is to maximize the value of midstream and downstream assets by expanding strategic partnerships, evaluating M&A opportunities, and increasing service revenues. And finally, we are committed to evaluating portfolio optimization alternatives, always with a focus on maximizing value in the medium and long term for our shareholders. Thank you very much for joining us, and now we will move on to the Q&A session. I will now begin the Q&A session. If you wish to ask a question, please click on the Q&A icon on the bottom part of your screen and type your question. To ask questions live, click on the Raise Hand button. Please hold as we collect the questions. Our first question comes from Mr. Leonardo Marcondes with Bank of America. Mr. Marcondes, you may speak. Good morning, everyone. Can you hear me well? Great. I have some questions here, my first being regarding the M&A with Recôncavo Cluster from 3R's perspective. Could you tell us what have been the main pushbacks and feedbacks that you have received from the market regarding the deal and whether you have a more concrete expectation regarding the timing for for the deal to happen? My second question has to do with the liability management done by the company recently. Pizarro kind of spoke about this, but I just want to make sure you understood this well. Is there any covenant that may limit you from investing in increasing production this year? And perhaps you can remind us of the breakeven for cash generation for the year. And if I may ask a third question, we saw the lifting cost declining one more time this quarter. I'd like to know, what is the expected lifting cost by year-end? And Pizarro kind of spoke a little about it, but how do you see the cost structure of your lifting cost, if we can compare with your reported structure with the ones the structure of your peers? Excellent, Leonardo. Thank you for the questions. To answer your first question regarding M&A with Petro Recôncavo, what we can say is a little bit of what we have reported to the market. We engaged Itaú as our advisor, and we have other legal advisors also following the evaluation of this possible deal. At this point, we are in the validation, verification, and technical due diligence stage on both sides. Petro Recôncavo also engaged their own advisors, as they mentioned, in their own earnings calls. We have a technical period of joint evaluation, so we cannot really say what is the right timing and what's coming next. What we can tell you, though, is that we do not have any consolidated view regarding structure, governance, and the deadline for the deal. On the other hand, on our end and on their end as well, we have full engagement and alignment in terms of the deal making sense. We'll step on the gas because companies in the process of emerging without a defined deadline, well, that's something that can get in the way of the execution plans of both companies. In a nutshell, that's what we can say at this point about this M&A deal. Regarding liability management, basically, we did intense work in-house. It started in 2023, at the beginning of 2023, when we structured the company for the acquisition of Potiguar Cluster. I'd like to remind you that in the past, we even considered keeping 70%, 80%, 90% of the asset. In the end, fortunately, our governance and our management defined that we should have 100% of Potiguar Cluster. For that, we had to structure a slightly higher debt than originally thought of. We also had a capital injection to support the capital structure adequately for the company. Fortunately, all along 2023 and the beginning of 2024, we were able to replace that debt with the debt that we had. It was a relatively small debt compared to our CapEx execution plan, so we were able to replace it by a long-term debt, which is a 7-year bond with a competitive rate, reopening the debt market for new issuers in Latin America since February of 2022. Regarding the covenants, not only have we replaced that debt and naturally flexed or eased the covenants because a bond always has restrictions or much lighter restrictions than obligations. Just to give you two examples, both in coverage ratio, or we used to call debt service cover ratio, we don't have that covenant anymore in all of our debts. We have no obligation to measure the cover ratio, which is normally the covenant that limits CapEx execution in any company. We need to evaluate our free cash and how much CapEx we're implementing vis-à-vis our financial obligations. We do not have that obligation any longer. For the bond, we don't have the obligation to measure the covenant periodically. It is what we call incurrence covenant if we want to issue a new debt by the company. Still, we have some flexibility to issue a debt even if we achieve certain levels. In a nutshell, we have a covenant and obligations structure, which is a lot more flexible. We have no concern even if the Brent drops 15%, 10%, 20% compared to the current price. As for the breakeven for the year, as we normally stress, having a portfolio structure concentrated onshore, we always have great flexibility to reduce the pace of CapEx execution onshore. We currently have about $300 million planned for onshore, about $100 million planned for offshore. These $300 million for onshore can be reduced to $200 or $200 million, depending on the short-to-mid term of the future curve of oil. This is a differential compared to companies which are positioned exclusively on offshore projects. We have this ability to adjust the CapEx also upwards. Of course, the flexibility to reduce is greater than to increase the CapEx, but we have a lot of flexibility. And the calculation of the breakeven, well, if we get to a structure of $52-$54, we still have the ability to have a positive EBITDA. We still have the ability to implement a fraction of the CapEx, of course, not the full CapEx. But I'd like to remind you that we reinforced the company's cash position, and that's why we have a lot of flexibility to serve the financial obligations for the next three years, which are very low, as we showed in the pro forma slide that shows that in the next few years, financial obligations and obligations with Petrobras are a lot lower than they were three months ago. Regarding the lifting cost, that's also an excellent question. The cost structure of the company, because we have mid and downstream assets in Rio Grande do Norte, which is where we operate most of our assets, and also Papa-Terra, in Peroá, because we have the floating units and the fixed Peroá unit. In other words, the equipment is ours. We do not have to pay daily rates to third parties. We don't have to pay for natural gas processing to third parties. So all of that in our cost structure is accounted for in the lifting cost. When we compare this with other companies that do not own, these structures do not have, and FPSO do not have the pipeline structure. Everything we have in Rio Grande do Norte, which is storage, pipelines, processing of natural gas, etc., this comparison is not always comparing apples with apples. To give you some examples, all our lifting costs in Rio Grande do Norte comprise the logistics by pipeline until we get to the mid-downstream. This logistics can cost seven, eight, nine, sometimes even more, even in Brazilian players as well as Colombian players. To give you another example, abroad. So ideally, when you compare, you should evaluate the lifting cost, the logistics, whether the logistics is embedded in the selling price of the product, which is the case of third parties here in Brazil. They sell their asset, oil and gas, to 3R. You have to evaluate processing costs. Just to give you another example, $1, $2, $3 per million BDUs of processing can represent $5, $10, or $15 per barrel of oil equivalent when it is time to sell the gas. So reinforcing the pillars of our thesis, as we have most of our assets concentrated onshore, concentrated on oil, and with our own infrastructure, when we consider these three aspects, lifting cost, logistics, and processing, it is very hard to find any player in Latin America with a cost structure as streamlined as that of 3R. Now, for you to analyze whether we are the best or the second best, you have to be very cautious in your analysis, in your evaluation. But in that league, we are not the best. We are among the top two, top three best in terms of operating efficiency cost. And as we mentioned in the presentation, we have a lot of low-hanging fruits. We still have a lot of improvements to make. And the trend is that costs will decrease. Not necessarily quarter after quarter will reduce the cost in all basins because there are workovers and improvements in all of the assets separately. But the trend is that by the end of 2025, we'll have a lifting cost structure that will be even more streamlined between $15-$17 per barrel of oil equivalent in Q4 of this year. Okay, super clear. Thank you for the answer. Our next question is from Bruno Montanari from Morgan Stanley. Bruno, your microphone is available. Thank you. Thank you for taking my questions. I have two questions, or maybe three. First, could you tell us about the production outlook for 2024? What should we consider in terms of evolution in the quarter and whether you can share with us what will be the expectation of the exit trading for the year? And my second question is in line with Leo's question on breakeven, but I'll put it differently. In your planning, thinking about a flat oil throughout the year, do you intend to be cash neutral, or do you think there should be a you would use some cash? How do you define this cash use before or after the payment of the principal of the debt? And my third question is probably an accounting detail. When you talk about your fourth quarter CapEx, so BRL 415 million, it does not dialogue with the cash flow. There is quite a difference. Is there any mismatch between the execution and the cash effect, or whether this disbursement will happen in the fourth—I mean, happen in the fourth quarter, or it occur in different periods? Hi, Bruno. Good afternoon, and thank you for your questions. I will start, and then I'll turn the floor to Pizarro, who will answer your question about cash generation and also that accounting question related to CapEx. In terms of our production plan for 2024, we believe that we will grow approximately 25% if we compare December of 2023 and December 2022, meaning that we ended the year with 47,000 barrels of oil equivalent on average, and our plan is to reach 60,000 barrels of oil equivalent by December of 2024. If we are to calculate the average annual production, that number should go to 51,000 barrels of oil equivalent on average for the year. But certainly, quarter-on-quarter, the performance will normalize throughout the second half of the year. It will normalize because of our strong campaign Papa-Terra. today, we have three workover activities Papa-Terra, and they should be concluded by May. The production potential is still limited, and it's around 10,000 barrels. Just to give you an idea, we are producing 13,000 barrels. So with the workover program alone, because in fact, there is something quite interesting to say here because all of these three workovers that are being done at the moment refer to wells that were producing for at least four years. I mean, two for four years and two for five years. With the change in the pumps, we gain some more breadth. Looking at the average lifespan, we gain at least three years. So probably today, we are producing 13,000 barrels with four wells, and we'd order three wells in the queue. With the workovers alone, we will be able to reach a potential of 23,000 barrels without considering drilling campaigns. This is an area where the company is working a lot and putting a lot of efforts, and we are prepared. We see great efforts to get all of the environmental licenses. This is very simple drilling once you compare it to other drillings because it's a twin well. In the set of lines and risers that are already in place and also in an environment that has no environmental restriction in terms of drilling the soil, etc. So Papa-Terra is where we are producing slightly less than what we produce in December. But after the conclusion of the workovers and also the maintenance facilities campaign that should be concluded by the end of July and August, this will not only increase our operating efficiency, but we will be much more robust when it comes to new pumps in production. This will certainly bring about greater stability for Papa-Terra. And this can be translated into lifting cost and more constant production. With the other assets, we continue to grow quarter-on-quarter, and you've seen that. So the onshore assets, they have lower increments of growth, but it's been quite stable in the company. Pizarro just briefly talked about CapEx, but 45% of the total CapEx of the company's total CapEx relates to workovers and the drilling campaigns. I mean, slightly above the numbers from last year. To give you an idea, up until February, we've concluded more than 200 workovers in the onshore wells. And this is due to a very well execution. It is in line with the plans of the company for this year. Of course, we are already in a very good position in terms of facilities and maintenance. Great part of the production, both Papa-Terra and Potiguar, was concluded. One slightly over a year and the other one last month. We still have to do some surface work, exchange of equipment, and to gauge some operating materials. But this is still a relevant amount of CapEx, but soon enough, we will be able to increase the number of workovers and drilling campaigns. But in summary, we ended the year with the plan for 60,000 barrels, and this represents an increase of 25% throughout the year with an average of approximately 51,000 barrels. And I hope I answered your question. I would just like to add one more thing Papa-Terra. if you calculate all the wells that had a workover and the ones that are going through the workover right now, by the end of May, 70% of our production will be with a new ESP. So if statistics work as it has been working, 70% of our production will have a new pump or a new ESP in the next coming year. So this is an important point. The other point is that I would like to highlight our improvements in terms of efficiency. We will have one unit in maintenance in May, and we will stabilize production, and this will solve integrity issues of the unit. Great, Diniz. I would just like to add one more thing. The additional 30% of the older pumps, they are on the TLWP, and we have there a cheap and permanent rig when compared to the traditional offshore rigs that allow us to do workover at a much lower cost and very quickly, and the pumps are already available. So in case any of the two wells that represent 30% of the production, if they stop operating in May, June, or December, we already have available rigs and pumps available for replacement. This shows that we will be much more resilient after June Papa-Terra because the revitalization stage Papa-Terra will be concluded. Now, Bruno, to answer your question about cash. 85% of 3R Offshore. I just want to clarify this. I mean, considering 3R as a group, but also considering only the 85% of 3R Offshore without consolidating the entirety, I mean, 100%, our EBITDA should be at least $630 million-$650 million. And if you consider the current oil curve, this number could go up or down. And certainly, to run that calculation, we don't need any guidance. All we have to do is look at what we've done in the third and fourth quarter of the company with that same portfolio. So the trend is increasing production, some dilution in fixed cost. Therefore, the other magnitude of this EBITDA should be around the numbers I gave you. In terms of CapEx, we have about $340 million-$400 million planned for our working interest, already excluding the 15% of 3R Offshore, which is from the partner. In terms of our Petrobras obligations, we have something around $115-$120 million, and we also have $125 million including the financial results. $150 million would refer to interest payments. And this is difficult to calculate. All you have to do is look at our total debt and just calculate interest rates for the next 12 months throughout the year 2024 and then deduct some possible financial revenue from that cash. This year, we already bring on board some financial revenues. Therefore, if you look at all the lines, certainly, the company has a positive free cash flow, meaning that operational minus taxes that I didn't refer to. But if we do the math and calculate an average tax rate of 25%-27%, I mean, 34% will be the full tax rate, but not even the 15.25% that we would have in the portfolio would be 100% incentivized. But this would mean about $80 million in taxes, and then we just do the math. I mean, whatever you decide to do it. So free cash flow is certainly positive. If we exclude the interest from the debt, cash will be close to neutral, slightly positive. And then if we exclude our obligations with Petrobras, that's why we did an additional funding of a local debenture for the company. So just revisiting liability management, we brought in $500 million in bonds that came in full to prepay the same amount with the syndicated loan. So we brought a local debenture of BRL 900 million, and this was fully used to pay a debt with a short maturity date and an additional $1 billion BRL to pay for our obligations with Petrobras. That's why I often say that net debt does not increase. I mean, when there is debt, part of it is to pay for our obligations, and the other part is to have more liquidity. Therefore, we are on our way to deleveraging, meaning that by the end of 2024, we will be less leveraged than what we are today. This doesn't mean that this will be reflected in the first, second, or third quarter precisely because of everything that we are doing in terms of workovers and improvements, particularly Papa-Terra. but by the end of the year, this will become clearer considering that Brent prices will be relatively stable, about 15% vis-à-vis the current curve. And finally, about CapEx in the fourth quarter. Bruno, this is a combination of prepayment to suppliers that we have done in the third quarter. So if you look at the second and third quarters, you see a reverse movement, meaning I mean, the working capital is higher than expected. But in the fourth quarter, we have operating cash flow less stable when compared to EBITDA minus taxes. It's very close to the operating cash flow. But on the other hand, CapEx used is much lower than CapEx that was allocated that was included in that slide about CapEx. We also have the effect of that CapEx that is measured throughout the fourth quarter, meaning the equipment arrived or the service was concluded. However, the payment was not yet materialized. So when you look at the combination of both, I mean, you will see that from now on, second and third quarter of 2024, you will see things more stabilized. I mean, in the fourth quarter, we will go down a level just to honor that CapEx of $380 million-$400 million for our working interest in 2024. Thank you. Thank you. Next question from Luiz Carvalho with UBS. Mr. Carvalho, you may begin. Good afternoon. And thank you for taking my questions. Congrats on the results. I have two questions. First, based on a comment made just now by Diniz about Papa-Terra. So you have some activity there of wells activity expected for next year. Can you comment on some kind of expectation regarding reserves certification? Because you also touched on that in the earnings release. That's number one. Second question would be for Matheus. Matheus, you visited Potiguar, I believe, in Q3 of last year. And I remember that you said that 2023 was a year still of adjustments to production, that some volatility could be expected. So you were kind of still mapping all of the assets acquired. So perhaps if you could look back and tell us about the lessons learned in 2023 and reconcile that with the outlook of growth for 2024, perhaps mentioning the main bottlenecks or some points of attention for the company in the next 12 months, that would be great. Thank you. Okay, let me tell you a little bit Papa-Terra. in terms of workovers, now we have production of about 13,000, and workovers are located in two areas, Wet Christmas Tree and TLWP. In the Wet Christmas Tree, we have a rig which is already operational at the field. It has exchanged the ESP in the third well. And the third well is expected to be completed by the end of next month. Regarding the TLWP, I mean, recall that in the past, in TLWP, we would have a rig coupled to it that had a high daily rate, and we were able to replace it and assemble a structure on the rig. With that, we started workovers Papa-Terra 17, more recently, just last week. This intervention will allow us to exchange this first ESP at the TLWP, which will make it quite easy for us to operate looking forward. So if there is any other ESP in the well that requires maintenance, we'll be able to exchange it. As for the reserves, we are in the final process of evaluating the reserves with a certifying body, and we expect that by the end of March, we should be communicating to the market our reserves. We are in the final stretch of the reserves analysis. Great, Diniz. Let me just make a quick comment before I turn the floor to Matheus. I'd like to remind you, Luiz, Papa-Terra is the asset where we have the lowest recovery factor. We've been stressing that quite a lot. That's where we have a huge capacity to allocate new wells. Both the FPSO and the TLWP have available slots, unlike old FPSOs or FPSOs which perhaps were not planned for the long run. Not the case in Papa-Terra. In Papa-Terra, it's the contrary. We have capacity available for allocation of new slots available for processing, for storage. Of course, all of that in parallel to the intense work that we do to recover integrity. But here, we have a great potential. Now, not necessarily all of that will be available in a first certification, but when we look at the long run, we see Papa-Terra with a great capacity to replenish the reserves of the company in the mid to long term. I'll turn the floor to Matheus. Hello, Luiz. Good afternoon. And thank you for the questions. Well, when I mentioned those adjustments, well, these adjustments, and I believe we have said that quite a few times, they're adjustments considering the context of the deals, the represented assets that would not be the core of attention for the old operator. So we always require some time that involves a lot of maintenance projects for existing things as well as new projects where we need to prepare the surface from the standpoint of systems and equipment so that we can have an increment of production. All companies, especially ours, in this niche of business of revitalization, of working with mature fields, well, we are basically project-based companies. In that regard, what we have observed internally, a timeframe of 12 months, perhaps 18 months, is what is needed for us to accommodate maintenance projects of existing systems and equipment. Then we start preparing projects to be the base of increasing production. So we basically have to expand capacity, expand oil treatment, expand the tank farm in the upstream before we move to more elaborate treatment in the production chain. Now, having said that, and I believe that the context in which I said that is kind of this one, but in addition to that, we can reflect a little on the challenges we have to achieve the production expectation this year. We already have some lessons learned from other assets. But now, we're getting into another phase as a company. Now, we are in a phase where we operate our portfolio 100%. We already know about the challenges. I'm not going to get into every asset, but from a macro standpoint, one of the challenges is what I've just mentioned. In our portfolio of projects, we have numerous projects to exchange equipment, replace equipment, and to increase production. So that's challenge number one because it kind of depends a little on the market, the supply chain, and the process of installation, commissioning, etc. So the first challenge is always related to timing. Although we try to fast-track projects, we end up investing in more equipment, spare equipment for risk management, and trying to bring forward a lot of projects. Also, in terms of stocks of projects for the coming quarters, it becomes a challenge. We have a lot of projects in our portfolio. And that's why we normally say we need a year to a year and a half to kind of balance the growth demand that we propose. We have other challenges. Another challenge we normally talk about, considering not only onshore but also offshore, is licensing environment for drilling. For all of the workovers, we already have approval. To give you an idea, this year, we are going to carry out more than 1,000 workovers onshore. In offshore, three workovers are being carried out. If there is any need in a well that hasn't been operating for longer, we already have approval for the workover. But on the drilling side, indeed, I'm not sure this is a challenge because it doesn't really depend on us. But on our end, we just have to do the diligence, work closely with the authorities, and have a diligent approach regarding what's submitted to the authorities. Papa-Terra, we have a license for two wells. One is very simple, which is the one we plan to drill this year. A little simpler than a new well, as I mentioned. But I mean, it's something that we need to work closely with IBAMA. That's how we work, actually. And in the other two states, in the other two basins, Rio Grande do Norte and Bahia, we have a timeframe, a schedule with the authorities so that we can have regular packages of wells to be drilled. We are in a kind of slightly comfortable position, not too comfortable, but we have five drilling rigs already. Two completing mobilization and final assembly to start operating in Bahia and three in Rio Grande do Norte, in Macau and Areia Branca. And another one in Rio Grande do Norte, which we consider a premium area. Regarding workovers, we continue at a strong pace with carried out more than 200 interventions, workovers, pullings, and reactivations, a little more than we had planned, 194 that were planned until February. As you see, we continue with a strong pace and full swing. In a nutshell, I believe that the main challenges, one of them involves licensing. The other one, the amount of projects. That's for any company, but we do have a lot of projects. We normally carry out many projects at the same time. In 2023, we were successful, which was reflected in significant organic growth. At the end of the day, we see more workovers. But again, we have the major challenge, the programs that don't rely on depend 100% on us, programs that depend on the supply chain, on the logistics chain of equipment, on the installation of these pieces of equipment, the amount of projects we have given the assets that we have in the portfolio and the fact that we work with everything at the same time. If we look at the assets that we've been operating for longer, such as Macau and others, where we are beyond this phase, well, these assets are a lot more constant. So I guess these are the main challenges from a macro point of Papa-Terra, Pizarro, and Diniz have spoken a lot about them in Rio Grande do Norte, the most recent. We do have some challenges, but these have been addressed by projects. There is a part which is steam generation. It's not really a challenge, but it's kind of a different treatment. We have acquired the generators. We're in the process of installing those. Canto do Amaro, which is slightly different. It's a matter of water management and treatment. We already have projects for water injection and water disposal already addressed. One starts in this quarter. That's the one for water disposal. There is another project in the mid-run for water injection, which increases pressure and releases a lot of the pent-up production. I believe that these are the main macro and one-time-off challenges for this year. If it gets into another business unit in mid-downstream, a good part of the challenges were addressed. Implemented some projects that were truly fast-tracked. We resumed the nominal capacity of the refinery. We resumed the processing ability of our NGPU. There's a project which is underway, which involves a lot of engineering, not just because of the flows, but also because of the schedule, which is the tankage farm. We revitalized more than four tanks. We increased capacity a lot. But this is ongoing work. A tank will become operational. The other one will be undergoing maintenance. So we have a lot of operational research to be doing here in terms of the mid-downstream engineering. In terms of the business, I believe we have addressed most of the challenges in the mid-downstream with a contract through which we protect 50% of our production coming from the refinery. The rest will have to spread the difference between the Brent and the price of oil products, which are more constant and related regarding the Brent for bunker fuel, which was the heavy part. I'm not sure we can call this liability management, but this was a kind of hedge we created for this business unit because, as we've mentioned over and over, we want to remove complexity. The main business is to produce oil and gas. Of course, the whole structure brings a lot of advantages in terms of flexibility from the standpoint of independence and management of the production chain. It brings a lot. A lot of those, well, we don't want to have complexity in a business unit which does not deliver the same EBITDA margin as upstream. The challenges have been addressed. For upstream, month after month, we increase the EBITDA margin a little. I think that we're addressing the challenges quite well. Again, Luiz, thank you very much for the questions. May I add something quickly? In the latest calls, there was a concern about the team, the rigs, and our contract of maintenance Papa-Terra. so this is a challenge that existed but has been solved. I just want to mention this. There were topics of concern. Today, we have a team that consists of people from many origins. This brings a lot of flexibility to us coming from other suppliers, from other operators, from the market. And it is a team that knows not only Brazil but other areas of the world. And that makes things easier for us to contract rigs and other equipment. For For the rigs, we have one operating. We're operating with 19, 20 rigs and another five drilling rigs. And we don't find it difficult to contract these rigs. All of the contracts are ready and are in the process of mobilization for us to start working in the next quarter at the maintenance unit. All clear. Thank you very much. Our next question is from Gabriel Barra from Citi. Gabriel, your microphone is already on. Thank you. Thank you for taking my questions. I have two questions, but most of my issues have been answered. There are two important points. One relates to the refining aspect. You just managed to close a very important contract as part of liability management for the refinery. A lot was said about the offtake contract. That maybe this would merit a more extensive discussion in terms of the connection to the terminal. I don't know how much detail you can give us, but I would like to hear from you whether the discussion is over or whether you could tell us about the second or third steps related to Guamaré and if you could tell us also something about the margin because you talked about the bunker. So maybe this could be a reactor in terms of the refining aspect. So I would like to hear what could be expected in terms of the margins. The second aspect and probably revisiting one important thing about M&A, we are getting a lot of questions about the deal. One of the things that we've been talking to the market has to do with timing. I know you talked a little bit about timing, but I would like you to refer to production increase in the second half. I mean, as you said, great part of that increment, like 60,000, will come in the second half of the year. Maybe some of that could be anticipated. How do you fit that inside the company in terms of the outlook for increased production and what would be the amount of increase that would really benefit the company? How do you address this at the time when we are talking about M&As and an increase in production in a very relevant moment for the company? Thank you, Gabriel. I'll start with the second question, and then Matheus will answer the question about refining. In terms of M&A, we always say that we agree. I mean, not only we agree, but we also value the merits of the transaction. However, the base case of the company is we are as it is. Today, the company owns onshore and offshore assets. We do have an execution plan, which is very relevant, as Matheus mentioned. We also have many engineering projects underway. We also understand that our team, as Diniz said, is fully capable of operating onshore and offshore projects. So this is our basic plan that has been executed. I mean, the liability management, we didn't postpone it. We didn't stop, even though we received that letter suggesting that possible transaction. That was precisely because a transaction like that doesn't necessarily depend on our own will. It depends on a series of other factors. Everybody is working to converge into a common point. But it doesn't necessarily mean that this will certainly happen. We never lose sight of our growth outlook and constantly making strides towards improving lifting cost. Now I turn the floor over to Matheus to answer the question about the refining part. Gabriel, good afternoon. In terms of that industrial asset as a whole, because that involves the refinery and the terminal plus the gas treatment plant, that was just a first step. This partnership through a commercial contract to sell the product is always the first step. We often say that the ideal situation for us would be I mean, we do recognize the value that this has in the entire production chain, in independence, as I said. But we would like to remove the complexities. We don't want it to become an activity that would rely on a lot of our energy. Our view on top of that industrial asset has to do with what we produce and what third parties produce that we acquire or that we render some services. But our business focus is not to increase capillarity or to work in a very structured way with trading. So we always thought about removing the complexities. Any partnership with trading or a distributor, not only will add more value to the asset because it will look at geography in a much more encompassing way. This partnership could be a commercial partnership or also an equity partnership. In fact, this is what we are looking at. Pizarro, in the last slide of the presentation, said that we are pursuing this agenda where we will look for a potential M&A in the mid to downstream assets. The first step involved this commercial agreement. We understand that a second option would be to have a partnership on the equity side. We are still looking at the ideal format that could expand the partnership whereby we would be able to decrease complexity and turn that into almost like an EBITDA that works like clockwork. In this sense, a partnership would potentialize the value of the asset. And we will continue to pursue that, as I said before. Now, in terms of the refining margin, in fact, this brings more predictability given the fact that 50% is known. There is no spread variation. On the light side, we have lower, for instance, the difference between Brent and the oil product amounts in the blends. I mean, we are also looking at other products like MDO, which is the maritime diesel. We were able to reduce the mix, and that, in turn, increases the unit contribution margin of the product. Therefore, we've been doing some combinations. The EBITDA margin is single digit. We know that in that productive chain of oil and other commodities like mining, etc., in production, we may have like 50%, etc. Then when we migrate to something smaller distribution, it's something like 2%. This year, we're looking for something around 6%-7% of EBITDA margin for these activities, which for us is quite relevant considering our simple refining plant. Now we have more EBITDA visibility and deliver a margin of around 6%-7%. Again, thank you very much. Thank you. Next question from Rodrigo Almeida with Santander. Mr. Almeida, go ahead. Good afternoon, Matheus. Pizarro, Diniz, and the whole 3R Petroleum team would like to start congratulating you on the results which what you're aiming to build and have been building over the past few years. I have some follow-up questions. A lot of things have been said, but I'd like to go back to the M&A deal. I just want to try to get a sense from you regarding the potential scenario where you would keep your offshore assets. In an ideal world, if you had infinite money, you have 3R Offshore. What are you going to do? Will you accelerate investments? Do you have other interesting opportunities offshore? Because this is something we discussed. And you have inorganic growth possibilities. Thinking about a deleveraged scenario. So what do you imagine in a just offshore scenario? So that's my first point. And then Matheus spoke about equipment and availability of material. So two quick questions. First, regarding the ESPs Papa-Terra, what do you have in terms of amount? And if you accelerate investments Papa-Terra, more drilling, you will need to carry out workovers in the old wells. How can you accelerate given the amount of ESPs that you have? We've seen other companies in the past also using BCS pumps. So also about Potiguar and still on the rigs. How do the contracts work that you have for the rigs? And I'm thinking about renewal of contracts, how long you will keep the rigs. And I'm thinking about a possible competition for rented rigs. I think it would be interesting to have answers to these follow-up questions. Thank you. Thank you. I'll start with the first one. Actually, we always stress here that we have complementarity. In our case, having about 80% of our production from onshore assets and about 20% from offshore assets. So if the deal is successful, as we have been working to happen, 3R will then start owning assets in this new entity that we prefer to call NewCo Onshore in a more relevant way. We'll start having relevant assets in this NewCo Of fshore. So I mean, it's not like we'll keep offshore and they'll keep onshore. No, we're thinking globally here in creating a large onshore company which has financial numbers which are unbeatable compared with Latin America, a significant EBITDA, a lot of proved reserves, a lot of complementarity because we have assets in the same basins. So I don't need to speak about the potential of onshore. Working like clockwork with production increment, very much focused on having capacity to process water and simultaneously for drilling campaigns. This is onshore. This is what we've been developing. This is what other companies in the Brazilian onshore that acquired Petrobras assets are developing. So we're joining forces. It's about the best of both onshore and offshore so that together we can create this new onshore entity which has a lot of potential. As we stress, there's no defined structure, no governance, no exchange relationship defined. All of that will be discussed looking or taking into account the interests of all shareholders and always thinking about the long term. That's the onshore challenge. When we look at the offshore challenge, where we can grow, of course, there's organic growth already addressed. Both in Papa-Terra, as we have mentioned, very low recovery factor, wide possibility of connecting new wells without having to remove the prior wells we can produce 1,000 barrels. No problem. We have slots for that. So there's a lot of flexibility at Papa-Terra. Just looking at Papa-Terra Field. However, when we have a bird's-eye view of the basin in Rio de Janeiro, there are other nearby fields, some fields that have no production unit, some discoveries underway, some A and B concessions around it. Papa-Terra, given its processing capacity, which is very high, high storage capacity, and a lot of slots, is also an asset and an excellent candidate for tieback, tieback with other companies or assets we might acquire in the future. So I think Papa-Terra allows us to use a lot of creativity in our new business department and the creativity of geologists, geophysicists, and reservoir engineers, all their creativity to develop this in a healthy way. And as you put it yourself in Peroá, we have the Malombe project, which is a tieback. It's conceptual. Just next to it, there's a big discovery estimated by Petrobras with a production peak above 2 million cubic meters of gas daily. We have processing capacity for all that volume. We are here giving you more detail regardless of the merge coming through or not, but we've been detailing this tieback to accelerate not only with a strategy for peak production, but with a high production of around 900 or 1,000,000 cubic meters of gas daily that we can put into production using the whole Peroá infrastructure. If today the lifting cost of Peroá is at $6 approximately, if we bring more gas volume, the lifting cost may decline. Another important aspect, looking at offshore as being a part or not of the current entity, which now is a 3R, we always have to look at the long term. Brazil has its largest reserves located in the sea. So thinking about the longevity of the company, having a foot in offshore is always interesting. It's something that brings the capacity to replenish reserves. Other majors are positioned in mature fields along the Brazilian coast. So it is not hard to have divestment processes. Some divestment processes are already underway close Papa-Terra, again, stressing the possibility that we can use the same facilities or share services, share rigs, emergency vessels. So there are some possibilities. And lastly, I'd like to remind you that in offshore, a number of companies have arrived with the divestment of Petrobras. I don't need to mention any names, but there are at least seven companies that come to mind, independent companies that have between 5 and 30,000 barrels of production. So there might be a consolidation process for offshore companies. It's something that makes sense in Brazil. And 3R, having this foot in offshore, can be a great candidate to enjoy this consolidation process. I think we have a full plate in front of us, both onshore and offshore. 3R has a full plate on both sides. If we segregate the companies into two, I think the best of onshore will go to one. The best of offshore will go to the other. But both sides have the same focus on organic and inorganic growth, particularly in offshore. Now, moving to the second question, Matheus. I'll answer and Diniz can complement. Rodrigo, again, good afternoon. Again, I'll start with the rigs before I speak about Papa-Terra. Our contract, just to give you an idea, as we mentioned earlier, we have five contracted drilling rigs onshore, 15 workover rigs, 10 in Rio Grande do Norte, five in Bahia of workover reactivation and conversion rigs, and four pulling rigs in the onshore industry. In offshore, we have two rigs. A DP is sitting next to the FPSO for the subsea wells. On the TLWP, we have a rig, as Pizarro mentioned, which is much simpler, a hydraulic rig, which is a lot simpler, a lot cheaper with a much lower unit cost compared to the DP. They end up working in parallel and carrying out simultaneous workovers. In the onshore scene, we have contracts that on average have a maturity of three years and are renewable. So part of them have been renewed. Some getting close to the end will communicate the partners about our demand. We are quite comfortable regarding market movements, demand oscillations, and supply oscillations because these contracts have some risk management involved, not just regarding market oscillations because we can renew them, but also regarding the timeframe, the timeframe we believe is very coherent with any movement, demand, or even licenses we haven't obtained yet. Today, working with 24 onshore rigs, all of them with on average 24-month contracts. On one hand, it's what Pizarro mentioned. If we have a de-hedged Brent and we need to control CapEx, we have some contract maturities that are flexible with penalties that are quite symbolic compared to offshore. Offshore, it's very hard to reduce CapEx. But in our contracts onshore, we do have that ability. At the same time, the rig contracts can be renewed at the end of every period and with great facility. Considering our CapEx program and planning, we will certainly be renewing them at least one more time considering a program of five-year CapEx. More specifically Papa-Terra equipment, a good part of the more structuring equipment such as the pumps which are replaced, well, they were acquired during the transition between the signing and the closing way before. And considering, and this is the characteristic of the offshore market, the lead time that we have for equipment which are a lot more engineered than in onshore. And the lead times are much more dilated for supply. So all of the pumps that are necessary for the next two years, not just for workovers, but for drilling as well, we already have those pumps. They were contracted even before the closing, actually six months before the closing. We already have these rigs already sized according to the size of the well. They're very specific. They were contracted way before, and we already have them. So we're very sure that if another pump fails, we already have a replacement. And this has a reflection not only in the pumps. Of course, we have a certain level of spare pumps. We don't want to flood our inventory. But considering the main equipment, where the supply lead time is more extensive because they're more engineered, we have a lot of warehousing or inventory management, is what Diniz calls preparedness for the main risks, the main equipment, and for production increment, we are quite sure about the equipment we acquired during the transition. Perfect. Let me just add regarding the onshore rigs, the timeframe of two to three y ears of every contract, but they were not signed at the same time. So every time, every month, we have rigs ending the contract or starting a new contract. So we have a lot of flexibility. Another point is that we have contracts with Brazilian companies, which, by the way, have re-energized the rig market in Brazil. But we have the rig that is going to be drilling soon is coming from Colombia. We have rigs coming from Mexico, Argentina. So given that our team is very knowledgeable about Latin America, it's quite easy for us to obtain the rigs from many locations. In terms of the BCS, in addition to the new pumps in Mossoró, we have an internal workshop. So if the market has a supply issue, we can service our pumps. And we also have a test well as part of our Mossoró base where we can test the BCS pumps for maintenance reasons. So we have great flexibility in terms of equipment as well, in addition to the contracts. And if I may ask a follow-up question regarding commercialization Papa-Terra oil, how's this advancing? How's your plan moving forward? Well, you all knew the track record. A good part that was limiting us from accessing the international market was linked to a tankage limitation when we took over the asset. Now we're a lot more comfortable. Now we can form lots or batches for the international market. So our strategy today since last year has been to transform this into shorter contracts so that we can have tender offers in the market more frequently so we can start our tests. At this moment, we have a contract that will remain in effect until the mid of the year contract with Petrobras. That was a first initiative in the market with shorter timeframes and that the market could test again. Petrobras continued as our partner, of course, with a contract condition much better than what we had in the beginning. I'll let you remind you, post-closing, we started with a discount of $20 that was reduced to $17, then $14. Now we are working with a discount of $12.40. And we are now in another tender offer to the market. It is possible we'll continue with Petrobras. It's possible we'll sell through another trading company or other refineries abroad. But we pursue reductions in this discount, in other words, improved discounts. We understand that we can still reduce the discount by $2, potentially $3, considering an oil comparable to this one that is trading in much better conditions. But of course, this is something we build with every short-term contract that we release in the market. And this is an oil that needs to be better known by refineries abroad. And of course, this will lead to an improvement discount curve as refineries will know the oil better, they'll know how to allocate the oil in the refineries. So ideally, what we expect, our expectation is that a discount of -$9 is feasible. We have improved a lot. We are at $12.41, way different than last year. And we consider with this strategy of having shorter-term contracts so that we can improve this discount even more for the company. And thank you very much. Excellent. Thank you. Our next question is from Pedro Soares from BTG Pactual. Pedro, your microphone is enabled. Good afternoon, everyone. I have two questions. My first question is another follow-up on Papa-Terra. It's very clear what is expected for the wells' workovers. I would just like to confirm whether the drilling of well 52 will occur after the July maintenance stoppage. And about the workovers, could we believe that this would also only happen in the hot workovers, or we should expect some interruption in production, and what would be the level of that? My second question is about the production curve of 3R as a whole for the period beyond 2024. I think that if I utilize the parameters you mentioned, about 51,000 for average production this year and then a Brent comparison of what has been certified in the reserves, can I assume that this adjustment should be done proportionally for the following years or not? I think that's it. Thank you. Pedro, thank you for your Papa-Terra, drilling Papa-Terra 52 depends on the environmental license. So there is no correlation with the maintenance activities of the unit. So as soon as the license is issued, and given the fact that we have a rig window because the rig is working with the old workover, but as soon as the workover is over, we can start doing the commissioning or the drilling. Therefore, we are making great efforts in an attempt to be very diligent, as Matheus said, so that we can start drilling as soon as possible. As soon as that drilling is concluded, the well will be ready for production. But looking at the schedule, certainly, the well will start after the flotel, which is the floating maintenance unit that is coupled with the FPSO. This floating unit spends between 90-120 days conducting maintenance. And they have hot services, which are the rigs, and we have to stop the unit for about two weeks, as Diniz said during the presentation. However, in the other 90 or 105 days, which is the time that the unit is adjacent to that, production continues with no impact. The advantage is that even though we stop for two weeks in the third quarter, probably efficiency resumes at a very high level. Therefore, the impact is not that relevant because the other wells would have been in operation throughout the third quarter. It is in the fourth quarter that we'll see a combination of factors. I mean, the unit with high efficiency, renewed pumps or ESPs, and new pumps with less than a year in use. Now, about the reserve certifications. In 2023, first of all, there was a delay in the Potiguar closing, and that was due to external reasons. We came here prepared for closing in the best-case scenario in January and the worst-case scenario in March. For those of you who look at 3R very closely, we spent six months working very hard to have all of the conditions precedent in place with everything ready. We re-evaluated the agreements to see whether there was any way to cancel that sale contract or not. So all of these things delayed the entry of 3R in the Potiguar Cluster. And this also delayed our CapEx plan. So in terms of Potiguar, we started at a lower degree, at a lower level. I mean, the last months of operation of the prior operator meant that they didn't make any investments, zero CapEx, and OpEx was just the minimum required. Therefore, we had to do some additional work when we resumed that well. The same thing happened with Papa-Terra. So certification impact occurs in the current year, 2024, and in 2025. Of course, there will be a little bit of carryover. But after all, the curve moves a year ahead. But this year-on-year, this will reduce the curve. We will have the 2P reserves depending on Brent costs throughout the year. But starting this year, the reserve certification will be very close to our internal plan because there is no closing. We have full visibility of the CapEx plan costs, OpEx. Therefore, that comparison between reserve certification and our business model becomes much more clear. And so we do not expect any major differences in terms of volume or NPV. The difference will be on the B rent curve, but the capacity to extract reserves from the basins has been preserved. We see great potential. There is a sentence from one of our investors because he usually says that, "Fortunately, the problems we have are on the surface. We have problems Papa-Terra because we received that with a lot of restrictions." On the other hand, in the reservoir, the surprises are quite positive. That's why we are very optimistic because we will be able to maintain a very competitive CapEx profile, lower than most Latin American companies, meaning that we will be very efficient and have reserves with greater profitability. Right? Thank you. That's very clear, Pizarro. I'm reading the questions in the Q&A, and I think that 90% of the questions have been answered. But there is one about dividends, whether the company will pay dividends related to the year 2023. As we close the year with net income over BRL 400 million, if we get the recovery of the tax loss accumulated in prior years from the entity that we acquired in the past, Ouro Preto Oil and Gas, we use the tax loss, and then we have the 25%, which will be suggested for dividend payout in the next ordinary shareholders meeting in April 25th. We'll have the general shareholders meeting. So during that meeting, we will suggest us, seen in our income statements, to pay dividends of BRL 93 million for the company. I think this is it. And well, I think that we can close this call. I'm going to make just some brief final comments, then I'll turn the floor to Matheus and Diniz. We had a year, as we mentioned, of hard work along 2023. We had many challenges: liability management, closing of Potiguar, start of Papa-Terra with all the restrictions and difficulties we mentioned. So this was a year when we had to hire people. As Diniz mentioned, we were able to put together a team of stars in each one of our operations in Potiguar, in Bahia, in Espírito Santo, in Papa-Terra. And all of those, we have highly skilled people from several nationalities and origins, former Petrobras employees, former service providers, former operators. And today, we are quite convinced that the company is much more well-prepared than we were in the beginning of 2023. So building this organic growth plan in our base of assets, which is excellent with integration, with midstream, with logistics capabilities that can export oil, can import oil by-products, can sell via cabotage to Bahia, as we did in the month of December. So in other words, we have a full plate to implement this organic growth in a sustainable, efficient way. I'd like to remind you that it's not just enough to look at the lifting costs. We have to look at all the cost lines to compare the companies. Combining all of these factors, we have all of the pillars in place to implement organic growth, relevant organic growth in 2024, and subsequently to deploy the growth plan of the company. So Matheus... Well, for starters, thank you very much. I'd like to thank all of you for listening to us, for attending this conference call, and listening to our results. A brief reflection in line with what Pizarro mentioned. I believe that a little over a year ago, when there was a significant change in the management of the company, we always said that what we were going to pursue for the company was that this was a company with a great focus on M&A, that we needed to cross the bridge. We needed to become a company whose core is to revitalize mature fields. And for that, we basically needed two things. We needed to structure the company a little bit in terms of personnel, people. So that was the first aspect, having the right people in the right positions. And secondly, have a maturity of processes because this is a company that is investment-heavy, investment-intensive. It needed to be systematized. And looking at the last 12 months and what we actually managed to deliver in the last year, I believe that the company as a whole in terms of people management, management, maturity of processes, and systematization, we evolved significantly. Of course, we're not going to stop here. As Pizarro said, our base case is to continue to focus on projects, on delivering what we are saying we are going to deliver, and pursuing an annual average production and get to December with our expected production. For that, we continue with a lot of focus on the base case of the company. But now we're in a different position because we believe the processes are a lot more robust in terms of people. I'd like to stress this. We have a team of stars, managers, coordinators, supervisors, engineers, our back office, all top-notch people. I would like to publicly thank everyone at 3R. And again, thank you very much for your patience with us. I think that we went way beyond the time allotted for this call. Quickly to end, I'd like to reinforce our principles and values at 3R. Safety is our number one strong principle. Ethics, it's something we pursue all the time. Credibility, I think that's also an important point. We did not come here to promise the things. We haven't done this in recent quarters. But what we've said, what we've said is what we've delivered. We have an excellent team. Our operational team is 24 hours a day working hard, operating our units with safety, respect for the environment, and respect for people. So that is a point that I wanted to highlight. We have a very important support team in all of the areas of the company. So I'd like to stress our message. We will continue to pursue our targets, our values, and we'll definitely have a 2024 even better than 2023. Thank you very much. Thank you, everyone. Thank you, and have a great rest of the day.