All right. I'm told that our webcast is now live. Thank you to those of you who are joining us online today. We've had an early start on our end, ad we're happy to have you participate in what we hope will be a really informative and interesting day for you. My name is Brent Anderson, and I am the Director of Investor Relations for Frontera. It gives me great pleasure to introduce Frontera's chairman, Mr. Gabriel De Alba, who will provide introductory remarks and an overview of Frontera. In addition to his duties as our chairman since Frontera's restructuring, Gabriel is currently the Chairman of the Board of Directors of Therapure Biopharma, Gateway Casinos & Entertainment, and Co-chairman of the Board of Directors of Cirque du Soleil. Gabriel is also a director and co-chairman of CGX Energy. I'm hoping, Gabriel, you can hear us okay. Thank you, Gabriel. Over to you. I think you may be muted. Just check your mic there and sound on your side. Yeah. Can you hear me now? Sí, señor. Gracias. That's great. Give me just one second. I think you needed to unmute me. All right. Can you hear me now? Brent, can you hear me? Yes, we can hear you. Okay, perfect. Thank you, Brent, and good morning to everyone, and welcome to Frontera's 2022 Investor Open House. You will hear a lot about Frontera today and our position as a leading oil and gas producer in Latin America. What we hope you will take away from our presentations is the unique investment opportunity that Frontera represents and our commitment to creating and delivering shareholder value. I have been chairman of Frontera since 2016, following a successful restructuring of the business. Since that time, we have made a tremendous amount of progress in focusing the company's operations and reducing costs, optimizing the portfolio, applying financial sophistication, simplifying our story, and returning significant capital directly to shareholders. It's been a big effort actually, you know, from the board and management during the past several years. One of the main objectives of this presentation is to outline to you the value creation drivers that Frontera is unlocking. As you know, today, Frontera is involved in the exploration, development, production, transportation, storage, and sale of oil and natural gas in South America, including related but actually separate value-creating businesses in upstream and midstream facilities. Frontera has a diversified portfolio of assets with interest in 32 exploration and production blocks in Colombia, Ecuador, and Guyana, and pipeline and port facilities in Colombia. We will want to emphasize in this discussion the E&P business in Colombia and Ecuador, separate the presentation of value from the pipeline and the port facilities, and then also give you a different framework of value on a standalone basis for Guyana. This is how we want. to unlock the value as we believe the sum of the parts is not currently recognized in the share price. In the context of performance, we recently announced our third quarter earnings, and I would like to take you through some of those highlights. As we reported, the company generated $173.2 million of EBITDA for the quarter and almost $500 million of EBITDA year to date for the first nine months of 2022. Frontera produced 41,033 barrels per day in the third quarter and has averaged 41,238 barrels per day year to date to the end of the third quarter. We remain on track to deliver on our 2022 production guidance of between 41,000 and 43,000 barrels per day, and we're again online as we are performing in the fourth quarter. Also importantly, we are delivering in our production and EBITDA targets so far this year while controlling our operational costs. As just mentioned, we are on target on production, we are on target on EBITDA, and we're doing this not only because of higher prices and again, solid production, but also because we are improving and reducing our operating costs. This is done even though there have been inflationary pressures coming in the market. In the context of the shareholders, year to date, the company has also returned $83 million through its SIB and NCIB share buyback programs, and the company has, in this process, acquired and retired over 8.5 million shares. The results for this year underscore the company's continued focus on cash flow generation, operational excellence, and unlocking value for shareholders while preserving a solid balance sheet. I would like to emphasize that in this journey of shareholder value creation, the board and management have been consistent, working hard throughout the years. We are focusing on driving excellence and accountability, and that has been our key mantra on execution. While higher oil prices are helping us, we are always conscious of preserving a solid production base, as well as maintaining a cost structure and balance sheet that will make the company sustainable in the long run. Before I turn things to Orlando, I would like to take you to some reasons why we believe Frontera is an attractive investment. With that, if we can please move to slide 11. Perfect, thank you. We have a proven and diverse asset base with longevity that generated value focused production and cash flow from our portfolio. As I have mentioned, in 2022 we maintained production guidance of between 41,000 and 43,000 barrels per day, and we currently have 2P net reserves of 167 million barrels. While we have not provided any guidance on 2022 reserves or the replacement ratio targets for 2022, the company aims to replace 100% of its production year-over-year. As an example, which will be discussed in detail later as it relates to our expectations for 2022 reserves. In 2021, Frontera delivered solid reserve results. We replaced 157% of net 1P reserves and 105% of net 2P reserves, and extended our net 1P reserve life index to 8.7 years, and our net 2P reserve life index to 13.3 years. We increased net 2P natural gas and associated natural gas liquid reserves by 105% to 19.1 million barrels. Further diversifying Frontera's future production mix and increasing the net present value at a 10% discount of the company's 2P reserves by 61% to $3.036 billion before tax and, as of December 31, 2021. Let me confirm the number. $3.036 billion. This is due in part to higher Brent prices year-over-year and greater operational and development cost stability. We have an advantaged transportation and logistics structure, which provides optionality to consolidate, blend and manage how we sell and produce crude. This increases the reliability and maximizes the realized price. Frontera has a unique business model, which again, is unique in the Colombian market for crude oil commercialization and trading that provides a significant differential compared to other producers. This is highlighted by an integrated transportation and trading team that is focused on optimizing price and cost. Frontera's commercialization model eliminates intermediaries, increasing wellhead prices, and improves trading margins, which we'll discuss in detail later in the presentation. We have strong growth potential through lower risk near field onshore exploration opportunities. In Colombia, we have 252 million-503 million barrels of mean prospective resources across eight blocks in the Lower Magdalena Valley and Llanos Basin. We have significant asset value and dividend income stream from our midstream portfolio, again, coming from the pipeline and the port, and high impact Guyana exploration. In September 2022, the company acquired the remaining 40.07% interest it did not already own in Pipeline Investment Ltd. The transaction represents an important milestone for the company as it increased Frontera's direct investments in the ODL pipeline to 35%. This strengthens the Frontera's midstream cash flow and creates a self-sustaining and growing midstream business. In other words, the midstream business, considering the pipeline and the port, can now stand on its own without any dependence from the Frontera upstream business. We believe again, this is a very important milestone to unlock value. On Guyana, earlier this year, Frontera and CGX announced the discovery of 228 ft of net pay across the Maastrichtian, Campanian, Santonian, and Coniacian horizons for the Wei-1 exploration well offshore Guyana. Tertiary analysis indicate the presence of light oil in the Santonian and Coniacian, and gas condensate in the Maastrichtian and Campanian areas. The findings are consistent with discoveries reported by other operators adjacent to the Corentyne block, and further derisk equivalent oil targets anticipated in the Wei-1 exploration well. The company is committed to delivering maximum return to shareholders via unlocking value from existing portfolio, resolving contingencies, and simplifying the story. Over the course of the last few years, we have cleaned up our operating portfolio and JVs to be squarely focused in production that can deliver value on a per barrel basis. We have also reduced a number of contingent liabilities and freed up restricted cash. We have also taken steps to solidify our ownership positions in our infrastructure assets to give us the ability to drive value from them in the normal course and maintain our ability to unlock the value from them in the future as standalone businesses. Much more discussion on these valuable assets will be also presented today. Over the last five years, Frontera has returned over $290 million of shareholder capital through normal course issuer bids, substantial issuer bids, and dividends. We can't control the share price, but we have fundamentally focused on unlocking the value of the business by generating significant income that benefit the shareholders through performance. As mentioned, we are also working very hard to unlock the value from the sum of the parts which we believe are not recognized in our current share price. We will talk about this also in a moment. Developing a strong and integrated ESG platform that guides our operations is also important for the board and management. In 2020, Frontera redefined its sustainability commitments, focusing on environmental, social, and governance factors in 2021. The company established new ESG goals that are revised annually, and we started to measure our ESG progress on a consistent basis, seeking to improve permanently our ESG performance. Our team will walk you through the details in the recognition we have received today. We are very proud of the ESG leadership and the commitment that our board, management, and team have to this important evolution in governance, transparency, and equality. If we can please move to slide 12. As I noted earlier, returning capital to shareholders is a big part of our investment thesis. As a fellow shareholder, it is important that the company do all it can to deliver against its operational priorities and drive margins, delivering strong free cash flow as a key focus. We have an opportunity to look at the free cash flow and determine our CapEx needs and consider available liquidity to create direct shareholder returns while preserving a strong balance sheet. As you can see, since 2018, even when oil prices were not as robust as they are now, we have been able to return substantial capital to shareholders. In 2020, we bought back 83.6 million of our shares through our NCIB and our SIB programs. We will continue to evaluate the size and scope of our capital return programs, but it's important to highlight that it is a key point of discussion every quarter between the board and management. Going to slide 13. A little bit of framework of how we look at our share price. When we look at our share price, we continue to believe that there is substantial upside with more clearly defined assets, a track record of performance, and increased liquidity that has been created over the years. We believe the ability and the opportunity that Frontera provides is very attractive. You will do a tremendous amount of work in your investment process, and we will want to provide you some highlights emphasizing the three main buckets of value creation: our E&P assets, our midstream, ports, and pipeline assets, as well as Guyana. I would like to highlight some points for your consideration. When we look at our valuation, we look at three distinct components. First, Frontera generates strong value-focused production, cash flow, and reserves from our upstream business. Frontera 2021 2P reserves have an NPV10 after-tax value of $2.25 billion, and the company anticipates generating between $675 million and $700 million of EBITDA this year. Frontera's enterprise value to EBITDA is low at 1.8x, and our enterprise value to barrel per day is $23,000 per barrel. Again, we think that's actually low. Second, we have a growing cash flow positive midstream business comprised of Puerto Bahía, which generates between $15 million and $20 million of EBITDA per year, and our 35% interest in ODL, which generates $200 million in EBITDA per year. In the case of Puerto Bahía, I mean, the business is performing extremely well with the wet port basically operating at close to full capacity. Our focus is to increase the velocity of volumes of the business, especially by looking into partnership with other operators. We're working very hard to figure out ways to again improve the velocity through synergistic partnerships and connections with our partners in the market. In the case of the pipeline, we are actually pleased that its you know utilization is actually growing, and it continues to be a key asset in distribution for the Colombian ecosystem. Actually, we believe that that will remain throughout the years. We are you know very happy with how the business is performing, and we see the sustainability of $200 million in EBITDA in the future. Talking about CGX, Frontera will hold 93% consolidated interest in CGX following the completion of our joint venture agreement amendment. Just as a point of reference, CGX market cap is approximately $200 million. We're giving here some reference points on how we believe the business is not recognized by the sum of the parts. We believe that our E&P business is undervalued. We believe that the recognition of the value of our port midstream assets, including the pipeline, is also not reflected on our share price. By the way, when the analysis is done and the research reports get written on our balance sheet, it includes the debt from the port, but we're not getting any value of what would be the standalone value of our midstream assets. Actually, our ratios include the consolidation of all of the port debt. Again, on CGX, as a pure reference, we're looking at the market cap of the company. We believe, actually we're working very hard to unlock that optionality with further successful exploration results that the team is focused on. In short, we believe that we present a very compelling investment opportunity with a strong upside potential for our shareholders. Moving to slide 14. Our success would not be possible without the deep experience and local knowledge of our team. Frontera now has the best team it has had in years. The professionals assembled to lead F are some of the most experienced in leading a large Latin resource company. Led by Orlando Cabrales Segovia, our CEO, the team is uniquely positioned to operate Frontera, drive our exploration, to engage with customers, and maximize value in the capital markets. I can only emphasize the great commitment that they have to the shareholders and its work focus on unlocking value. We have a great team that is committed to delivering to the shareholders and to all of our stakeholders. With that, I would like to turn the presentation over to Orlando. Orlando? Hello. Can you hear me? Okay, good. Thank you. Thank you, Gabriel. Thank you very much for that introduction. Thank you to you for coming and joining us today in this Investors Day. Let me start by saying that in addition to the management team that Gabriel presented, we have also, I mean, many members of our management team here with us to be throughout the day and take your questions. I also need to say that in addition to the members of the management team that you saw in the slide, we have speakers today, Regan Palsgrove, who is our head of exploration. She's going to do the Guyana piece. We have Rodrigo Torras, who is our new CEO of Puerto Bahía. Welcome, Rodrigo. He's going to talk about Puerto Bahía. And Andrés Sarmiento, who is our director for sustainability and corporate affairs, who is going to talk about ESG. Let me start by making some remarks about the oil and gas industry, particularly in Colombia, but there is also a comparison with a country where we are operating as it is Ecuador. The message here, the main message here is that Colombia oil and gas industry is still very important, very relevant for the health of the Colombian economy. These are some figures that I want to show here, which are not totally consistent with what Luis Fernando presented, because when Luis Fernando presented the mining figures, he include the coal, the coal and the rest of the mining sector. These figures only include the oil and gas sector. You can see here the importance of the oil and gas sector, particularly oil here. This year, the oil sector represents 36% of the Colombian exports. I mean, that is a lot. About 9% maybe this year more than the foreign direct investment coming into the country. In terms of oil revenue as a percentage of the GDP of the country, oil and gas represents 2.6%. Luis Fernando was showing like more than 3%, which includes coal. That is an important part of the GDP. If you assess the oil revenues and the participation of the oil revenues in the total income of the central government this year, it could be around 15%, between 15% and 20%. No. It's not the majority of the revenue, but it's a significant part of the revenue. No. Between 15% and 20% of the central government income. That excludes the royalties that goes to the producing areas in the country. You can see Ecuador participation of the sector in the oil revenues of Ecuador is 4.4%, so it's significantly higher than in Colombia. The total oil production by country, Colombia is still, I mean, still relevant, 738%. That is an increase from previous year in production. Ecuador is 473%. So those are the two countries that are relevant for our conversation. Here, the total 1P oil reserves, that means that Colombia still needs something because this 1P, 2P could be 2.8 2P. That gives around seven, eight years of self-sufficiency for the country. Like the country has to do much more to expand that self-sufficiency, and investment is an important part of that equation. Again, the message here is that the oil and gas sector is still very relevant for the Colombian economy and for the economy in Ecuador. This is, I mean, this is the, as Gabriel used a word which I like, is the mantra. The mantra of the Frontera's management team, board of directors and the whole organization. This is our mantra. The first mantra that we have is something that we have been discussing over the last two years, which I have been CEO of this company, is our mantra of value over volumes, of increasing reserves, generating cash flow for our shareholders. That is the mantra. When you talk about value over volumes, we are talking about basically three things. One is that we are prioritizing the assets with the highest returns and the short payback cycles. That is number one. You know, that is where we are focusing our efforts and our investment. We are adding reserves by very targeted exploration opportunities. We are going to talk about that today. We are also carrying out acquisition opportunities and divestment opportunities, as we did with PetroSud like a year ago, as we did with ODL. Those are the three parts, the three components of our mantra of value over volumes. The second one is how to be more efficient, to try to bring cost reductions into the system, into the operations and the production of the company. That is something that we do every day. We have several initiatives in the company that help us to bring those efficiencies. We have several initiatives. One of them, which I like a lot, is Frontera Eficiente. Paula is here, the head, the leader of that. Where we really extract from the bottom up initiatives, cost reduction initiatives throughout the whole organization. Every year we have a very significant target of cost reductions in OpEx, in CapEx, in transportation. Every year, we have very, very aggressive targets to bring further efficiencies, further cost reduction, further optimization into our operations. That includes not only the production part, but also the transportation, the logistics side of the company. That is an important part and a very important component of our focus, of our driver, of our mantra. You know, the cost component. The other one is to create a self-sustaining midstream business going forward. You know, that is also a very important, significant part of our efforts here. We have this acquisition of ODL, which is a great acquisition. It's an EBITDA of $200 million, dividends for our 35% participation of around $40 million per year. The system is great. There is more production coming online in that system, production coming from our peers, from Ecopetrol. That is a great acquisition that we did, and that helped us to make, again, a self-sustaining business. One. What was the price that you paid for the stake in ODL recently relative to the dividends that you're expecting to see next year? The acquisition price you paid for the recent stake inmillion ODL and relative to the dividends you're expecting to see for that three-year period. The dividends historically have been between $30 million -$40 million. That's more like $35 million, $36 million. Like 1.5x the current rate? 1.5 x EBITDA. Okay. In addition to ODL, we have Puerto Bahía. I will let Rodrigo expand on Puerto Bahía. But as you will see in Rodrigo's presentation, we have been able to increase volumes and EBITDA in Puerto Bahía in the last year. We are making Puerto Bahía less dependent on Frontera. You know, we had a take or pay for Frontera that finished this year. We have been able to increase the revenues in Puerto Bahía to make Puerto Bahía less dependent on Frontera and to continue looking into opportunities and increase the potential, the upside that we see in Puerto Bahía, which is a great asset. Actually, we are looking, and we can expand that on the Q&As, but we are looking into some opportunity to bring a partner on the dry terminal side of Puerto Bahía to expand the containers business and to expand that part of the business in Puerto Bahía. It's an EBITDA between $15 million and $20 million. This year, that is the range. Next year, talking to Rodrigo, we should be closer to $20 million for next year. But as you can see in Rodrigo presentation, we have been able to increase the volumes and the business in Puerto Bahía over the last year. We are also advancing the company's exploration portfolio, which is basically near-field portfolio, near-field exploration portfolio. Victor is going to expand on that. One example of that we have been successful in doing is that this year we had a discovery. At the end of last year, we had a discovery in Ecuador. By mid-year, six months afterwards, we had 3,000 barrels of oil production gross in the country. Those are the type of opportunities, exploration opportunity, near field opportunities that we can monetize quickly nearby to the infrastructure, to the existing infrastructure and to existing fields that we can monetize very quickly. That's also part of the focus here. As Gabriel said, we have returned more than $290 million over the last five years to shareholders through dividends and share buybacks. Andrés Sarmiento is going to expand that, but we have been, I mean, having clear metrics to measure the ESG performance of the company. One thing which I would like to highlight there in that section, and Andrés Palacios, who is our director of HSEQ is here, is that in the third quarter of this year, as we announced it, we had the best safety performance of the company since Frontera's existence. That is a major achievement. Because for me, safety is one of the best, if not the best measure to reflect the quality of an operation. No? That is the best way to measure the quality of an operation. We have been doing that. That is of course a credit to not only Andres, but to the whole team, to the operations team. You know, safety is not only a performance made by the HSEQ team, but the whole organization. We have been able to embed the safety culture throughout the organization. We should do better every quarter on that front. This is also an indication of, and Gabriel touched on this, but this is an indication of what value over volumes means. As you can see here, the Our full cycle cost and how our full cycle cost have been decreasing over the last years. It's a $7 per barrel decrease over the last years. It's a 15% decrease over the last year. That is again a reflection of what we have been doing to try to bring efficiencies into the system. That is an important part. This year we are, I mean, somehow is flat, but to be honest, I do feel that it is a major achievement this year to keep flat costs over last year with the significant inflationary pressure that we are having this year. No? That is a major achievement from my perspective, to be able to keep flat the full cycle cost of the operation. This one here shows the netback, the operating netback of the company, how that has been increasing over the last years and the significant cash flow generation that we have achieved over the last couple of years. Now, that is another part of the value over volumes, no? Prioritizing the highest returns barrels, but also adding reserves. This is, I mean, a very good story. Very good story because, first of all, we have been able to increase the 2P reserves of the company, no? In the last three to four years, from 155 to 167. No? That is number one. Number two, we have increased by 60 million barrels of oil equivalent our gas reserves, no? Particularly coming from those liquids-rich natural gas fields like VIM-1. That is an important part which, because we have been able to diversify, not only to grow the reserves, but also to diversify the reserves by adding more gas reserves. The other thing which is very important, we are going to highlight that a lot today, is that we have increased by 7 million barrels the heavy oil reserves coming from CPE-6. Other than Quifa. You know, Quifa has been our main field for years. We have been doing many things in Quifa. We are going to expand that in Ivan's presentation on how we are managing the decline and actually increasing the production in Quifa by increasing our water injection capacity. This shows how in heavy oil, we have increased by 7 million barrels of oil equivalent, the CPE-6 reserves, which is a great story. I'm going to emphasize that in a moment. The other thing is that we have increased the reserve life index in the 2P to 13 years. That has doubled the reserve life index of the company in the last five years. As Gabriel said, the reserves replacement ratio has also been above 100%. That is the target that any oil and gas company try to achieve every year, to be above 100%. Going forward, what we are going to see going forward is that with the exploration portfolio that we have in the company, and again, Victor is going to expand on that, we are seeing that the driving force of reserve addition going forward is going to be exploration. That is why our exploration portfolio is so important. It's so important. I'm going to let Victor to talk about that, to expand on it, but we have identified in our portfolio, again, near field portfolio, over 500 million barrels of prospective resources. When you risk that number, that could be between 59 million and 111 million barrels over the next three, four years, and that depends on the success exploration rate of the company. The lowest number being a success exploration rate of around 30%, the highest number of about 70%. Victor is going to show how we have been very successful, above 70%, in our exploration efforts over the last years. More on that. Of course, Guyana is, as you know, an important part of that. Regan is going to expand on that. The good thing is that the most recent discoveries that Exxon has announced are getting closer to where we are, you know. Regan is going to expand on that. This has been a journey of Frontera to unlock value for all of you. You know? Where we like to characterize it as the first years as the recovery phase. You know, the recovery phase, which is again, cost reduction. I have addressed that already. Reducing in a significant way the contingent liabilities of the company. As you know, we were able last year to settle the Bicentenario dispute, which eliminate more than $1 billion of contingent liability for the company. We are still optimizing our exploration commitments. We have been reducing actually our exploration commitments, optimizing, focusing on what really creates value for our shareholders. Last year, which was a perfect timing, last year, we were able to do the bond refinancing of the notes that were expiring this year. That was the perfect timing for the company to do that. But now we are getting into the growth phase, 2021 and beyond, to develop that potential upside that Gabriel was talking about. Which is by doing the M&A consolidation with ODL, Puerto Bahía, Petro Sud, to have that value over volumes. That is the reason why we exited Peru. Have more production for the sake of having more production doesn't make sense. Value over volumes is the mantra here. More than 10 years of the reserve life index. Growth opportunities in Ecuador, Guyana, and, as I said, a near field exploration portfolio of more than 500 million barrels of oil equivalent of prospective resources. On the growth, the 550 million prospective barrels, where is that coming from? That is the more than 500 million is Colombia and Ecuador. To finish here with this note, I would like to highlight a couple of things here. One is what we are seeing today with the portfolio that we have today is that we are in the trajectory of reaching 50,000+ barrels of oil equivalent per day in 2024. So what you are seeing here is that this is the base, what we call the base and the exploration upside. The base is mainly Quifa being able to increase the water disposal volumes up to 2 million barrels per day. Ivan is going to talk about that. Increasing CPE-6 drilling facilities and facility expansion in CPE-6. Today we have a capacity of 120,000 barrels of water injection capacity today, 120,000. We are planning in the following couple of years to get to 480,000. That is basically based on the results that we had this year in the wells of CPE-6. Production in CPE-6 has been better, much better than what we expected for the year, and the results of those wells make us comfortable to have that facility expansion up to 480,000. Infield drilling in Cajúa and in Quifa. Those things with the technology pilots that we are implementing, particularly in Quifa, we are going to sustain the base next year and increasing in 2024. The increase in 2024 is basically driven by the expansion in the facility of CPE-6, which are going to be ready by next year, by the end of next year, as well as the SAARA/ Agrocascada project, also by the end of this year. That will put us in 2024. Exploration activities are coming from VIM-1, which is the Parex-operated field. Also Hamaca, which is CPE-6, we have identified exploration opportunities in the north part of the field. Victor is going to talk about that. Also appraisal opportunities in the south part of the field. Also Ecuador. Ecuador provides additional upside from an exploration perspective. Those are the exploration activities, exploration upside that we are seeing for the following years. This my remarks. Again, I mean, most of these remarks are going to be expanded by the team here, and looking forward to questions by the end of the day. I think, Ivan, I think you are next? Thank you. Christine, do you have a question? Yeah. I just had a question about your growth projection. Do you think that you can achieve this with your current service contracts, or do you think you're gonna need to be bringing in more rigs? Sorry, just so I can repeat it for the webcast, for those listening in, the question broadly is, do we think we can achieve our growth forecasts with our existing contracts, or do we need to bring in additional rig capacity? I think. Do you want to take that one? Yeah. Yeah. Sure. Thank you. Good morning, and thank you for the question, and for the welcome too. Well, yes, of course, we need to increase our drilling campaigns in both CPE-6 and Quifa. Also we need to have more resources to achieve these numbers that we are projecting in the coming years. One of the most important investments we are going to tackle in the CPE-6 and Quifa blocks are the facilities. I'm going to talk a little bit about this for the coming years in both fields. Yes, we need to increase our services to drill more wells. Of course, we need to. Okay. Well, good morning, everyone. I'm going to touch base on our operations base. Basically, I'm going to refer to the light blue bars that Orlando just presented to us, and Victor is talking about the upside and the opportunities we have on the exploration side for the company. Well, firstly, I would like to refer to the base of resources we have in the company. We have, as of today, 31 contracts or blocks signed off in three different countries as Gabriel and Orlando pointed out before. Out of those 31 contracts, we have 16 blocks under production. That means that our resource base for growing and opportunities in the future for exploration is half of our blocks of portfolio that we still have to keep developing the company to the future. Today we are focusing on these 16 blocks. Most of them are. Yes? Does that mean that 15 blocks are exploration licenses not held by production? Not all of them, some of them. We are in some blocks, and I will refer later on in my presentation, that some blocks have today production, but they have interesting exploration upsides. Even in traditional blocks that we are facing our base of operations. Okay? Well, we have again these blocks, 31 in three different countries. Our base is Colombia. We have 28 blocks located in Colombia. But the interesting that we have in Colombia is we are located all over Colombia, in the most prolific basins that we have as production in country. We have our resources in the best basins in Colombia. I'm going to refer later to this. We have all of these participations. We have a very interesting thing that probably Renata is going to talk about, is how they are connected because we have synergies between blocks. Despite we have long distances between some of them, we have synergies between the blocks. Recently, we have entered into Ecuador. I will refer later on to this. We have two blocks in Ecuador. As of today, we have a very good results, and I will refer later to that. Of course, still have opportunities to grow, not only in Colombia but also in Ecuador and Guyana. We are going to talk later through Victor and Regan, who are going to talk about this. Okay. As I mentioned before, we are located basically in Colombia and Ecuador. Our reserve base and production base are pretty much in line. 55% of our reserves are producing about 55% of our production today, so we are developing the fields in line with the resources we have. Basically, we have the base of our production belongs to four different, well, 16 blocks, but five out of them produce the majority of the production for Frontera. I will talk a little bit about where we are. We are focused on the Meta Department, which is today the most producer in Colombia. We have three blocks here, and the major producers are located in Meta. We have Quifa, CPE-6, and we have also Guatiquía. Those three blocks are located in the Meta Department, which is again the most producer oil in Colombia today. The other fields are located in the Llanos area. We are producing most likely the light oils and medium oils are produced in the Llanos area. They are spread all over the Casanare and basically Casanare department. We have in Colombia the gas and extra light oil that we are producing today, which is in the Lower Magdalena Valley basin, where we traditionally used to have La Creciente. We also have two interesting new blocks in the company, which is VIM-1, which I'll refer later on. The recent acquisition that we had on the El Dificil field and El Dificil block that we acquired one year ago, as Orlando pointed out. This is our geography in Colombia, and now we will move to Ecuador. Also in Ecuador, our two blocks are located in the hot spots of the oil fields in Ecuador. Remember, Ecuador has a very good track record in production, but also in reserves. Those two blocks were the product of the signing of two recent blocks in the first Intracampos round that Ecuador launched in 2018. This is very interesting. I will refer a little bit on how we have been performing in Ecuador as of today. Pretty much here, our reserve base is pretty much in line with the production today. We are expecting to develop more in the new assets that are coming in our portfolio, such as CPE-6, VIM-1, La Belleza, and other opportunities that we are going to talk a little bit about later. This is our production performance for the last two years. Difficult times. The pandemic times were really, really tough for the oil companies in Colombia. We were not the exception. The most important that I wanted to share with you is we are returning the increasing in our production, just as Orlando pointed out before. We are in the right way to reach these 50,000 barrels of oil targets that we have for the coming years. We have been recovering the production. As of today, we have increased 10% our production year-over-year, 2021 versus 2022. I'm proud to let you know that today we are back into 43,000 barrels of oil a day. We are in that way, and we are expecting to keep growing our production, per our plans, that I will share with you in the coming slides. Yes? What percentage of your associated gas are you able to market? Well, today our gas production is around 10% of the total production, the equivalent, and it is all marketed. They are coming basically from the assets that we, that I showed you before in the north coast of Colombia. Okay? Yeah, this is an indicator, not only liquids, but also gas. Well, we have recovered this trend. Most importantly, that Orlando showed before, despite the fact that we are facing not only a high commodity price, but also a high inflation environment, we have been able to sustain the production cost in low levels. Not only the production, but the full cycle, production for the company in lower levels than the ones we had in 2019, despite of that. This is because of discipline. We have been focusing on discipline for taking care of the resources, for taking care of the initiatives, and also for optimizing all the time every process we have in our facilities and in our processes. That's why we have been successful growing production but sustaining the costs that we are. This is our base today. Here we have some challenges that I will share with you a little bit in some fields, basically in the heavy oil assets. Yes? Do you have any production type curves to share or? Not at this point. This is just a zoom on the last two years, but I will refer us to some blocks, the major producers and how they are performing today. Okay. Well, now I'm going to walk through the base of resources. This is Quifa. This is our major oil producer today. It's a heavy oil field. Quifa still have a big amount of reserves and resources within the block. We still have nine years to go in the block. We are the operator. I will walk through a little bit in this presentation to Quifa because tomorrow we are visiting to the field and I will prefer to show you in field how we do the production and how we have been performing in better details. Just to let you know about Quifa. Sorry. About Quifa, well, this is a field that has been producing for 13 years now. Yes, 13 now. Which has been focused on developing the structure on the southeast. This structure on the southwest. Sorry, this is the same structure that is located in this portion of the Meta Department. We have Rubiales as neighbor, and also we have Caño Sur here. It's the same trend on the oil accumulation in the subsoil, so that we have been focusing on developing this. Remember where Rubiales were the first discovery in this area, and then came Quifa, and then came Caño Sur and CPE-6 as new developments and new opportunities in the area. We are going to be visiting both CPE-6 and Quifa tomorrow. Importantly to mention in Quifa is the acreage we still have. We have around 140,000 acres for this block, and we have been, as I mentioned, focusing on this. But we also have one field, which is called Cajúa, where we are producing around 3,000 barrels of oil a day today gross. In total, we are producing from Quifa and Cajúa like 28,000 barrels of oil a day, and 60% of that production belongs to Frontera. This is our participating share in this contract. The challenges Orlando mentioned, the mantra I will mention, I wouldn't say this is the karma, but this is our challenge, is the water. This is how we have been developing all the barrels we have in these blocks. If you see, this is like a track record on the water disposal in Quifa that has been. We got a challenge during pandemic 'cause we shut in some wells because we need to be economic. Some of these wells at the lower price that we used to transact in 2020 were not economic, so we decided to shut in some wells. Yes? What is the water cut on Quifa? 98%. 98%. Yeah. When you expanded your capacity, it was because that was the bottleneck, increased production as a result? Yes. Today, yes. This is the driver on the development of the field. It's not a bottleneck, it's a driver. The more water we have to we manage, the more oil we can produce. Okay? Iván, sorry to interrupt. Can you repeat the question just so the people on the webcast can also hear? Okay. No. Thanks. The question was if the water capacity was the bottleneck that we have in Quifa. My answer was yes, not the bottleneck, but the driver we need to develop. We need to increase our facilities in water management so that we can produce more oil. Okay? After the shutting of these wells, some of them increased the pressure after we resumed them back. We need to find a different alternative to dispose the water. In 2021, we started drilling different locations of water disposal. We started spreading the water disposal capacity in Quifa. We drilled two wells in 2021, and we drilled one more well in 2022, so that's we started increasing our water disposal capacity. This is the opportunity we are preparing the block or the field to continue the growth on production in the coming years. We have, for instance, for this year, we are also expecting to increase today. Sorry, before talking about this. Today, we are managing about 1.5 million barrels of water again. This is basically the same water level that we were managing before pandemic. We were able to recover those volumes of water. Of course, we are recovering the oil too. Just to build on the question on the water ratio, it's important to mention that per every 100,000 barrels of water management, we are able to produce 2,000 barrels of oil gross. This is the importance that we have in why we need to manage more and more water every time. Considering this and taking into account that we still have good resources and good reserves in Quifa, we have developed a plan for the coming years, which includes drilling more water disposal wells, at least one next year. This is the new thing that we are including into the equation, which is going to be Agrocascada or SAARA project. We are visiting that tomorrow too. Sorry? Yes. This might be too far in the weeds in terms of reservoir management, but since the field is now, you know, 13 years on production, do you have older wells that can be converted now into injection wells or those old original wells are continuing to be productive? Yes. The answer is yes, we can do that. However, we need to take into account where the wells are located because the facilities to reinject the water, they need to be in synergy with the disposal of waters. But also those wells that are shut-in are going to provide oil. Today it's closed, but once we have more water capacity, we are going to be open to open the wells, the wells that are shut-in today for that purpose. They can be used for both production or disposal. Okay, going back to this forecasting, we are expecting one of the most important projects that we have today is Agrocascada or SAARA, and we are visiting that tomorrow in field. Agrocascada is or SAARA; we have renamed the project. SAARA is a water treatment plant that will allow us to treat the water to dispose into a palm oil plantation. This is the project of SAARA. We are here in battery four. We produce and separate or treat primarily the water coming out from the wells, and then we are going to transport water here into SAARA. SAARA is a reverse osmosis plant. It is a very well-known technology that the only purpose that is going to help us with is to improve the quality of the water so that water can go to a plantation. Okay? Even though the quality of our water today is good enough, because of the environmental license we have, we need to get it better. This is what we are expecting SAARA to do, to improve the water quality. Then we are going to pump the water from SAARA to the palm plantation. The palm plantation is ProAgrollanos, a 100% controlled company by Frontera. We have about 3,000 hectares of plants today. This plantation has about 8 years producing. But we are expecting with this water is not only help the oil production in Quifa, but also the more volume of water received that by the plantation is going to increase the palm oil production. We are expecting also to have an important impact on the production of the palm oil. It's this is a project which has very different benefits. It will help us to manage the water from Quifa. It will help us to grow the production on the palm oil trees. More importantly, this is one of our ESG projects that we are going to reveal later. Andres is going to talk a little bit about this. This is not only a technology solution but also a sustainable issue. Sorry. Yes. Two questions. Can you explain to us a little bit about where the permits in this this project? And second, is there any risk related to the government or the tax in this project? Okay, thank you for the question. The permits that we have, we need different permits. There are two questions coming here. One is, what are the permits we need for the project to run? And secondly is if the government may take any other action regarding the project in the future, right? Okay. To answer the first question is the project requires different permissions. The first is from the oil field, which we have. We have already the permission to pour the water into a plantation. Of course, working through a process that permits but assures that the quality of the water is going to be in the right quality to get into the plantation. There is one permit, it is ready. The second permit is in SAARA itself. SAARA has the permit to receive the water and to deliver the water to a third party, in this case, to the plantation. This permit is also in line. There is a, not a permit, but an agreement that we have since the SAARA or the Agrocascada project is located in Rubiales field, physically. We signed off an agreement with the operator for this field in order to use the facilities for SAARA to accomplish the purpose of this project. Those permits are required, and those permits are in line, and we don't have any, I would say, not risk, but any issue regarding the permitting on the project itself. The second one is if the government may take anything regarding the plantation. Well, I couldn't answer that, but I don't. I wouldn't say that this is something that may go against this. Most importantly, because this project, the plantation, is going to oversee it. Once the oil fields are gone, that remains in time. This is a long-term project for the company. Not for the company, but for the region. Okay? Yeah. Fine with that? What I think is going to be the ESG impact of this project, right? This is a very creative way of taking water, repurpose that water, 'cause remember, that water is coming from the ground. It's already impacted by oil. Clean that water and repurposing it for our use, that creates a circular clean economy. We'll talk about the ESG concepts of that in the future. One quick additional thing, Ivan, is that the operator for Rubiales is Ecopetrol. We managed to achieve this agreement with Ecopetrol to be able to activate Agrocascada, SAARA, as it is called today. Which is an important part, no? Because that shows, I mean, the credibility and the trust that we have gained with Ecopetrol over the last years to be able to do these type of things, no? Thank you, René and Orlando. Yes, of course, important mention about Ecopetrol because he's not only the operator for the block, but he's also our partner in Quifa. This is something that has facilitated to work through this option for the field. All right. Sorry. Before going to that, I will come back to this slide. We are expecting to have to grow in two or three different stages in SAARA. Once we are expecting to start by the end of this year. You will be able to see tomorrow how advanced we are. We are expecting to start with the first 50,000 barrels of water treatment this year by late second half of December, late this year. Once we do all these adjustments, 'cause we need to adjust all the operation, the operational part. In parallel, we are expecting to build and to grow the plantation. The plantation or the SAARA itself. Today, the nameplate is about 1 million barrels of water treatment, but the connectivity with Quifa does not allow today to treat all of those volumes of water. We need to build new pipes, and we need to connect Quifa with the major volume that is available today by SAARA. This construction is to be in the coming years, in 2023 and a portion in 2024, so that we can increase the water disposal or transportation capacity from Quifa to SAARA and then the treatment from SAARA to ProAgrollanos. This is one of the drivers that we are going to have to increase the production in Quifa in the coming years. In other words, once we have 1.8 million-2 million barrels of water management and water disposal capacity, we are going to be able to increase our oil production, which is part of the story to rise our production back to 50,000 barrels of oil a day. The second-largest field that we have is Guatiquía. It's a field that today is producing around 9,000 barrels of oil a day. We don't have a partner here. It's 100% working interest for Frontera. This is one of the traditional fields that we have. We have been developing this. We have different fields in this block. Four fields actually. The original field that we discovered the first time was Candelilla, light oil. The second one was Avispa and Ardilla, the second field discovered in this block. We moved to Yatay, which is the third discovery that we have and the third field that we have within the same block. The most recent discovery and development that we have in this block is Coralillo. Coralillo is in the southeast of this block. We found good resources in three different formations in this part of the block. Today, for instance, Coralillo produces around 30% of the total production for the block, which is an important portion. We still have some opportunities here in this area for the rest of the year. As a matter of fact, in 2023, we are planning to drill two more wells in the sweet spot. One interesting thing that we got this year was that in some wells we drilled, we found extra heavy oil, which is not in our base. This is not in our production base, but this is something that is challenging us so that we can find the best way to produce or to put this on surface. Extra heavy is around 7-8 API, so we need to do something different in the block. This is something that we are studying with technology. We are studying that with the resources that we have today to produce this sort of oil. This is something that we are not talking today, and we are not considering today for the equation for the coming years. This is something that could be an upside for us. Repeat. Sorry? Repeat reserve. Yeah. Our third major field is CPE-6 today, but we are expecting CPE-6 to be the new jewel from Frontera. We discovered this field about 10 years ago, and we have discovered this is our field that we have named Hamaca. The whole block is this CPE-6 that has a lot of resources, and Victor will develop that a little bit on his speech. What is interesting to mention is the same trend of production that we have in Quifa is the one that we have here in CPE-6. In other words, we need to increase our water management capacity so that we can produce the oil that we have in reserves. Very important, CPE-6 is our top second field in reserves today. We have a big amount of reserves from this block and 20 years of contract to develop these reserves. This is something that we are focusing on developing for the next years, and I will elaborate a little bit more in some minutes. This is the production area again. Two more comments. We have some more upsides in exploration, and Victor Vega will refer to that later on. This year, we are expecting to drill one well here in the north and one well here in the south, so we can start confirming these resources or to be coming into reserves. I will let Victor share with you that. This is the first point, and the second one is the acreage we have in CPE-6 is even bigger than the one we have in Quifa. The total area that we have here is still under, I wouldn't say exploration, but under opportunities for the company. This is how we have been moving our production. It's very important for you to know that this year we drilled 14 new wells. These 14 new wells brought us a lot of information, not only for production. Of course, it brought us a lot of barrels too. It brought us a lot of information. Those wells were drilled in the sweet spot here, and those wells allowed us to navigate better the reservoir. The complexities of this reservoir is higher than the one we have in Quifa, for instance, so that we need to have better information, quality information to develop the reserves. This drilling campaign this year provided us with very good information and will allow us to leverage the growth in CPE-6 that we are expecting to do in the coming years. Two more wells are expected to be drilled this year for exploration purposes. This is the production curve that we have in CPE-6 for the last years. If you see, we have been consistently growing this year. Not only the drilling was the driver for growing in production, but also, as Orlando pointed out, we grow our facilities from 60,000 barrels of water a day to 120,000. We double. This year, we are expecting to get the approval, and I think this is something that is going to happen soon, the multiyear expansion on the CPE-6, meaning that we are raising our capacities up to 480,000 barrels of water a day. Of course, this will allow us to raise production in CPE-6 up to 10,000 barrels, which is double production that we have today, okay? This is something that we are working really hard, and we are expecting to bring these barrels into the tanks in the coming two years. This is... I'm just talking about the Hamaca resources we have here. I'm not including potential upsides that we may find in the future in the surroundings of the block. This is something that could be an exciting block to keep looking at. Does this include information that you got from the 14 wells that you drilled? Sorry? Does this include information that you got from the 14 wells that you drilled this year? Yes. The information was here in this portion, in the sweet spot, and this allow us to growth the development of the Hamaca field. To add to what Iván is saying is the 14 that you see there in green are the ones that are drilled this year. Two that we're gonna drill more. I'm gonna expand on that exploration and appraisal, as Iván mentioned. Those 14 will help you with the sweet spot, right? Then the other wedges that you see there on top of the graph that is shown in there are related to additional areas that you may be able to find. One of them is called a C7, which is a different level, stratigraphic level, to the one where we are producing today. Then the exploration wedge, and then what Ivan is also showing, which I'll expand on, is what else do we have outside of the block. I'll get into that in my presentation, and that way you'll hopefully get the whole picture. Thanik you, Victor. This is why CPE-6 again becomes a very important player for the portfolio at Frontera. Exciting blocks. I'm referring to VIM-1. VIM-1, more importantly, in CPE-6, we have no partnerships. I mean, we are 100% share for Frontera. In this block, in VIM-1, it's located in Lower Magdalena Valley, in the basin on the gas and the condensates are found. We have 50% of share. The operator here is Parex, our partner. We have been working with them with this block since 2019. As a matter of fact, we drilled the first well, the first successful well in 2020, which was La Belleza 1 well, which is located here in this area. This year, we completed the second well, which is La Belleza 2. This second well was completed two weeks ago, and we were able to manage from this well over 20 million standard cubic feet a day and about 2,800-3,000 barrels of condensate. The prospective and the production that we are expecting from these wells are very interesting, and I'm just referring to wellswell one or two wells. We remain with Parex to find new opportunities, not only in La Belleza structure, but also in some other structures that are located in the same block that Victor is referring to them later on his presentation. This is something that is bringing an increase in our production this year. Because of this new well, we are expecting to raise another barrels from here to the end of this year. This is something that excites us. The most important thing is a young area. We still have 20 or 22 years to go, firstly, and secondly, we still have acreage to keep looking for new resources and for new oil or gas. Importantly, from here, we are selling both from this block. We are selling the condensate, but also we are selling the gas. We are selling as compressed gas, which we compress in the field, transport to our field in El Dificil, decompress and pump through the gas line. Okay? This is something that brings this block not only more production, but also diversification on both condensate and gas. The last one today is Ecuador. Ecuador is, I mention always to Victor, a case study because we signed this contract in 2019. Some months later, we got into the pandemic situation, and we had to wait for almost one and a half year to get the licensing to start drilling. We got it in fourth quarter last year, 2021, and we drilled the first well in December last year. Completed and put it into production in January this year. Then we drilled two more wells. The three wells are producing today. We reached 3,000 barrels of oil gross production from these wells. That means that we have 100% success rate of exploration in this block, three out of three. Of course, we are trucking today all the production through Lago Agrio, which is pretty close to our field. Lago Agrio. Ecuador is not only a good country because of the resources they have, but also the facilities it has. I mean, we are pretty close to the electrical grid. We are 10 kilometers away from the pipelines, the major pipeline, both OCP and SOTE, which are the transportation system in Ecuador. The infrastructure that are surrounding the blocks are very complete. We still have some opportunities. We still have one well to be drilled as a commitment and some area also to keep discovering. Today, we are producing 2,600 barrels of oil a day. We don't have permanent facilities because we need to keep investigating, and we need to encounter the way to the reservoir is so we can have or plan the facilities we are going to have, definitive facilities to produce this. Today, we are working with the authorities in Ecuador to get the licensing for producing the field. Today, we have an exploration license which allows us to produce and to test the wells that we are testing today. We are expecting to have the license by the end of 2023 so that we can start building the final facilities in 2024 and growing, of course, the production from this field. In 2024, we are going to have the infrastructure and the delineation on the size on the prospects to develop the resources we have in Ecuador today, okay? In this block. The other block is under exploration. We finished the first well. The operator there is GeoPark, and one more hit, one out of one. The first well was also a success. The well is producing today, and we are drilling the second well in the second block. I wouldn't anticipate what Victor may share with you. Saying this is our presentation. More details will be provided tomorrow in our field visit. I prefer showing to you the reality from Frontera in the field, and we can discuss, if you want, deeper tomorrow. Key point, we have a diverse portfolio in all of our, not only in Colombia, but also in the region, Colombia, Ecuador, and then Guyana. This will become true in some years. Our base of resources, which is Quifa, Guatiquía, CPE-6, remains solid, but we are now talking about the new opportunities and the new portfolio that is becoming Frontera in the coming years. Adding CPE-6, VIM-1, Ecuador, which is the names that we are going to be focusing on the coming years to replace and to increase our production levels, as Orlando challenged to us this morning. Finally, of course, the structure is not only in production, but from this discipline on CapEx and OpEx and discipline on the finance, we have been able to generate the sufficient cash flow to fund the operation itself, the drilling of new facilities, the construction of new facilities to operate the fields, and also generate cash to the new opportunities, to the exploration in both Colombia and Ecuador, and also for Guyana. On top of that, we are generating the cash to return to our shareholders, as Gabriel pointed out in his presentation. Okay. That's it from my side. Thank you so much. I think the next stage is. We're gonna take a break, I think, till 11:15, if that's okay with everyone. We'll take a quick break. If we can have everybody back in here for 11:15. Thank you very much, Iván. Appreciate it. Thank you. Thank you. As close to the agenda as possible. Good morning, and welcome again to all of you to Colombia. My name is Victor Vega, and I'm responsible for exploration, also, field development and reservoir management and reserves. I have a couple of members of my team here with me. Three members actually. Andres Fajardo, who is the exploration manager for Ecuador and Colombia, Oscar Valbuena, who is the head of reserves. You also already met Regan, who is the head of exploration for Guyana. All of them are part of the organization. We are here today to present to you first Colombia and Ecuador, and then we'll have a separate section on Guyana because we know that's a pretty hot topic, and where we are probably gonna get a lot of conversation going on, so we are prepared for that. Basically, what I want to is Ivan already made the introduction in terms of the number of blocks that we have. Then what I want to take you is a step a little bit further and into more detail of the blocks itself and some of the excitement that we have around the portfolio that we currently have in our company. The first thing that you see is we looked at the five-year exploration strategy, and we talked about Colombia and Ecuador. We are going to talk about this in the way of a funnel. You probably are familiar with the funnel concept, which is very commonly used in exploration to mean more uncertainty to less uncertainty, right? You know, by the time that you book the reserve, then you need to have quite a bit of certainty. In the case of Colombia and Ecuador, we have basically very good ideas about how to progress from here to here. In the case of Guyana, we are here. We're still in the upper part of the funnel, and we'll be there for a while, so we'll show you some of that in a separate presentation. Basically, in this particular funnel, we go from prospective resources. This is basically what you have when you do a map, when you have some information, when you use analog data from different basins, and you say, "I think I have the same petroleum system. I say I have the same stratigraphic trap, the same trap that other people have, same reservoir or whatever." Right? You make an analogy. You have some information, and then you make a decision to actually go and drill a well because you have a prospect that has some prospectivity, right? That's at the upper part. Once you drill the well, and then you have actually tested that, you go to the next level, which is the expected discovered resources. Once you have that, and you are able to put that well on production, then you go to the certifier of the reserves, and you say, "Look, I now have done the well, I have seen production, and here is the proof that this is flowing. This is the type of hydrocarbon that I'm getting," and all of that. You go to a 2P, right? That's at the end. For that first part, you are only gonna get what is around the well, right? Because then you don't have enough information unless you do some long-term tests or something like that, where you can actually justify more than a certain drainage area around the well. All to explain that we are very excited that we have around 550 million barrels already, as it was discussed by Orlando. We mentioned that, you know, the lower or the upper range depends on the success rate that you assume, and we're gonna show you a table. We are using the low range when you go to a lower success rate and a high range or the high number if you go to a high success rate, right? Because you know that in exploration, very unlikely that you're gonna be 100%, right? Most of the companies actually have a 20%-25% success rate when you are doing well, right? 20%-25%, right? Below 20% is not so good, right? We have that. We also have the expected resources that range here from 74 to 139. We have the 2P. The 2P we divided into two, assuming a 32% average success. Our historic is 73, as I'm gonna explain in a minute. Basically, the 22, once we drill these wells and we are successful, some of them we have already done that, then we will go after this, which would be additional wells because we have an area. The first well will only certify a certain radius around that. You go with more activity, and you show that to a reserves auditor and then say, "Look, we have now a plan to develop this area." It's kind of like where we are in the Ecuador case, right? Where we have already done more than one well, so we are able to show to the auditor that we have actually more to come. Yeah? Now, this one shows you, I'll describe the graph first. You see the years, 2022 to 2026. You see the symbols. The symbol is if you have like a little tower, it's an exploration well. If you have like a sound wave, it's like seismic. CapEx if you have a bag of money. And then you have blue and green. Blue to indicate that is near field and frontier, green to mean that is frontier. And then what you see here is the portfolio divided into two pieces. One is for Colombia on the right-hand side and Ecuador on the left-hand side, right? You see the number of wells that are being drilled or activity that is being done, like seismic per year, right? You go from 2022 to 2023 to 2024 and so on, right? What you see there is that in our 2023, our focus, a lot of our focus is gonna be on the Lower Magdalena Basin, where we have acquired many blocks and where we have several blocks that were already presented by Ivan, but I'm going to get into more detail. In the next few slides, I'll expand on these blocks. Okay. We have Llanos, and then we have Ecuador. 2024, then as I said before, right, for example, this year we are drilling a well in La Creciente block, and this is one of the examples, right. If we are successful on that one, then we are gonna be drilling more wells because we have two other structures in the same block that we can follow to be drilling additional wells. In 2025, and then you see also in 2024, we also have a couple of blocks in Llanos where we are doing seismic. Next year, once we have the seismic, they will confirm, hopefully, the prospect, and they will go and drill the well to actually test the structure. You have Ecuador, we have more activity, and I'll explain again. In 2025, again, we have more activity. One of them that I want to highlight is VIM-46, which is a block that we acquired in the last bid round that the ANH has. On that one, we are focusing on the seismic now, and we are actually preparing to acquire the seismic sometime later next year. If we go now to the details, I'm gonna start with Colombia, and then I'm gonna go to Ecuador. You see here two areas. You see area A, which is the Lower Magdalena Basin, which is one of the key areas for us, where we have the blocks VIM-1, where Parex is the operator, VIM-22, 100%, where we are gonna drill three exploration wells. One of them is gonna be drilled in the early part of next year. We are preparing for the location and the road access and all of that. Two more wells back to back after that. That's one exciting block. The VIM-46 is where we are gonna do a seismic. La Creciente, we are right now drilling the well Magari-1. It's being drilled right now. It was spud last week, and we hope to have a result of that well by the end of this year. You have El Dificil block where we drill a couple of wells this year, and one of the wells we are going to hopefully complete by the end of this year. We are giving priority to the activity on the exploration side because we want to get that done this year. In the Llanos Basin, which is area B, you see here where the blocks are located, sorry, on area A. All of this is very close to existing infrastructure, right? Which is the other advantage that was pointed out in the introduction by Orlando, where basically we are saying one of the key characteristics of our portfolio is that near field. It will take very short time for us to actually get it. For example, in La Creciente, if Magarí is successful, we already have the facilities, and they're ready, waiting for the discovery. We can actually monetize very quickly. In the Llanos Basin, which is a more prolific but also more mature area, you see here where we have Quifa, you see also where you have CPE-6. This is to put things in context. This is where you're gonna go to the field tomorrow. We also have Sabanero. And then in here, we have two in yellow, which we added, which is Llanos 99 and Llanos 119. Again, like 119 is close to existing infrastructure. Llanos 99 is not too far. On those two, we are focusing on seismic, 3D seismic, which is the preview for the drilling of the wells. That's our portfolio in Colombia. This one, I'm gonna take it from the left to the right. It's a busy slide, but I'm trying to make the high points. First, the upper part, our onshore exploration success rate. We have listed there the successes and the failures. We have listed the discovered resources and the 2P reserves. The key points, and then we are showing 2019 to 2022, and the reason we put this slide together is to show you that the funnel that we put actually makes sense, right? That some of the assumptions that we are making make sense because, you know, we should show you know, how we have done so far in the last three years in exploration, right? We havixe 73% is what you see here. We have seen six wells in heavy oil, four in the medium, and one in gas and condensate, which is the VIM-1. We are listing here only the exploration wells, right? If you have subsequent wells that are not exploration anymore because they would be either appraisal or development, depending on the activity. What you see here is the success rate, the success cases, the failure cases, and then you see the discovered resources, which then are translated into the reserves, right? Depending on the information that you got from the well and how much that is representative of a particular area around the discovery well. Yeah? Okay. The bottom part is the incorporation of new acreage, because I think that's the other question that we have been getting from you guys. Many of our calls is, "What happens if we don't get any more licenses, right?" What we have here is we can see that we did an approach where we diversify by fluid type, basins, and countries. We participated in bid rounds. We also did one farm in VIM-1, and we also got some extensions. The other thing that you're gonna see in a minute is that we have also been focusing on the blocks that we have and around the blocks where we have, because that's also another way to get new areas, is you don't need to actually go into a bid round when you do that, and you can actually get an extension, and that's what we did in CPE-6. If you are successful in showing to the government that actually you have done the homework, right? That some of these plays that you have developed or discovered, you can expand in surrounding areas. That's another area that I want them to expand on. Then you see here the description, so I'm not gonna go into that. As a result of this strategy, five blocks in 2019, two in 2020, and 2021, three. This includes outside of Colombia, which in this case is Ecuador. Yeah. We go to the next slide, then we will start talking about a couple of examples. One is the VIM-1. You see this light blue outline here, which basically represents the La Belleza area. The way that I would try to characterize La Belleza is imagine if you were to look at a reef today, right? You were able to go scuba diving around the reef, and then you would see that this is a big reef, right? Which is where we have La Belleza. Okay? That's what we are trying to produce right now. We have two wells, one which was the original well, the second one, which is the well that we're gonna use to do injection to keep the pressure at the reservoir level, because these gas condensate reservoirs, if you don't maintain the pressure, then you get a black oil loss. You lose all the pressure, you lose also the ability to extract the liquids from this. We have the advantage here that we have pretty rich reservoir, so we can extract a lot of the liquids. That's what we have here. We have like the equivalent of a reef. We have a small one here, so it's another one that we have in our horizon. We have this one and then La Belleza, and then we have this one, which we have a code name internally, but it's a different one. On top of that, we have this area to the west, which is based on sands that are in the lows of these flanks of these high structures. You see it here, you see it here. These are like the lower areas where the sands have been deposited, and those are the areas that we're gonna be targeting in the future with two or three exploration wells that are planned for 2023, 2024. These areas are pretty significant, and those are included in the funnel that I mentioned to you before. Okay? That's La Belleza. The next one is CPE-6. CPE-6 is heavy oil, high water cut. Seismic, I show you here, seismic line that basically goes like the, in this orientation. And then what we are showing in here is that we have a big area here, which is Hamaca, and then we actually got an extension. This is one of the examples of the extension. In this one as well, in the one that I showed you before in VIM-1, takes a while to return sometimes. Yeah, here. We also got this is an extension as well. This part of this block. These are two of the examples of the extensions that I mentioned to you. This is like a new block that we were able to get via an extension. Okay? We didn't have to go through a bid round. We just have to show our technical case, the data that we got from the wells and all that. You have Hamaca, and then you have another complex here that we're gonna test, and then you have this well that is gonna be drilled. Actually, we're gonna start that well this week, we hope. With that, we will show hopefully confirm the extension of the play to the north, and then we have this oil structure. You see the size of this structure is pretty significant. That would be like another sweet spot if we are able to confirm that actually the play extends to the north. That's why we are really excited. What you saw in the wedges that Ivan showed you only refer mainly to the exploration around the block. If we have success on another sweet spot, then that would be a game changer because then that would be very, you know, a significant addition that we are not showing there in production yet because then we have to test it first, right? Okay? That's why we are looking at this. Then we put 480,000 or 500,000 by the end of next year, but then the intent is not to end there. We are putting modules in place so that we can grow in modules because we think that we actually are gonna have to go like to 600,000 or even more in the long term to be able to double the production in this area. Because as Ivan already mentioned, this is similar to Quifa, right? Where you need water management at the surface, ability to manage significant volumes to be able to deal with that. I think that's that block. Then Perico and Espejo. Two really exciting blocks for us. You see the other key thing that we mentioned switch for Asia well. This may be like a very simple question, but how do you define the success rate or the success? Is it just a mere discovery of oil, or is it conversion to the 2P reserves? If you can help us understand that. That's a good question. In this particular case, the way that we are showing in here is that we actually found a producing reservoir, and we were able actually to get it to production. Okay. You can find it describing different ways before by other people where they say geological success, right? But not commercial success. All of these are wells that actually were able to get into production, right? We did not include some of the, say, geological successes that we had because those obviously did not translate into barrels. These successes are when it's actually. Yeah, where it has gone to production. If you like, during the course of a fiscal year, if you find and, you know, have a successful well, does the 2P reserve increase on the next annual report or is that? Yeah. It depends, right? For example, right now Magarí, right? We are drilling Magarí, and we gave priority to Magarí over Difícil, say, Norte, which is a well that we need to put on production in the Dificil because we need to do certain activities before the end of the year for the auditor to be able to accept that actually it is something that we can put in the 2P category. We need to show him evidence that actually we were able to put the well on production, and then he will say, "Okay. Yeah, I feel comfortable then with certifying that these are 2P." That's why. You would do it the year that you have the information that is required by the auditor to certify you that this actually is gonna be a producible well. Thank you. Can I just maybe go back to the Espejo? Thanks. Going back to Perico and Espejo, just wanted to get some sense on the seismic acquisition because I think it's not fully covered. Yeah. Okay. Actually, it was the case in Espejo. In Espejo we actually had coverage on both areas, but the northern part was not very good seismic. It was decided as part of the bid that was put in place for acquiring this block, that 3D was gonna be done. The decision by the partnership was actually to focus on the northern part. That survey actually was completed and has been processed, and is being analyzed, and it will be used to drill a well next year. You will see that, once we talked about 2024, 2023 activity, but the plan that we have is to drill one well next year, which is gonna be focused on that part of the field based on the new information from the 3-D seismic that was acquired this year. I th ink Oriana, you had a question. Yeah. Hi, think maybe staying in the Ecuador side of operations, are there any conversations of a new bidding round? If so, is this close to where Perico and Espejo are and would be something that Frontera would be going after? Yeah. We are actually looking at the information, and we will be doing the evaluation of the blocks. There are six blocks, and they are distributed as being published by the government of Ecuador. Some of them are around these blocks, some of them are in different areas. We are doing the technical evaluation to confirm that actually the data room was actually open very recently, so we are still doing the evaluation, but we are in the process and we will actually see if it actually makes sense or not, right, to add more. But that's something that is underway. We have until February to submit or to decide to submit any kind of bid. We are in the early part of the process at the moment, but definitely looking at it. Okay. Okay. Thank you very much. Now I'm gonna pass it to Renata. Well, good morning, everyone. It's a pleasure to be here with you today. I hope you are gonna have a good days here in Bogotá even though it's raining. Let's see what happen today and tomorrow. My turn is to show how Frontera manages the transportation and marketing our production. Gabriel mentioned this morning that Frontera has an important advantage because of our transportation and logistics infrastructure. I will go deeper into it in order for you to understand how we do and why we have a unique commercialization and transportation model. Frontera has a unique commercialization and marketing model that give a competitive advantage among Colombian oil producer companies. Our strategy is supported by a well-integrated transportation and trading team, allowing the company to negotiate its crude and sell in different markets, complementing domestic sales in Colombia. The infrastructure that the company has, pipelines, storage, and blending facility, give us ample flexibility to handle our crude oil, obtaining better realized price compared to our competitors and creating value for the company instead of selling the barrels at the wellhead. This is very important to understand why we have this advantage. Frontera has become a key player in the market to sell Vasconia and other segregation at Puerto Bahía according to client needs. This has been the result of an ample, robust, well-known, and diversified client portfolio and daily market monitoring that helps Frontera to cope with the market volatility and the turmoil. Through the access to the crude oil gathering pipeline and storing infrastructure, we have minimized the crude oil handling risk because of diverse crude oil evacuation system to cope any potential risk. Also, this allow the company to handle or take advantage of any crude oil market changes. We can use the system to manufacture different crude oil segregations, adapting to any market change opportunity, like we did for CPE-6. CPE-6 is my favorite block right now because we can handle CPE-6, take it to Puerto Bahía, and we can blend any API. Even though it's a 10 API crude oil, we can blend to 12, we can blend 14 in order to make an asphalt segregation that is for asphalt market. Or also we can take there and blend to Vasconia. We have a different option to have the storage capacity in Puerto Bahía. Also, we can manufacture general purpose crude oil stream, produce a specialty crude oil blends, and also produce finished products like low sulfur and high sulfur for the bunker niche market. By combining the pipeline system plus Puerto Bahía storage capacity, we were able to take advantage of the contango crude oil market structure during the COVID-19. Low diluent naphtha prices when we buy the diluent this year because of the Russian and Ukrainian war, we got a very good price, and we had a contract because we have the storage in Puerto Bahía. We bought from June to January, and we got a good price for the diluent in for the national gasoline. It's important to say that up to September this year, Frontera realized price $1.42 compared to the market price. The result is that Frontera earned $11 million versus selling barrels at the wellhead. That's very important number that we get this year. That's up to September 2022. You're gonna see the fourth quarter is gonna be better. We continue to focus on cost reduction, delivering enhanced EBITDA by optimizing logistics and operation costs and increase revenues. Regarding this, we can say that we have a Frontera processing deal with Hidrocasanare Refinery. This is a small refinery in the nearby our fields, and we process some of our light and medium crude oil in order to get three products. Naphtha for dilution, fuel, it's a kind of diesel for power generation, and residual oil, residual fuel oil for bunker niche market. Actually, we do that. We are doing this because what we need is to get the diesel or the fuel number four that we use for power generation. The difference, in the past, we used to buy the diesel for the local market. The price is around $40 different if we do this compared with the local market, if we buy the diesel. That, for us, was a very power generation. Also for the dilution, because naphtha is inside the country, it's a cheaper way to import the national gasoline that we do through Puerto Bahía. This local refining process deals reduce operating costs, generate more than $6 million between savings and incomes, up to September 2022. Remember what happened in 2020. We closed the big conciliation for the litigation that we have with CENIT regarding the take or pay at Bicentenario and Caño Limón. We have two alternatives in the new contract. It was a new take or pay. It was 2,300 barrels per day. The one alternative was using the CENIT monobuoy in the terminal, in the maritime terminal in Coveñas. The other way was shipping the 2,300 barrels per day through the Bicentenario corridor. One of the advantages to reduce the usage of the Bicentenario because of the force majeure. We are now getting our export volume through the CENIT monobuoy. That gives us a very good advantage. Why? Because that monobuoy is almost exclusive for Frontera. We can forecast our windows before the pipeline system gives us the window. Like, our client portfolio is almost to direct refineries, and that is in the. As you know, the refinery, they schedule like three months in advance for their processes and the crude oil in their refinery. If we get advantage and get the windows before, we've taken advantage of the market and sell a better price. Given the exclusivity or almost exclusivity, because we are only the cheapest to export in this monobuoy, we can forecast the windows between 10 days, so we can go out to the market before everybody else. That is a good advantage and it has helped us to get a good price. You will see later on in the presentation that 50% of our production is delivered by truck. You are gonna see that, and we have a huge system to control that. Because the fields are not connected to the entry point of the pipeline. They are nearby the entry point, but we have to truck them to the pipeline. That was a project that we did with operation in order to reduce the time for the loading and unloading the crude oil in order to reduce the time, and that will give us better volume and more volume in the trucks, and the cost will be reduced also. Okay, let's talk about commercialization. In 2022, the Russian-Ukrainian war, the U.S., and. The U.S. Strategic Petroleum Reserve crude oil release caused to us a change of the typical crude oil flows. If you see in 2021, most of our crude oil was going to Asia. Right now, because Asia got the crude oil from Russia because of the sanctions and because also Russia sells with a huge discount price. We lost the Asian market. We got now the U.S. West Coast market, and also now we are getting to the US Gulf Coast. That is why we have changed our portfolio, I mean, our cargos to go to different clients. There is another thing that is important to say is we sell our volume as a Vasconia. A Vasconia is a 23 API, is 1.2 sulfur. Normally is we relate this Vasconia with Mars swaps. If you see in the beginning of the year, in 2021, Vasconia was very related to Mars. Because of the crude oil that's coming from Canada to the U.S. Gulf, the Mars differential has been ample, and that is why we don't sell related to Mars. We sell related less. If you are gonna see in fourth quarter, we had a beautiful price because we sell to the West Coast. Most of our crude oil went to the West Coast, and that is related to the Alaska North Slope. That's a part of what we are doing monitoring the market because we try to see where the Vasconia will get the better price. Okay. Let's talk about CPE-6. CPE-6 is why we believe that CPE-6 will is a beautiful block and why we think that the. For me, that's the maybe because I have a refinery hat. CPE-6 is a beautiful crude oil. Has asphalt and also has a lubes specialty yields. CPE-6, we sold in July and September cargos from Puerto Valle. Small cargos went to asphalt refinery, and we got around $3 better than Castilla. Remember, Castilla is 18 API, and we sold Llanos blend at 14 API. Llanos blend is we have to blend to up to 800 centistoke because Puerto Valle and also the vessel cannot handle it, lower viscosity in the for this crude oil. We have to blend it up to 800 centistoke. It's around 14 API. That specialty crude oil is the better netback that the company has today. That's why, when we do the economics to increase production and do this the big project that we are planning for 2023, is because it's a good netback. That is because we are finding a new niche market for this crude oil. There is another one. It's Ecuador. Ecuador now, as Iván said, we are transporting the crude oil from the field to the SOTE, that is the Petroecuador pipeline by truck and after it sells as an Oriente segregation. Because of the small volume that we have in Ecuador, we have to go through the clients that Petroecuador has, and we go on top of their cargos. It has been very difficult to sell the Oriente, but we are getting there. We normally do tender with FI, the FI company that has contract with Petroecuador, and we are selling the crude oil at a market price also. Okay. Let's now talk about transportation. If you see on the map, Colombia has a lot of flexibility in pipelines. We have flexibility because we can get into the pipeline at different entry points. We have some rights, but also we have capacity in ODL as a take-and-pay contract, so we don't need. Because the Colombian production has been reduced, we have capacity. Everybody has capacity. When you have rights, you have like the first priority in the nomination. That's a good thing to say. We have rights in OAM, ODC, ODL, and OGD. Orlando was mentioning before about our commitments. In Q3 2020, we have $400 million of commitment. Today, our commitment is $286 million. They are actually by two contracts. The one is the take-or-pay of Ocensa P-135, and the other one is the small take-or-pay that we have Bicentenario in Caño Limón. Here is another advantage. The tariff of the P-135 is 23% lower than the take-or-pay contract of Ocensa. That's another advantage to have the P-135 contract. On the other hand, as I mentioned before, we are compliant with the take or pay in CENIT and Ecopetrol because we are using the monobuoy in the maritime terminal in Coveñas. We don't foresee any problem to comply with the commitment. We are doing that. Actually, because we are using the monobuoy more and also using more volumes in ODL, plus this take or pay, we can reduce the timing to pay the commitment. We are going there. A question regarding the tariff. Next year, we should have the renegotiating of the contracts for the transportation, right? That will affect your tariff? Yes. Okay. Are you expecting to go down or? No. I don't think so because I don't think that this government will change the tariff. Remember that the tariff is a regulatory tariff. The take or pay, because the P-135 is increased every year in January 2.4%. That's part of the take or pay contract. The regulatory tariff is increased depending on the formula that is in the regulation that could increase anything depending on the investment and the return of the pipelines. I don't think that this has been a lot of conversation with the government to change the tariff. If you ask me, I don't think that is gonna happen. Okay, thanks. Well, now, like I said before, we have a lot of fields that are not connecting to our field. I will talk about the transportation. But it's not only transportation of hydrocarbon. It's we also do transportation of fluid, personnel, dry cargos, all services. Why we integrate all the transportation activity in our in my organization is because we could use the same model, the same cost model in all tariff. That was part of the optimization that we did in order to reduce costs. Remember that transportation cost has in the your numbers, when you put in your model transportation is only pipeline and trucking, hydrocarbon trucking. That's the only two that is in the transportation cost. Personnel, fluid, and dry cargo service is in operating cost. If we optimize trucking, personnel, fluid, and service, that will reduce operating cost. We optimize transport of hydrocarbon and pipelines, the optimization of pipelines, we reduce transportation costs. That's why, if you see our transportation cost right now, has been very flat during the last two years. It's around between $10 and $11. Okay. Our transportation logistics operations is integral and transversal to the entire company. We handle the transportation of hydrocarbon, as I said before, the transportation of fluid within the field, transportation of our personnel, movement of equipment all over within our field. We also use all kinds of vehicles, vans, trucks, everything. The land transportation team carry out 200 loads per day. I want to show you the magnitude of the activity in land transportation. They carry out 200 loads per day with 41 contractors, companies, in which 35% are community companies. We have development, a local supplier, in the local supply program that after Andrés Sarmiento will talk to you. We have development, we call cooperativas, so small companies, and we grow this company in order to perform the contracts. Traveling 113 route in Colombia and in which represent 60,000, almost 60. You can imagine that how do you control that? We build a platform with GPS, and we know where our trucks are, and this platform is called Pegaso. As I told you before, we try always to optimize costs. We centralize under transportation also the personnel and the service and dry cargo activity in the same platform in Pegaso. Yeah, yeah. Yesterday we were laughing, trying to tramnslate the Voy por ti. As I pick you up. That was I pick you up. René said that is our Frontera Uber that we also have a Frontera Uber. It's called Voy por ti. That is also integrating the platform. When a person in the field needs a truck, so he can ask in the platform, and he will have the ride. In 10 minutes, he will have the ride to get to the location he wants to go. Okay. Let's talk about the trucking strategy. Most of the Frontera Energy land transportation service have been integrated into the transportation management system to optimize process and cost under a single strategy vision and logistic, and also with very good numbers of HSE. As I say, Pegaso logistic platform will represent our system. We had one program called Mujeres al Volante. It's Women Behind the Wheel. We think that sometimes they are better than the best. We are launching this program. It's the program to strengthen competencies and skill of women in the areas where they remember that we have in our field, there are a lot of women that are what like we call cabeza de familia. We try to help those women in order to get the training, the skill, and to be part of our organization in this program. The other one, the last one that is one of our babies is Transporte Limpio. That is a program to use green technologies such as natural gas and also electric vehicles to reduce the greenhouse gas. Also to the particulate matter emissions. Okay. Finally, I would like to say that maybe Andrés Palacio is here, and he has said this morning that I have to say this, that we had an audit two months ago to get the ISO 39001. So we are gonna be the first operating company to have be certified with ISO 39001 in this land transportation operation. In conclusion, Frontera has a unique commercialization and transportation model to maximize the VTI and generate value to our shareholders. Any question about this part? Yes. Sure. Page 46, page 47, where you have all the pipeline contracts. If I recall, you had a disagreement with some of the CENIT entities. That would be the one on the next page, Bicentenario and then Caño Limón. I think you settled about 1 or 2 years ago, right? Whatever take-or-pay problems that you had. When I see that you entered a new contract after you guys settled it about 1 or 2 years ago for another 5 years, can you just help me understand what the economic differences are? Like, what was your take-or-pay that you had back then? Because of cancellation, was it completely gone and you entered it again on a spot basis? Yes. We finished the take or pay. Maybe Alejandra can help me also in that. When we had the conciliation, the old take or pay finished. We closed that contract, and we owe to CENIT or Ecopetrol, we owe some money. That money, we will pay with two take or pay contract. One is the 2023 for 2,340 barrels per day through the Oleoducto Bicentenario and Caño Limón. The other one is 10,000 barrels per day through ODL. That's the two contracts that we have right now. What is pricing back then? Because I know what the price is now, but how much are you paying for it? I know. We pay per barrel around $14 through all the corridor. Right. Okay. Right now, because we are using the monobuoy, remember that the agreement is like a liquid monthly payment that we have to give in CENIT. No matter what the way that you do. You can use the corridor, or we can use the monobuoy. The tariffs will be OCENSA tariff when you go through OCENSA corridor. If you go to Bicentenario and Caño Limón, you will pay that. Because of the small volume, the amount is very little. It doesn't impact the transportation cost. Okay. In ODL, you have Quifa that is connected. The field is connected to ODL, so you have to go through ODL, and the take or pay is almost a take and pay. Your equity stake in Bicentenario is completely gone. Yeah. Yes. Just because of that. Yes. We don't have equity in Bicentenario. Did you get paid for the equity? 'Cause I think in the disclosure you made, you never kind of showed what happened in terms of payments between two parties. Alejandra can help me in that. Very simply, we had a take or pay that dated. You know, we were one of the founders of the Bicentenario pipeline. Today, that pipeline is not necessarily operating. The Caño Limón isn't because of the continuous attacks that it undergoes. Back then, we had a firm commitment to pay around $125 million, and either you ship or you pay. 2018, the board made a decision that because of the lack of use of that pipeline, we had an exit related to our contractual obligations to pay that $125 million. We opted to exit that contract. It took us two years in negotiation with Ecopetrol to reach an agreement under which the obligations on both sides, right? 'Cause they said to us, "You owe us X amount of money for the operational pipeline." We told them, "Well, you didn't deliver on this or so the contract." Net-net, the result was to reach an agreement where they would forego all the obligations related to the pipeline, all these payments I just mentioned to you. In lieu of that, we would enter into those two contracts, which are very manageable. They're low, and they're not necessarily fully take or pay because there's a way that we could somewhat mitigate them. As compensation or consideration for that, we were handing them over basically the Bicentenario pipeline or interest in the Bicentenario pipeline. Right? That's. Like she said, there was a mathematical analysis, and the mathematical analysis versus their contingencies, our contingencies, what ended up being the sum of which is this is the result. Is that more or less? Right. I would only add that it was not only a mathematical exercise, but also an assessment of the legal merits of each of the parties' cases, and we ended up making concessions, so did they. Is that? Yeah. Is the same deal that basically both sides getting out of? Yes. Sorry, I was just gonna add. With the completion of the conciliation agreement, we were able to remove $1 billion plus worth of contingent liabilities from our books. That's the other factor here that we need to consider as part of this overall metrics and math around this. John Henry. Is there any update on the 480,000 barrels in Peru? Yes. We have an inventory. It's at 480,000 barrels. The new operator has been assigned. The crude oil, part of the crude oil is at the end of the pipeline. We need the new operator start operation in order to push forward our inventory. The other inventory is in the field. We need to get that inventory out, a new operator. We are trying to do a lot of thing, conversation with [Petrocolor] and Petroperú and Perupetro, how we can do that. In the plan for 2023, we have sell some part of the inventory. Any other question? Let's start with midstream. I will start this conversation of midstream with the pipeline called Oleoducto de los Llanos. After I will pass the baton to Rodrigo Torras, who is the CEO of Puerto Bahía, so he can talk about Puerto Bahía. For those who are not familiar with the ODL is a pipeline that has 235 kilometers from Rubiales Station to Monterrey, and 224 when it goes from Rubiales to Cusiana. The ODL has three pumping stations, one in Rubiales, one in Corocora, and one in Jagüey. This normally is in enough mode because the pipeline doesn't require. The pipeline only requires the Rubiales stion to pump the 15 API quality. The capacity, the pipeline of 1,300 centistoke is around 3,000 barrels per day. The clients are Ecopetrol, Hocol, Frontera, Parex, GeoPark, and also Tecpetrol. GeoPark and Tecpetrol using a trader called Trafigura because they sell the crude oil to them. Trafigura is also a client of the Puerto Bahía. There is another thing is they have ODL has a crude oil. A crude oil unloading facility. It's a heavy crude oil. Here, we use this facility to unloading the Caño Sur block from Ecopetrol, that today the production is around 20,000 barrels per day. We sometimes unload Pendares. That also is a Tecpetrol crude oil. Sometimes we also depend on the economics, and depend also if we have blockage, we use ODL for the CPE-6 production. Up to September, this facility has been receiving 23,000 barrels per day. They have two dilution facilities. One in Rubiales with naphtha or national gasoline, and the other one in Cusiana with LPG. The volumes that has been injected in the pipeline, 62% is Rubiales, Quifa, Caño Sur, CPE-6, as I say, and the other 35% is in Jagüey. There are most of these crude oils coming from GeoPark and Parex. The 3% is the volume from Hocol. That's the Pendare crude oil that help us. It's around 22 API, and help us to dilute also in the pipeline. Okay. You see here the production. As you can see here in this slide, even though the Rubiales-Quifa and since Rubiales-Quifa or let's say in the Rubiales station, the production has decreased. We also, with the other producer, we almost maintain the same volume transported. It's around, it's gonna be around 209,000 barrels per day, average 2022. However, if you see that, because the tariff in this is $4 per barrel, and this one is around $1.20. Even though that we are increasing the, we try to maintain the EBITDA of the pipeline. That is very important because that shows you that ODL has a strong track record operational and financial performance and cash flow generation. Here you are gonna see, well, the dividends that we had in 2021, it was $108 million. We and the net income payout ratio, that was 100%. This year, we think that we will have the same amount of dividends for 2022. Another thing that I would like to say is, ODL is compliant and they are 100% carbon neutral. They bought voluntary bonds in order to do that. With a project that is reforestation of species of. It is a project that is handled with a different company that they buy those projects. They buy the bonds in order to be carbon neutral. Additional opportunity in ODL. There is in order to increase the volume and also increase revenues. First of all, we are planning, as I said, we are planning because we have 35%, as Orlando and Gabriel mentioned before. We have 35% equity interest in ODL, so we are looking for additional heavy crude incremental. That's gonna be because it's gonna, the heavy oil unloading facility will be expanded in order to receive more volumes of Llanos 34. We are gonna expand the storage capacity in the Hawaii station because right now it's very low, so that also will help to receive more volumes in that area. I would say that as the biggest project that we are planning for 2023-2025, is connecting the Caño Sur production that could go up to 60,000 barrels per day, that go to the ODL to go to Rubiales station and connect it to the ODL. The other thing is that ODL has two power plants, one in Hawaii and one in Rubiales. They are power generation with diesel or fuel oil. Here in Colombia, we have a program for the reliability chart. ODL participate in this program, and also we will receive income for this program also. That's it for ODL. Question? René will help me. Yeah. Yeah. Go ahead. Gracias. Regarding the ODL, you mentioned a payout ratio of around 100%. That's like a policy or do they Wave a target for that? Do you wanna answer, René? Okay. Actually, they have trapped cash, and that's why they give you a 100% ratio. Actually, the percentage is 65%. That's the minimum. That's the minimum policy. Perfect. Historically, they've been paying 100%. Historical has been that, but because remember that ODL doesn't have any debt. ODL finished the debt in 2020. Everything, all cash generation is gonna be trapped cash. It's better to deliver a dividend to the shareholders. an additional one regarding the reliability charge. How much are you getting? I remember that was like for a certain period of time, right? That XM gives you their reliability charge. How is that working? Well, remember that because Ecopetrol bought ISA, we have the ODL could not get the reliability charge. What we did, we did a session one year with Petroeléctrica and the other nine years to another company. Anyhow, we will receive the income for that reliability charge. Sorry. Sure. The follow-up to that, I mean, this one was asked as well before in this meeting and during the earnings call. Some of the equity purchases from your supranational bank partner in the entity that owns ODL and the valuation multiples, like it seemed fairly low. And without going into details, is it because, as you said, like 100% payout ratio, which is a maximum under Colombian corporate law, from my understanding. You cannot dividend more than what you make in a given year, which is a maximum. No. Oh, it is? No. Okay. Why is multiples so low? Because then, like sometimes when I ask other people, they were like, "Why are these pipelines changing hands?" And then. Look, if you wanna get into that question, why is my multiple so low? Let's have a broader discussion. There is clearly a valuation discussion that we prepared a page for you guys to talk about. Just think about it this way. It was an attractive opportunity. We clearly are a direct partner to the opportunity, right? There were some rights related to it. When it came across, we saw it as an opportunity to increase our stake, saw the value, and that's why we purchased the transaction at, you know, for $47.4 million. Was it an open tender or was it just negotiated transaction between you two? Look, it was a negotiated transaction between us two. I think, Inan, you go on. On your per barrel transportation cost, do you guys net out the dividends from the ODL pipelines? No. No. I wish to. Remember, we don't consolidate. Okay. We don't consolidate our pipelines. Actually, the way that you see it in our financial statement is share income from affiliates or from equity income, basically, is kinda the way that it comes in, so no. And just, uh, another- You gotta remember, old Frontera used to do it. New Frontera doesn't do that. In the past, they would have actually deduced that from the actual reported number. No, in our numbers, we do not deduct that. Okay. Since you have a higher price, like, at the wellhead versus your competitors because of this pipeline, does that kinda disadvantage you, like, if the royalty deductibility, like? I don't understand your question. 'Cause we have higher price where? At the wellhead prices. If you're able to sell at a higher price at the wellhead, doesn't that mean that you have higher royalties as well? Remember, we don't sell at the wellhead. We truck our production or we actually export our production. If we get a higher price, we get it for ourselves. Like, the royalty is the same metric if we sell it for, you know, other than the high price clauses in the new tax reform. Mm-hmm. Our royalties are royalty, and the benefit of a higher price is for us. Thank you. Go. For the Rubiales and Quifa production, I guess that's at, like, 440, correct? Mm-hmm. GeoPark, Parex, what's that at? Is there any prospect to increase that? On the potential Caño Sur, what would sort of the tariffs there be? No. The Caño Sur will be the same as Rubiales and Quifa. That's why we think that when Rubiales and Quifa decrease volume, that will compensate with the Caño Sur volumes. That's part of the estimation that we have. In Llanos 34 also will increase production, that is going through Jagüey. Remember that GeoPark and Parex built a pipeline connecting Llanos 34 to Jagüey. They are increasing production in part of the other fields. They are not connected to Llanos 34, they are going by truck to Jagüey. That's why they are increasing the. Remember that also GeoPark and Parex, they sell at the wellhead. Trafigura do most of this activity for them. That is why they use Jagüey, because they actually sublease capacity from us. Got it. Mm-hmm. To add the Caño Sur volumes, do you have to spend CapEx or is there anything you have to do to get that or? No. ODL has cash, so all the projects will be done through the ODL budget. It's cash generation and we don't think that we have to put any money there. How much CapEx will ODL have to spend? Well, we are doing right now the analysis. Actually, ODL will do that. We saw the budget in the last board meeting. It's very in a basic engineering. Yeah. Got it. We think that I mean the project will be analyzed in 2023, and we'll maybe if the economies will be good, we'll start construction in 2024-2025. Thank you. Rodrigo. Well, thank you, Renata. Good afternoon. I'm glad to be here to present Puerto Bahía to such an interesting audience. On the other hand, it's hard to be the last speaker before lunch, so I will try to do it as fast as possible. Well, I'm Rodrigo Torres. After starting with my presentation of Puerto Bahía, I would like to give a short introduction of my background and why I'm convinced this is an excellent port, plenty of opportunities to keep growing. I have been working in the port industry for more than 10 years. I worked for the biggest companies involved in this industry. I have a broad experience in Latin America and in Colombia in particular. When I received the invitation to join Puerto Bahía, I didn't hesitate for a second. I already knew the project, and its potential, and I can tell you that, I think, I'm convinced, sorry, I made the right choice. Let me briefly introduce about this unique opportunity. Puerto Bahía is a strategic partner for all the liquid and dry cargos that wants to manage their logistic efficiently in the Cartagena Bay. The port is owned by Frontera Energy, as was previously mentioned, 90% of the stakes. And started operation in 2015. And despite the pandemic period, it has been growing in terms of volume, gaining efficiency, and improving their operations. It is strategic, strategically located at the entrance of the Cartagena Bay, access channel, with a natural depth, allowing the port to handle deep draft vessels without any restriction. That generate, of course, economies of scale for shipping lines when comparing with other facilities that operate in the Cartagena Bay. We are flexible to customer needs and without the necessity of performing any maintenance or even capital dredging in our port. All what I just mentioned, facts, make this facility a unique one because for the port and maritime industry, what I just mentioned is really important in terms of efficiency and operations. Puerto Bahía, of course, in terms of the day-to-day business, handles export and import of crude oil and derivatives, roll-on and roll-off cargo, which is basically vehicles, all types of vehicles, high and heavy-duty cargo and break bulk. Providing the typical services such as loading and unloading, storage, etc. We are well-known because of our value-added services that differentiates us from the other ports. Well, regarding the EBITDA evolution and volumes, worth mentioning that Frontera took control of Puerto Bahía, and please correct me if I'm wrong, by the end of 2020. Since then and without the take-or-pay contract as a backup, Puerto Bahía have managed to increase EBITDA, and this year we will end up with an 83% of our EBITDA composition coming from other customers than Frontera. Which for us, of course, is very important because it represented an increase in our customer portfolio. Of course, for the next year we are expecting, as Orlando already mentioned, an increase in our EBITDA of approximately 24% compared to the estimation for this year. Part of this increase is explained by the volumes that we are handling so far, and we expect to handle during this year and the coming year. In terms of liquid bulk, as you can see, we have been able on a year-to-date basis to recover the volume that we had previous to the pre-pandemic period. We expect to end up this year handling 22 million barrels, which is a record for Puerto Bahía. In terms of ro-ro volumes, which, I repeat, includes all types of cargo, vehicles mainly. We have been, despite the drop experienced during the pandemic period, growing and, as you can see, the trend is positive. We will end up this year with another record of more than 100,000 units handled in our facility. If we look at break bulk cargo, since there is, let's say, limited space in our facilities so far, and roll cargo is more profitable and with long-term contract with our customers, compared to the break bulk cargo which is negotiated in a spot basis, of course. The increase in RoRo cargo can explain the decrease in the break bulk cargo. Adding to that, we have explored this year a new business unit, which is the shore-based logistic activities that we provided for the offshore exploration. That's generated a pretty good income and EBITDA for the port this year. We think we will continue doing that during the coming years due to the excellent results of the exploration that have been performed in the Caribbean coast. Well, regarding our value driver, as we already mentioned, our strategic position converts us as an ideal operational hub with no draft restriction, as we already explained it, which is very important for the maritime industry. We guarantee operations due to our location, protected location in the Cartagena Bay, almost 24/7, 365 days per year. Which compared to other ports, not only in Colombia, but in the rest of Latin America is a clear advantage. Our exceptional connectivity with our hinterland is an important differentiator against the other ports in the Cartagena Bay. We can see that in the next slide. The figure will speak for itself. Also in terms of operational advantage, we can mention being the owner of the lands where the port was built and currently it's operating. Our proximity to Reficar and being a terminal already in operations, generating value and operating safely and with top-tier standards of operations compared to the other terminals is a clear advantage. Of course, to have available land for expand our facility is one of the most important differentiators that we have against the other ports in the Cartagena Bay. Here, as we mentioned, we have a strategic location. As I mentioned, I think the figure speaks for itself. The advantage of being the first terminal in the bay while the vessels navigate through the access channels is very important in term of reduction of navigation times and also emissions. To have a proximity to the Canal del Dique give us another advantage because we are able to efficiently manage all the cargo that goes in and out through the Magdalena River. Then the proximity to the corridors that connect Cartagena with the rest of the country and being outside of the industrial area of the city give us a clear advantage. Worth to mention that we have a free trade zone status with all the advantage that implies, not only for the current business that it's operating right now, but for all the potential developments that we might have in our port. Here we can see the current layout, but the most important message in this slide is all the available land that we have for expanding our business. As you can see here, we have 10 hectares for the liquid, for expanding our liquids activity. 27 hectares here for dry cargo or also liquid bulk expansion. 40 hectares on the other side of the access road to the port, and then 8 hectares on the other side of the Barú Bridge. A lot of land available for future expansion. Regarding the liquid terminal, our liquid terminal is a state-of-the-art terminal with the latest technology, ensuring a secure, safe, and efficient operation. As from the opening today, we have managed more than 200 million barrels. 400 vessels were attended, 12,000 barges and more than 100 trucks. It's able to handle up to 1 million-barrel vessels, with a loading capacity of 35,000 barrels per hour, that can be increased up to 70,000 barrels per hour, being the key success factor with our customers, our flexibility for performing their operations. Worth mentioning that these loading or unloading rates are very high and very good in terms of operations. As you might know, as fast as we operate a vessel, the better for the vessel and the customer, of course. Regarding the landside infrastructure, we have eight tanks with a nominal capacity of 334,000 barrels. Four of them with heating facilities. All the tanks are interconnected among them, facilitating, of course, the product blending, which is an advantage. And also, the tanks have the status of international logistic center habilitation, which give us also the advantage to storage product for a large period of time from a customer perspective. Regarding the dry cargo terminal, currently we are handling two docking positions with 290 m of berth that can be expanded up to 650 m. And that with the current permit and licenses that we have in place, so no additional permits to be granted for the authorities. That will allow us, of course, to expand our dry cargo business. As Orlando and Gabriel were mentioning, for us, it is crucial to expand both the liquid terminal and the dry cargo terminal, and we are working with several projects in order to do that in the coming years. In the current dry cargo terminal, the roll-on/roll-off cargo is the one that leads, having Puerto Bahía 95% of the segment market share and still growing, adding new automotive brands arriving to our facility. Value-added services being provided in our facility are our key differentiation to attract to keep attracting more customers in this segment to Puerto Bahía. We do also manage different type of break bulk cargos, and we are in constant process of expanding our dry cargo business, trying to attract other type of cargos, such as containerized cargo, as Orlando mentioned. Of course, I previously mentioned the shore-based logistics services that we are working for the coming years. That's all for Puerto Bahía. Hope you have enjoyed the presentation, and I don't know if you have any question. If not- Um- Enjoy the lunch. I was just gonna ask one. You know, obviously with Europe and the US trying to displace Russian cargos as much as possible, that actually creates a big opportunity for Colombia and all of Latin America in terms of exports. Like, do you have like a five-year outlook of kind of like that best possible growth case, you know, wherein you capture this opportunity, you know, caused by the Russian-Ukraine situation? I mean, you know, we actually see Mexico already starting to capture a big opportunity caused by COVID-19 because a lot of manufacturers that, you know, were previously, you know, doing a lot of work in China, you know, are now hustling over to Mexico, and it's really driving up the economy there, which is why the Mexican peso has been so strong relative to the rest of Latin America. The answer would be yes. Actually we are working in several projects that we are, let's say, in a feasibility stage in order to expand our facility going forward and taking advantage of the opportunity that you just mentioned. Is there a way to think about how much of Puerto Bahía's revenues or EBITDA come from the different revenue sources, so like hydrocarbon versus roll-off versus break bulk? Well, let's say in a general. I don't know if you want to answer, but I can do it. In a big picture or in a general overview, let's say it is distributed. It is reaching almost 50-50, liquid bulk and dry cargo. We foresee that in the next year, it will be tight. Right? Thank you. I think that's it for the morning session. Thank you, everyone. Thank you. We will adjourn for lunch, and then we have to be back here to start the second half of the presentations at 2:00 P.M. We don't need to broadcast this part. We've arranged lunch upstairs for everyone. We have people waiting outside that'll take us upstairs to the sixteenth floor for lunch. You're welcome to catch up with our guests. We've got ta- We're having a pretty good conversation with Cristina at lunch, after lunch. We would like to have a conversation about Guyana. The way we have structured the presentation is we want to give you a little bit of an overview in terms of how do we see things going towards production, right? That's the theme of the conversation today, because we have received a lot of questions from you in the last few calls that we have had about that. We want to give you a little bit of certainty beyond, right, what we have been discussing, which is where and how are we seeing things and all that. Regan is gonna share with you on the technical side, kinda like what is the latest things that we have done in terms of the analysis of the information that we have. Remember, last time that we talked, when we had the webinar, we were still doing some things. Like for example, we were still processing the seismic. We're trying to get the latest result on the little data that we were able to get from the samples that we collected in Cajúa. Like the analog sample that we took, which is an indirect measure, and also some of the mud gas and some other things. What Regan is gonna do is show you a little bit of at, to give you a little bit more context. At the end, I'm going to finish the conversation talking about how do we see things in terms of the whole spectrum, right? Going to production, and then people have asked us some questions about, you know, if we get to that stage, what kind of development are we talking about? I think the intent of the conversation today. We know that this is a hot topic for you guys. What we have agreed with Orlando is that if there are any questions, let's wait for the questions at the end of the session, if possible. In that way, we can have the whole presentation, and then at the end of the session, if there is any specific question, we'll be happy to address hat. Is that okay? If we wait until the end, so that way we don't get derailed. 'Cause it's a bit different, right? The first part is more contractual, second part is more technical, and the third part is more like going into the future, yeah? Okay. The first slide is one slide that we put together to kinda give you an idea about where we are in terms of some of the things that are in the contract, which we have been asked about by some of you, which are important to keep in mind, yeah. What is the first thing we want to point out is that we drilled Cajúa, and then we actually made the announcement that that was a discovery, and that's important because that's the first step. As per the license that you have to take, right? Is to declare the discovery and actually to file the notice of discovery with the government to say, "Look, this actually was a discovery." That was the first part. We have done that on the sixteenth of March. After that, you have to, as per the contract, you have to then submit a notice of potential commercial interest, which is a definition that they have in the petroleum license that you have there. Then with that, you have the option at that point, once you present that, to have an initial period of two years for appraisal. That period is initial because the government has the prerogative once you present the case to have additional activity beyond that, right? If, for example, you think that you're gonna need 3, 4, 5, 6 wells, I don't know how many wells we're gonna need. That was a question that we were asked. We don't know yet. We will find out once we get the fluid data and the static data from Wei, we will have more information about the potential degree of connectivity to different areas. Once we know that, the government has the option to give you more time, and actually there is no specific mention to a timeline after that point, after the two years, right? It could be as many as the government feels that that is the right thing to do, right? That's the first part. Second thing is, you know, we have submitted an appraisal program, and we have had a conversation with the government about that. Then what we have done is we have put in the appraisal program Wei as a dual-purpose well, which is a well that is going to comply with the exploration commitment that we have, but it also has a component of the appraisal side that we need to have, right? Because why do we say that? Because obviously, we need to actually confirm that what we found in Wei is similar. Sorry, what we found in Cajúa is similar to what we found in Wei from a static point of view, right? In terms of the rocks, the reservoirs, the levels, and all of that. The appraisal side is like more of the very complete data set that we are trying to acquire for Wei, which is gonna give us a lot of information to be able to proceed with additional information, right? Where do we need to put more wells? When? How? How many? So on. Something like that. Yeah. That's kinda like what we have done. Again, you know, we will wait to hear back from the government. We put some comments here at the bottom that explain, you know, some of the questions, hopefully address some of the questions that we have heard from many people in the past. Yeah, give me a second. Hopefully with this slide at least we give you some indications of some of the steps that we are taking with CGX and where the conversations with the government are in relation to this particular topic. Yeah. Is Wei-1 being drilled in such a manner that it could be saved for production or? No. It's not. No. From this point forward, everyone is kind of. Right. We're getting to that. I have a slide where I'm gonna go into that. That's a good question. These, all of these wells that we're talking about are still wells that are not the producer ells. We're gonna get into that. I'll explain in a minute. Give me a second, and we'll get into that. I'm gonna pause here. This was just the introduction, right? That's the part that. I know that you may have some questions about, you know, what all questions that we have heard from you on the license. If you agree, let's just save that for the end, and then that way we can come back and address the whole thing. Yeah. Now I'm gonna pass it to Regan, who is gonna give us a quick update, and then I'll come back, and after that we will be open to take some questions. Yeah. Thank you. Back when they like to. There we go. Good afternoon, everyone. Well fed, I assume, but wide awake. I'm very cognizant of the fact that many of you are familiar with this project, but others maybe not so much, depending if you've seen our previous webinars. Today I'm going to first review Cajúa-1 targets and results and relevant competitor activity. Then I'll show some updated technical material that's been developed since our last webinar. Since that webinar, we've continued to receive data and interpret that data. I guess we are increasing our understanding not just of Cajúa, but of the block in general. This includes quantitative interpretation of the seismic, QI, biostratigraphic analysis, detailed analysis of lithologs, ongoing lithological analysis and geochemical analysis. We have been advancing this story as we go. The play type schematic shown on the left. This one here shows the play types that were a target at Cajúa, with the primary targets being those upper Cretaceous channels and fans deposited in a slope environment. By slope, I mean between the shelf and the basin floor. The sands are carried out through canyons over the shelf and down the slope, but not all the way out to the deep ocean bottom that we call a basin floor. Cajúa's targeted zones, which are these ones right in here, are the same age as a vast majority of the discoveries in the basin, as I've annotated. I'm showing sort of some Stabroek pay types and then some Block 58 discoveries in slightly deeper and older zones. Cajúa -1 was very outstanding in that pay was found over a large stratigraphic interval and in far more zones than we anticipated. In fact, it was distributed over 6,000 ft in the wellbore through the entire upper Cretaceous, so that's Maastrichtian, Campanian, Santonian, and Coniacian. With elements of both, you know, the Stabroek Golden Lane, so to speak, and the Silver Lane, which is more inboard. A total of 228 ft of pay was identified on the logs with good porosity, even at depth. In the seismic line in the middle of this slide, you can see how the pay is distributed through the wellbore. To the non-technical, this seismic line is like a vertical slice through the Earth at the Cajúa location. It shows the sea bottom at the top, and then drilling all the way down and hitting right there at around 21,000 ft. The layers highlighted in yellow represent the pay zones that were encountered in the wellbore. Now, I don't intend to go into great detail on these intervals. I did that in a previous webinar, but we'll point out the highlights of each. Starting at the top in the Maastrichtian, this is where we got some of our blockiest and thickest pay, up to 26% effective porosity and indications of gas condensate. The Campanian sands underneath it were thinner but equally porous. I guess I should say these targets were not primary targets in Cajúa -1, but we were very excited to see the sand with good porosity and pay at those levels as they're mappable elsewhere on the block. The pay in the lowermost Campanian and Santonian below were intended targets for us, and they had indications of oil rather than gas condensate. Even at these great depths, porosity was preserved. The Upper Santonian zone in here was particularly interesting as it was associated with a large mappable channel complex that thickened away from the wellbore, and it's a great analog for our targets elsewhere on the block. The pay in the Coniacian at the bottom of the wellbore was most difficult to define. It wasn't logged due to wellbore conditions, but the well kicked and good reservoir was observed in cuttings. Now the new well will not go that deep, but it is an important potential resource in future wells. Pre-drill, the JV did have a robust evaluation plan, but as I say, wellbore conditions prevented acquisition of some of that data, in particular the MDT samples. Therefore, we were forced to analyze the hydrocarbon type from the data we did have, more indirectly. That was mud gas data, gas data collected in isotubes, hydrocarbon extractions from cuttings and from oil mud mixtures from the annulus at the bottom of the well. The results were actually very consistent from all those data sources. They all pointed to a similar conclusion summarized in the table on the right. Gas condensate indicated in the Maastrichtian and Upper Campanian, light volatile oil in the Lower Campanian, Upper Santonian, and volatile or black oil in the deeper zones, Lower Santonian-Coniacian. The fluid characteristics that I've annotated there are typical characteristics for the interpreted hydrocarbon type, with the exception of the Lower Santonian and Coniacian, which was more directly measured because we did get oil in the annulus fluid samples. To reiterate, these aren't MDT samples. They're mixtures of mud and oil that were collected from the annulus after the well kicked. They can't be pinpointed to a particular sand bed. What I like to say is that the analysis of these samples gave us a lot more confidence that oil was present in this petroleum system in the deeper parts of the well, and this was very consistent with the competitor results in the offsetting blocks. On that note, I am going to talk a little bit about the competitor activity around us. This slide summarizes some but not all of the activity most relevant to us. The base map shows the position of the discoveries relative to the present water depth and the location of the modern shelf here, where you're transitioning from white to dark blue. For reference, the location of the Liza Field up here, this is the Corentyne Block, and this little polygon here in black is the position of our most recent 3D seismic survey in North Corentyne, where all of our activity is focused. Discoveries announced before Cajúa was drilled are shown in olive green. I hope you can see the color difference here. These are the ones that were announced before Cajúa was drilled, and the blue ones are the ones that were announced after Cajúa was drilled. Just from a trendology perspective, you'll see that many of the recent discoveries are very close to North Corentyne, and in some cases, actually, these discoveries are closer to Wei-1 than Cajúa is. On the Guyana side, much of the activity has been in that established Liza trend, now referred to as the Golden Lane, and it's marked here with a gold band. Wells in this trend targeted the shallower targets, Maastrichtian and Upper Campanian. In these reservoirs, it's typically oil to the northwest and then trending to condensate closer to Corentyne and the Suriname border. Two new wells in this trend have been drilled very close to Cajúa-1 or to Corentyne. That's these two right here, Sailfin and Lau Lau-1, recovering over 300 feet of hydrocarbon-bearing reservoir. Our competitors are also having a lot of success drilling what appear to be up-dip feeder channels to those down-dip discoveries, and this has widened the Golden Lane, and it now actually overlaps this, what we call a Silver Lane, which is generally defined as more shoreward drilling, targeting those deeper horizons. Really this shoreward trend has seen a lot of drilling recently with successes as you go down here, Fangtooth, Berbice, Yarrow, and Lukanani all on trend with us. These target a variety of things, with apparent discoveries and everything from Maastrichtian down to the Coniacian or Santonian. That's not surprising to me as we are in a place there where the Golden and Silver lanes overlap. It's interesting how many wells on this trend were drilled after we drilled Cajúa, and their results really mirror what we see in Cajúa in terms of how the pay is distributed through a large interval throughout the Upper Cretaceous. It really reinforces what we see as prospective in North Corentyne. On the Suriname side, success in the deeper trend had already been well documented with all the drilling in Block 58, like Maka, Sapakara, et cetera. There's been a smattering of drilling outboard in Suriname with mixed results, but maybe more relevant to us is the release of some information from appraisal drilling of some of these wells. I haven't put it all down there. We're starting to see information released on resource size, permeability, details on hydrocarbon type, and that's all valuable and relevant to us. To summarize this slide, North Corentyne sits in a very prospective location in an area where the discovery trends overlap, and oil can be expected in many horizons. Since we drilled Cajúa, nearby competitor drilling has just continued to march toward us and de-risk our block as a whole and increase our confidence in Wei. Let's take a look at what Wei is targeting here. The figure on the right is an excerpt of a seismic line representing another vertical slice to the Earth, this time from Wei to Cajúa, which are 14 km apart in this display. In this case, this slice is focusing in on the lower Campanian and Santonian age interval. The horizontal and vertical scales are not the same, so this vertical thickness you're seeing is approximately. Approximately 3,800 ft. Even a non-technical eye, when you look at this, you can see the changes in the seismic character, both vertically and laterally, and those represent changes in rock type. The highlighted yellow anomalies, when mapped in 3D, each reveal a sinuous channel, and you can see that in some of these examples. I'd shown this one in an earlier webinar, and here's another one just also that will be penetrated in Wei here. Each one of these yellow anomalies interpreted to represent a channel complex in the slope, so they'd be filled with a mixture of sand and shale in various ratios. Generally, the center of the complexes would be expected to have more sand and less shale than the margins. Cajúa penetrated the margin of one of these smaller complexes, and got porous sand and pay. When we see similar channel complexes interpreted across the block, we get really excited, especially when they stack up. You'll see, just from this, Wei will penetrate a number of these channel complexes. As you see, they don't stack up perfectly in a vertical line anywhere on this seismic section. That means Wei will penetrate some of these channels in a nice center position and some in a marginal position. There'll be a variety of sand and shale throughout here. Targeting any area where a bunch of these channels stack up increases our chance of getting more sand and therefore more pay. As you can see, that central area between Cajúa and Wei also has a significant number of these stacked channel complexes, which will provide additional drilling opportunities in the future. Let's just take a closer look at that central area. This is a more three-dimensional view right here. Note that north is no longer on the top of the map. Imagine you're floating in the Cretaceous Sea, you're looking back toward the Cretaceous beach and shoreline, you're looking down the length of the Corentyne block, and you're seeing these channels of sand coming down the slope towards you. That's why Cajúa is now on the left in this figure and Wei on the right. The figure on the left is called an opacity probe display of the seismic data. In this portrayal, the transparency of the volume is manipulated to allow you to see the geomorphological features of these channel complexes. It's done through a window. You're seeing you know, it's a window into a broader interval and seeing channel complexes at many levels. In this case, you see laterally and vertically stacking channels within an upper Santonian level. These channel complexes are really well imaged, they're beautiful, and they look more like things we're used to seeing in a river valley, the Bow River in Calgary, in a much smaller scale. These processes occur in present day submarine environments. To demonstrate this, I just put some figures in of the modern Indus fan. It shows us similar looking, similar scaled submarine channel complexes. The Indus fan is one of the world's most significant, most researched channel levee systems. I just thought it was a great example here. The schematic on the right shows how these channels tend to migrate down slope and then migrate back and forth across. It's depositing sand in a big area as it migrates back and forth. When these sands overlie each other, cut into each other, larger bodies of sand amalgamate and form a nice connected reservoir, and we refer to these as geo-bodies. On seismic, we can define geo-bodies by identifying areas where particular seismic parameters are consistent, and then can be interpreted as connected reservoir. The colored blobs, again. This is that same view, but now some geo-bodies interpreted. That's an example of a geo-body extraction at this specific interval, and you can see that it directly reflects that migrating channel complexes that you're seeing. Now, this is an interpretive process. It obviously benefits from more rock data, and it will evolve as we get more data. We spent a lot of time in this presentation and previous presentations talking about the lower Campanian and Santonian. It's important to note that additional prospectivity is on this block in shallower and deeper horizons. I wanted to spend my final slide talking about that. This is the same seismic section between Cajúa-1 and Wei-1, but is now expanded to include the whole upper Cretaceous. Previously we were looking just at this interval, now we're going all the way up. This is the tertiary up here and then the various Cretaceous horizons as you go down here. Again, the anomalies are highlighted in yellow and are interpreted to be primarily channel complexes. Based on basin modeling, geochemical analyses, the comparative results in offset blocks, we believe the sands above this line are more condensate prone, and the sands below this line are more oil prone. What I wanted to share with you is just a sampling of the prospective things that we see. Some of these are penetrated by Cajúa and Wei, some are not, some would be targets of future drilling. But close to Cajúa, not penetrating the wellbore, there are several interesting deeper anomalies. This is the one we've got some pay and porosity in. You have these really robust channel anomalies just beside it, and there's a nice example of one there. I hope you can see the nice channel sinuosity there. There's also a very large Maastrichtian anomaly up here as well at Upper Cretaceous. This is the same age as Golden Lane discoveries just north of us on Stabroek. These shallower, younger anomalies, they do look a little different. They don't have the same sinuosity. They may represent a different depositional environment. The offset discoveries north of us and the porosity and pay we saw in, you know, smaller Maastrichtian zones here, make us really excited about some of these bigger, more robust anomalies near us. If we walk over more toward Wei-1, we see a really good anomaly in the Campanian here. Again, you can see a really nice channel complex there, and it would still be in the oil zone. In the shallower zones at Wei, we've got a series of stacked Maastrichtian channels that seem to stack up, and we will actually get a good look at those in Wei when we drill that well. To reiterate, these are just a sampling of some of the additional shallower and deeper opportunities. Maybe you can even get a feel for it yourself looking at that. These additional opportunities do vary in size. Some are more robust than other, but I can tell you all of them are mappable. To summarize what I've shown here today, I would say that as we continually refine our interpretation, the more excited we are about the prospectivity at Wei and the abundance of follow-up exploration and appraisal opportunities in North Corentyne. That's all I wanted to share for you today. Until the next update. Victor will pick it up here. Thank you, Regan. Now to keep moving. We put this slide because, you know, we have also received many questions about this in many of the calls, so we wanted to reiterate here a few points. One is that, you know, the range in terms of development for the first oil or the first gas molecule that you see out of a deep water project in frontier areas, the range is now has been established between 4 and 8 years. Before it was more like between seven and 10 years. ExxonMobil has done, you know, an amazing job of being able to shorten that cycle to four years in the second phase, not in the first phase, right? In the second phase of the development. The first phase was more like five years. What you have is a range between four and eight years, and it depends on how complicated or not, and the number of appraisal wells that you need to do, whether or not you're gonna go to a higher number of years. In here we put an example, right, of what it could take, right? Where you are saying that it could take, for example, around three years to get into appraisal. Once you get into appraisal, so once you get confirmation from your original wells, usually 1 or 2 in our case, wells, and you get the data that you have to be able to proceed, then you go with the appraisal wells, and you go and make a specific usage for those appraisal wells, right? In a particular case, for example, you could be testing the connectivity level, and at that point is when you start entertaining DSTs, which are, you know, tests that you do over time, where you try to sense what is gonna be the productivity of the wells that you're gonna drill in the future, the development wells, and how much drainage you're gonna have, because that's also gonna be very important obviously for your field development plan, because then that will decide, you know, how many wells you're gonna need to put on the ground, and if you're gonna need to put water injectors or if you're gonna use a different scheme, right? That's the first part. Once you get your appraisal activities done, depending again on the degree of complexity, that will decide how many wells you need. You get the data, and you start selecting what is the optimal solution for that particular area that you have, right, in terms of all these elements that I mentioned, which I'm gonna stress in the next slide. After that, usually you go into something that is called define, which is the pre-FID, which is the final investment decision, where you actually say, "Okay, now that I have looked at all the options," right? "I have several options here. I now have to commit to one option, and then I'm now ready to do that." Usually at that point, you start going into the detailed design, the execution, the project delivery. Sometimes, you know, before you actually start operating, you actually have to drill your development wells. That's where the wells that actually are designed to produce will come into play. All of these wells before that, which are in the appraise and the select, typically are not wells that you actually design to be able to produce. Why is it that it's not done like that in the offshore unlike in the onshore? Because of the amount of uncertainty and the cost that it would require for you to do such a well, because then you would have to put so many contingencies in place that it would be something that is not manageable. This is the typical timeframe. As we said, you know, we are here in the early phase, and we are starting to enter, hopefully with Wei-1, into this next phase. If we go to last slide and then we will open it for discussion, is we have looked at, we have invested some time and effort into third-party studies, which have included the quantitative interpretation analysis. Some of the stuff that Regan showed you before, which is very important because once you have the well data, then you have to understand what happens away from the wellbore, right? What we hopefully were able to show you today is that with the additional data and the information that we have processed now, we feel pretty good about the area around Cajúa. Not just about Wei, right? Because a lot of people feel that maybe, you know, Cajúa is not good or was not good, but actually it was one of these wells where the first well in a frontier area, which actually proved the hydrocarbons in many areas of the stratigraphic column. We have spent a lot of energy on that. We also have done some advanced geochemical analysis, and actually this has been with people that are familiar with the basin, that have worked for oil operators that are in the basin, and that cannot tell us, you know, information from the other wells, but at least they can say, "Yeah, this makes sense, and the interpretation is in line with what we have seen in other places." We have also spent quite a bit of energy on that, and as we said, the expectation that we have for the Wei-1 well is that the upper part of the well will be more on the condensate side. Then the yield is what we want to know. That's one of the key pieces of information that we need to get as part of the appraisal nature of Wei. What we're gonna see is it on the high yield side or is it on the low yield side? Because obviously that would have implications in terms of what do you want to do with those horizons. We have also done some engineering studies. We have looked at the subsea engineering, the flow assurance studies, the CapEx estimates with Technip, which is a very well-known company, is very familiar with this type of development. This has been done in detail. We have looked at the development well design, drilling and completion, execution and efficiencies with Halliburton at a high level, obviously, because we don't have all the information that we need right now, but at least to look at it at a high level. As a result of all of this, you know, we think, you know, that one of the most likely cases, right, that you have here is gonna be on an FPSO, which is kind of like the way that is being done in the region. Right, where you will have some subsea production systems, you have some umbilical riser flow lines, and then you will have some development wells, you will have producer gas injectors, where injectors you probably have seen some of the information from what ExxonMobil, for example, is doing. I don't know if you guys attended the meeting in Houston that the AAPG organized this year, but ExxonMobil actually presented a lot of detail of what they have been doing in terms of the development and the appraisal and development of their fields in Liza. You know, it's in line with some of the stuff that we are proposing here. In a summary, we are taking this very seriously. We understand the importance of having line of sight, you know, of what happens after Wei-1. We have been spending some energy preparing for that from a static point of view, trying to get, you know, as much information as we can from the seismic so that when we have the new information from Wei-1, we can calibrate and integrate. We have also started taking some steps with the government and internally to look at what happens with the license after this. It's a journey also, remember, because it. We are the first ones that are doing this. Remember that ExxonMobil is in a different place. They still have a valid phase, so they are not in the same place that we are, right? They are still within the first 10 years, so they haven't had to have this kind of degree of detailed conversations that we are having, right? Because they are still within their license. Their license, the first phase is gonna expire in the at the end of this year. At the end of this month, I think. That's the other part, so we're looking at that. Then we are starting to see what happens beyond that, right? At the right pace, because we don't want to get too far ahead of ourselves making assumptions on stuff that we don't know yet about where we have some uncertainties. Let me stop now, and then we will open it up for questions or comments. I may also have to invite Orlando here to the podium. Please. Yeah, Oriana? Yeah. I think you have to. There? Okay. Yeah. Thanks for the update. Maybe just a couple follow-ups. First, with regards to the Demerara, and just to be completely sure that not moving forward with the exploration commitments doesn't entice any financial or other payments associated because you are concentrated on Corentyne. Following up on that, on the Corentyne and just by looking at this presentation, like I understand that it's very preliminary, no? But in a ballpark estimate on how much cheaper are these appraisal wells compared to the exploration ones, and how is Frontera looking, if we think of this as in a medium to longer term perspective, is it something that could be done alone or what are your avenues that you could be exploring just to make sure that if it's enticing enough, you move forward in Guyana? Yeah. I think if you can repeat the first question because I did not- Yeah. The first one has to do with the exploration commitment that you had in Demerara, that you- Ah. Relinquished that. Demerara. Understanding that if there have been any updates from the conversations with the government, in terms of if that's already cleared or should we expect any updates soon from that, from the end? Orlando, do you want to start with? No, yes. I think on, Oriana, on Demerara, as we said in the previous quarter results. I think it was in the previous quarter results. Alejandra come help me here. We signed the deed of termination for Demerara, so that's it. That's gone. I don't know if we have received back the version signed by the government. Not yet. We did it. That was a few weeks ago, a couple weeks, three weeks ago, no? November 20. Yes, November twentieth. That's gone. I think it's, I mean, good news for the government in terms of their intention to include Demerara in a potential new bid round that they have announced. That is number one. Number two is the- I can address. You can address that? Yeah. Okay. What I would also like to say, Orlando, is that back to your question, sir, no additional commitments. Obviously, with the signature of this agreement, basically, we are basically released from any obligations, okay? Basically that's the important news, I think that was one. Second part is in terms of the appraisal campaign and the wells. It's counter because actually sometimes the appraisal wells, depending on the nature of the well that you need to have, may actually cost more than the oil one. We don't know yet that until we get the data from Wei-1 and until we decide how many wells we need to put, right? Because then if you have to do like a DST, then that usually takes time of the rig, right? Being there on standby, you know, while you do the testing. Sometimes actually a DST, sorry, an appraisal well would be a little bit more expensive by design because you are trying to achieve some objectives that are very specific before you make your decision on the selection of the best development scheme that you have, right? It's something that will depend about also how do we feel about the information that we get from Wei-1, right? How conclusive in some case it would be that will help you to minimize some additional costs in the future. Yeah? Okay, any other questions? Obviously you haven't given a reserves assessment post-Cajúa, but pre-Cajúa, the third-party reserves assessment. If I remember correctly, there was lik a P50 estimate of potentially 5 billion barrels just in this northern tip of Corentyne. Obviously, that would take way more than one FPSO in the event that you had multiple large prospects discovered. I guess really my question would be: How many years do you think it will take you to drill out your top prospects within this Northern Corentyne region? Yeah. I think there is an element of exploration. We feel, and I think we feel we share this with Regan, but I would be happy to hear from you, Regan, if you feel different, is that with this next well that we're gonna drill, we feel very comfortable we'll have enough information from the exploration side, right? We don't think we need more than that. Now, from an appraisal point of view, it depends on the connectivity or the degree of connectivity we think we have, and that's why this static update that we gave you in terms of the of the sand bodies, right? If you see, before we were not showing you those before because we didn't have the data, right? We were processing the data. Now we can see that, and actually we can relate some of these features very well with features that are, have been now drilled by mainly ExxonMobil around us. It's very clear that these are the same features, right? That they are drilling. Now we have that qualitative view that we didn't have before because, as Regan mentioned, there have been several wells that have been drilled since Cajúa, actually closer than Cajúa to Wei-1 that we did not have before. Now we have some seismic, right? There's no 3D, but some seismic that connects with some of those areas. Now we're saying, "Okay, this is the same stuff," right? That's giving us encouraging views on that. That's the first part. The second part is in terms of what else do we think we need? We need to have the clarity that our model, geological model that we have proposed is correct. That basically, being in the center of these channel systems is what you need to have good properties. With that, if we can prove that, hopefully with Wei-1, and if we get also a good definition of the fluid types, then you'll say, "Okay, if I have a good yield," right? "If I have a high yield for the gas, for the condensate in the upper part, then I need to take that as part of the development scheme," right? Then I have to extract the liquids because it's worth extracting the liquids because it's a good yield, and then I have to put that into the picture, right? If it is on the drier side, then you say, "Okay, now what I'm gonna do with the gas?" Right? ExxonMobil is actually dealing with that right now because they are starting to say, you know, maybe the gas we're using, that's what they showed in Houston this year, they may be using the gas for pressure support, for example, right? That's a part of that. I'd say kinda like, I don't know if I answered completely the question, but we have to take all of these elements into account, and then at the end, final decision will have to take all of these elements on the static side to see if the porosity and permeability that we have is good. That would mean good connectivity and also a type of fluid because then also you have to see if you have to deal with gas that is on the drier side or on the wetter side, which will then take you to a particular development, right? Because then you have to extract all of that liquid and then try to produce it with the liquids that you find, below, right? In the San Antonio. Okay. I guess my question, just to be a little bit more pointed, if Wei is a success, how soon can you drill your next well? Oh, okay. The appraisal well. Yeah, I think what we are thinking, you know, based on these preliminary conversations that we have had with the government is that we'll have to start planning right away, and I don't know, can we? We. Can we disclose that? I think, I mean, the way I will respond that is, I mean, we don't know yet. We should wait for the result of Wei, no? Incorporate the results into the model, analyze the results, and plan accordingly, no? One of the things that we are still looking, as we have previously said, is still looking for strategic options to continue with the program, no? That's a fact, no? In the conversation we are having with the government, we are talking about a two years appraisal plan, no? That is what we are talking to the government. Mm-hmm. As Victor said at the beginning or earlier, we are looking at Wei-1 as with a dual nature, exploration and appraisal, no? We have submitted all the relevant information to them to analyze that appraisal plan. That will depend on the result of the well, of Wei. That's the only thing I can say at this point in time. It's difficult to anticipate what is. We are excited about it. I mean, I think, based on all the information we are getting from Cajua, from the recent discoveries nearby, I mean, we are still very excited about this opportunity, working hard on that, and discussing with the government on that appraisal plan. Oriana, I think I had not answered part of your question. I think that was answered by- That was okay. Answered by Orlando, yeah? Because she was asking about- Okay. Are we gonna go, what are we gonna do, you know, after Wei? After the Wei, yes. We are looking at strategic options because we understand, you know, what it's gonna take to go after that, right? It's very clear. Nice. I think. Yeah, I guess 'cause, I mean, like, my big fear as an investor is, you know, while I really enjoy deepwater because I kinda feel like it's the future. But I know that we're entering into a region where deepwater rigs are constrained. Mm-hmm. I know it's gonna be really, really hard to get our hands on another rig. You guys did really well when you contracted the Noble Discoverer, and you had that option for a second well. You know, I would hope that you're already in discussions. Yeah. You know, in case it looks like you need to bring another rig soon, because just like what we're experiencing now with Shell having its delays in Trinidad, you know, through no fault of your own, your well gets pushed back, you know, almost by half a year. Yeah. Which is substantial. No, we are also looking at what is it gonna take? What are the kind of things that we need to be looking into? Obviously, that's a big element of the equation. Mike, you had a... Just on the Stabroek Block, I know we know that 11 billion barrels have been discovered there. In terms of the Corentyne Block, do you just ballpark what minimum threshold of volumes discovered do you need, economically for standalone development? Is it like 400 million or 500 million barrels, or just ballpark? Yeah, I think the way I would answer. I mean, that's a good number to start with, by the way, so that's a good number that I would start with. Then I think at the end, I would qualify my answer by saying that it will depend. We have been looking at different analogs, and actually, by the way, you have seen that Exxon, with the exception of that, presentation, was like a whole day presentation that they made with different topics. In Houston, they have not shared much. Only Hess is the one who shares occasionally, right, a lot of information, but from the Exxon side, you don't hear much. Anyway, what we learn a lot is that they have been having to adjust quite a bit their program as they go. Initially, they had some ideas about how this thing was gonna go, but for example, they have had surprises. They show one example where they did a gas injection in one of the areas of the field, and they didn't realize that that was an area that has such a great connectivity that the gas got to the wrong place really fast, you know? Then they had to make some changes. I think what I would say is that at the end, we're gonna have to see how much gas do we have, how rich or dry that gas is, that would be one key element, and how connected this whole thing is. If it is more connected, then the higher the recovery that you're gonna have and the lower volumes that you're gonna need to make it, you know, economic, right? Your number I think would be more like in the case that is kind of in the medium case, where it's not as connected. If you are more connected and better quality, you probably could be thinking about a lower number, right? That's what I would say at this point with the information that we have. One further question, too, in terms of the Stabroek Block. Does ExxonMobil have confidentiality on the well data in perpetuity, or does that become public at some point where you can access some of that data? Yeah, the laws are very clear, so for anything in there, if you want to do any data trade or anything like that, you need the government approval. It's not public, but you could have a conversation with companies to have a data trade or to have data trades. They don't publicly share the data. They own the data until they have the license. The same with us. Okay. Here. Question from Cameron. Yeah, just wanted to know, like, how the conversations with the government have been going around the Discoverer delay from the Shell well? Yeah. No, I just wanted to reiterate what we said a couple weeks ago. I mean, there is a revised spud window that's still the same. We have much more certainty on that spud window, new spud window, mid-December or late January. The government is comfortable with that. They have agreed in principle that the reasons for the delay are beyond our control or the JV's control. The other element which I think maybe is new for this conversation today is again the appraisal plan discussion that is going around, no? That gives you an indication of the level of support, cooperation from the government in moving forward, no? We're still committed to the well. We have been prepared since August. Looking forward to that, believe me. That's the situation. Yeah. I think that again, I mean, just to reiterate, the appraisal plan conversation where Wei-1 has this dual nature of exploration and appraisal, no? Is a good way forward, no? Yeah. To add also, I think that's important point that Orlando mentioned, is that in terms of what's happening with the rig on the current operation, yeah, we have a lot more clarity. They have been finishing, or they have finished the operation they were doing, which took so long. Now they have moved on, and now they're in the last stretch. You know, we are in constant communication with them, and then we're gonna have another conversation with them next week. Things are progressing in the right direction, so we feel comfortable that the end is gonna be very close for that operation, so that they can do the handover within the window that Orlando mentioned. Mike? Yeah. At Wei-1, once you've reached TD, and if everything's going well, will you have an option to take the well deeper to test those lower Cretaceous horizons, or is that getting beyond the? Right. Pressure regulations? Actually, that's a great question, Mike. We learn so much from Cajúa. Actually, due to operational considerations, you know, you typically have conversations with other operators, right? Who also, because it's in the best interest of everybody to make sure that we share operational experiences so that, you know, and the people are very open, right? Total, Apache, Exxon, Repsol, you know, everybody has been very open to us. We have had the conversation, right? What we have experienced, as we showed you before, is kind of a bit unusual to find it in the same interval, the two cases that we found. Everybody has said, "You know, the way that you guys managed this was very proper. We don't have anything to add. Probably we would have done similar things to what you did. Now, for future wells, if you can avoid mixing that with the deeper part, which was where we had the big kick, better. That's why the design of this well is to not go into the deeper. I mean, we do have. As per the well design, you could do it, but we don't want to do that because then it would add that level of complexity, which we don't think is necessary this time. Because this time we are very focused on what we think is gonna work, which is this Santonian, the Campanian, the Maastrichtian, which is kinda like what has been confirmed by all the activity around us from Exxon. I don't know if that makes sense. It has been a good conversation and a very conscious decision that was made not just in isolation based on the results of Cajúa, but in the context of a bigger conversation from an operational point of view with other operators in the area. Okay? So thanks. So we'll be in touch and if anybody has any still some energy left, Christina, I'm getting the signal from Brent. After you TD Wei-1 well, how long will it take to get our reserves update? Reserves update. Sure. Potential discovered resources is what we have, right? Not reserves, right? Because reserves would be after appraisal. What we have to do is first have to get it. Hopefully, this time we'll get it. That's what we expect is to do the MDT. We have to do a PVT analysis, which will take two to three months, right? Because then you have to analyze, as you probably have done it before, right? You have to analyze in the lab all the information. You have to get all the information from the static point of view. You have to integrate. It will take us probably few months after we drill Wei-1 to get that so that we integrate all the pieces. Because as you remember, the data acquisition program that we have is very comprehensive. This time we want to take the time to be able to analyze all of this data, right? You're probably gonna see the initial results in terms of pay and things like that, but not a lot of detail after that because then we need to do the homework, right? Do the analysis. Because this time we are treating this also with the appraisal lens, right? Okay? I know that, you know, you'll have to be a little bit patient, but it is, it's because we have to do an analysis on the data. This is not a near field exploration. Yeah. Yeah, it's just. No. The problem is you gave us the numbers before Cajúa, and then now we've waited two years. The problem is that we don't have much more to say at this point, as I mentioned, Christine, because we couldn't get the fluid data, and we couldn't get the rock properties data. That's the problem. Basically what you're saying is your prospective resource assessment is the same now as it was pre-Cajúa. I don't have anything to update the number with, right? We have decided not to do any update because we don't have any new information that would, you know, kinda provide. It's not worse. Yeah. I mean, I don't have. Yeah. Let's wait for Wei-1. Let's wait for Wei-1 so that we can get the data. Yes. Well, good a fternoon to everyone. The good thing is all the enthusiasm that you showed for Guyana, we have the same enthusiasm towards ESG here in Frontera Energy. Basically, what we've been seeing during the last session is what we do in Frontera Energy. What I wanna talk to you about is how we do it, because all the commitment that this team show towards what we do, we have the same commitment and the whole team and the whole company, has the same commitment towards ESG and the way we do it and how we do it in Frontera Energy. First, let me start by a little bit of context. Basically, Frontera, since it was incorporated, we've had our sustainability report where we've been showing all our sustainability developments year by year. However, in 2020, thanks to the big involvement that we have of our board of directors, because there is a direct involvement of the board of directors, the top management, and then the entire corporation towards what we do in ESG, we updated our sustainability policy and our sustainability criteria and priorities. We came up with an ESG approach. Basically, what's the ESG approach that we have in the company at the moment? You can see that on the environmental side, we have climate action, life and ecosystems, clean water and sanitation, and of course, the responsible production and consumption where we are sourcing our consumption, we are trying to do it in the most responsible way, and of course, always working with our local communities and with the local and regional authorities. In terms of the social approach, we have our health and safety strategy. The diversity and inclusion and equality transcends not only the inner company, the Frontera, but also the way we relate to our communities and the way we work with them and community relations. In terms of community relations, I'm gonna share what we've called our strategy to relate with our communities because this is part of the social license and the operational viability that a lot lies in how we relate to our communities. Finally, in terms of government, the four criteria that we have prioritized is outstanding business ethics. I'm sure most of you are aware, but Frontera has been awarded for the last two years and has been recognized as one of the most ethical companies in the world. This is thanks to a culture of compliance and a culture of transparency, and ethics that we have developed within the whole company and the way we relate to our contractors and subcontractors. I'm gonna talk a little bit of that later on. Then human rights and cybersecurity. Actually, cybersecurity is a new part of the strategy that we've included in 2021 after the update that I was talking to you. Finally, in terms of context, I would close that from Frontera. We are following all international standards, like most of the companies in our industry. Ratings and frameworks, in terms of our sustainability report, we used to follow primarily GRI. We are now following also SASB and TCFD. Basically, we are aligned with the evolution of the ESG compliance in the world and migrating towards more SASB and TCFD. That is happening not only in Frontera, but in a lot of companies within the sector. Well, now what I'm gonna show to you is before coming into the 2022 performance, but I wanna focus on that part, is these are our publicly disclosed ESG goals for 2022. I only want to highlight a couple of those that I'm gonna touch more thoroughly, some others in the next slides. However, from this, I would like to highlight the following is: In terms of climate change, we are going to neutralize, and one of our objectives is to neutralize more than 50% of the emissions that the Scope 1 and 2 as a company has, and to develop a solar farm project at CPE-6. I'll tell you a little bit of how we are doing and the way this developing is going. In terms of water management, reduction of 20% of water consumption in our operation. The good news in terms of the water reduction strategy is that at the moment, our performance is 25% already. To the third quarter and the information that we disclosed, we are above the reduction of water that we had of 20%. Finally, from this environmental part and our goals, last year, 2021, we protected 764 hectares of biological strategic corridors within the areas where we operate, primarily Meta and Casanare. In terms of 2022, our goal is to protect 900 hectares. The important thing is this goes directly to impact biodiversity. Biodiversity is something critical for Frontera Energy in its environmental strategy. We are protecting the corridors for the jaguar, for the giant otter, river otter, and other four. There are four mammals that we are protecting. Hopefully, you'll get to see a jaguar tomorrow in your visit to our operations. In terms of our social priorities, HSE, we have the goal to reduce 20% the TRIR that we had last year. We are performing really well on that side, and I'm gonna tell you a little bit of that, afterwards. In terms of diversity and inclusion, probably a very high goal that we have set for us during this year is to achieve the Friendly Bee Certification. That is basically a certification that would show that as a company, we guarantee for our employees a gender discrimination-free environment. This is very important because it will complement another award that we have, that is the Equipares Gold Seal, that I'm gonna talk about it a little bit more in the following slide. Finally, in terms of our community engagement, the way we relate to our community is not only caring about our community in a very empathetic way, understanding their needs, but also how can we work with them. In terms of local goods and services, we have set an important goal of buying $41 million from local suppliers and providers in our regions. I'm also going to talk a little bit about how we're doing on that component. Finally, in terms of the governance part, I already mentioned our being recognized as one of the most ethical companies in the world, but also the two good things that we're doing is we are integrating ESG risks into our macro processes within a company. That's important. It's also one of the main priorities that we have, and we've been working during the last year, and that we'll continue to work during next year. Finally, we have set for the first time to maintain a rate zero of material cybersecurity incidents. It is the first time that we have included a cybersecurity goal in our operations. Well, now coming to the environment. As I was telling you, what are we doing in climate action? In 2023, we are going to have our first solar plant for the consumption of CPE-6, for the energy of CPE-6. The plan is that the plant is going to produce or generate around 11 gigawatts per hour and will reduce close to or more than 8,000 tons of CO₂ emissions per year. We have started already the development of this plant, and it should be working in 2023. In terms of something that we did towards the closing 2021, and that we have seen the reduction of emissions during 2022, is that we decided to migrate the thermal generation that we had in Termo Petróleo to the national grid in order to get the energy that we need for Quifa. This represented a reduction of close to 70,000 tons of CO₂ per year. That's almost 15% of Frontera's emissions as a whole. That's an important reduction in terms of carbon emissions that we got. Only during the first semester, we got those 70,000 tons reduced. In terms of the performance, we have neutralized already 52% of our total emissions, and we plan to neutralize close to 52% by the year-end. We will be 2% above the goal that we have set for this 2022. In terms of water and sanitation, I'm going to talk at the end a little bit more about SAARA project that Ivan already spoke to us. Probably if we see not only what we are doing this year, but the quantity of hectares that we have protected during the last four years is 2,600 hectares. This is very important because what we are trying to create, as I was telling you, are strategic corridors for the mammals to move around the areas where we operate. This is, of course, coordinated with both the regional authorities, but also the Ministry of Environment or it's part of this strategy. I would close our E part, our E factor, by highlighting two things that Renata mentioned. The first one, our clean transportation project, pilot project. Why is this important? Because we are incorporating to a way of trying to improve the way we move with cleaner energies. What we are doing is that we are introducing natural gas into some of the trucks that we use for our hydrocarbon trucking, and we are also using electric cars in our operation. Again, this goes to reducing the emissions that we have as a company, but also it helps us to give signals of not only improving the type of carbon emissions, but also air quality in the cities or in the areas where we operate. If we look at our net emissions per barrel, this, thanks to the change that we've made, that I've commented, in Quifa, we will have close to 10.7 kg of CO2 emissions per barrel in 2022. That's a big reduction as we can see. Of course, this responds to a strategy of reducing emissions, but also always looking at a cost efficiency energy perspective, from our energy team. This shows the neutralization that I was referring to in terms of the scope two emissions that we have as a company. Well, now let me come into the social part, the social factor. In terms of, I'm gonna start with health and safety, because if you see currently our TRIR, our TRIR, it's 0.99. That's the lowest TRIR that Frontera has ever reported as a company. This is important not only because our goal was or is 1.4 for the year-end, for the whole 2022, but also because we are showing that we are decreasing that number by an important factor. We have here a culture that we have in Frontera is to operate in a responsible way. That's part not only of the team that is responsible of the HSE, but it's part of the company behavior, and that's something very positive that we are committed to as a company as well. In terms of maintaining our zero fatality rate in its operations, as we've announced in 2021, in 2022, we continue to be a zero fatality operation, not only with Frontera directly, our employees, but also our contractors and the people that we work with. Well, in terms of diversity, inclusion, and equality, we got awarded in 2021 the Equipares Gold Seal. What is the Equipares Gold Seal? The Equipares Gold Seal is a gender equality, a recognition that is given by the United Nations, the Ministry of Labour, and the Presidency of Colombia because they recognize that companies have taken actions in order to be more inclusive and to guarantee an environment that has gender equality for its employees, but also for the companies, or for the communities where it operates. This is very important because it's the only oil and gas company in Colombia that has got this award. This started four years ago. At the beginning, we had the bronze seal, then the silver seal, and only last year we got to the gold seal. It is something that we've been doing during the years, trying to be more inclusive in terms of gender and diversity. Now, in terms of community engagement, we invested $4.7 million in more than 164 initiatives in Colombia, Ecuador, and Peru during 2021. Our objective for this year is a similar number. Something very important is that I was telling you that the way we obtain our license to operate is by understanding the communities where we operate in an empathetic way. Our strategy is called Genpathy. That is generating empathy in the areas of influence and with our stakeholders. These help us. The way we do it is by working with them, but also by complying with social investment in three particular areas where we have identified that we can have long-term value creation for our communities, and those are education, those are social development, inclusive social development, and quality of living. Those are our three lines of investment that we have prioritized. In terms of our local goods and services purchases, we have purchased already $32.3 million during the first nine months of the year, so we should be fine. Actually, we know we're gonna be able to comply with the $41 million goal that we have set for this year. Another very important thing is that we are working with local suppliers, with local companies to help them improve the way they're doing it to strengthening their entrepreneurship capabilities, because in order to work with us, they need to comply with some criteria, and we have prioritized around 100 of these companies, and we're working with them to improve the levels at which they operate in order to be able to work with Frontera and with other companies that operate within the areas where we are present. Finally, in terms of two programs that we're working with our communities, T That is basically creating local entrepreneurship within indigenous women in our regions, actually in Puerto Gaitán, where you will be visiting tomorrow. All those baskets were made by them, and we not only support them in terms of what they do, but also helping them to come to the market, to come to the cities and be able to sell their products in other cities. Well, finally, in terms of governance, we have been recognized as one of the most ethical companies in the world. As I was telling you, we are integrating our compliance standards within all the companies like Puerto Bahía, not only Frontera Energy, but we're working with other companies to comply with the same levels that we have in Frontera. Additionally, we are progressing in the execution of our ERM risk strategy to involve ESG factors. This has meant that we are revising all the macro processes that we have in the company, and we are integrating ESG risks to those. That's something very positive because the whole company is involved in what we are doing. We are also trying to include some ESG criteria in the way we decide how we develop our operations and the different projects that we analyze from a capital expenditure perspective as well, looking at our ESG impacts and the ESG benefits that we can create. Finally, our cybersecurity strategy to maintain a zero rate without loss of information and financial losses. We are still good with that, with that goal, and we are complying to that goal. Well, in terms of what Iván told you, in terms of what we do in SAARA, what we must tell you is that SAARA is aligned with Frontera's ESG strategy all the way. Basically, since we structured the project, what we are seeing is that we are working in terms of creating local employment. We are doing it with SAARA in terms of trying to generate a circular economy within the region, but not only impacting the water that we use, but making sure that we are taking this water to palm trees. That is also an important economic activity within the region. With the same project, we are not only helping the hydrocarbon sector in terms of water use, but also we are helping the palm oil industry in terms of the water that they will be using that will be coming from this operation, from this SAARA project. In terms of energy consumption, what we are going to be able to see in our pilot is to see how we can reduce the energy that we are using in SAARA, and probably that will also help to reduce the carbon intensity that we have as a company. Those were the main aspects that we are developing in terms of our ESG strategy. We are committed as a team in the way we are doing it, in the way how we operate. This is a commitment not only by an area in charge of responsibility, by everyone in the company, because this is a strategy that goes all within the different areas of the company, from operations to transportation. We are all looking at how can we do it better from an ESG perspective and from an operational perspective. Thank you very much. Sure. Do you have? Everyone wants a break? It's been a long day. Okay, let's do a break. What time is it now? For those in the West, we're taking a 15-minute break. See us at 3:30 P.M. Eastern and Bogotá time. All right. Welcome back. MIvány name is René Burgos Díaz, and I'm the Chief Financial Officer of Frontera Energy. Okay. I have some prepared remarks. Please feel free to kinda interrupt me as we go. Hopefully, we'll get through this very quickly. Thank you very much for being with us here today. I know this is your favorite section. I know you all of you have been waiting for the final sections to start. For those of us still online, thank you for joining us. Please get your last cup of coffee. We're almost done. For all those here, thank you very much for coming. Some of you came from very far distances, so again, we appreciate you guys making the trip. Please, no more coffee trips. We're almost done, I promise. Throughout the afternoon, we laid out the investment case for Frontera Energy. Today, our chairman has reiterated our board's commitment to shareholder value and the significant upside related to our onshore oil and gas assets, our expanding midstream business and our high-impact exploration program in Guyana. Our CEO shared our core focus areas and a vision for Frontera into the future, including a path to 50,000 barrels a day of production. 50,000 barrels a day of production. Our team very eloquently laid out the details supporting our investment case and our excitement behind several key initiatives, including the expansion of CPE-6, Quifa production increases, our integrated water management project in SAARA and ProAgrollanos. Again, like Andres mentioned, this is a key initiative that aligns well with our ESG goals. Our onshore exploration portfolio with over 550 million barrels of net prospective resources, our expanding midstream businesses generally generating roughly $50 million a year in cash flows and their related upsides. Of course, our high-impact exploration program in Guyana. All these efforts were made possible by our focus on a sound financial policy, a strong balance sheet, a relentless commitment to efficiency as mandated to our board. In a moment, I'll give you a quick overview of our key financial metrics. First, I would like to take a few minutes to speak about the recently passed tax reform. Orlando, please help me here to fill any gaps. The components with the largest impact in the tax reform to producing the barrels to be paid as royalties to the government. For those analysts in the room, today, we roughly pay around 2,800 barrels a day in royalties. When does the tax reform take effect, and how? This tax will take effect for tax year 2023. Payments to the government as is customary actually happen in April 2024 as we actually make our tax filings. At the same time, from a financial standpoint, you will see the accrual of income taxes throughout 2023. There also is the cash holding taxes that we do pay. If you have any other questions, our tax expert is right here, glad to actually pitch any questions up to him. Depending on oil prices, and this is the chart that you see right here. What does this mean for Frontera? Depending on oil prices, we could see tax payments equivalent to around $2-$4 at a Brent price of around $80, $6-$8 at $90, and over $9 per barrel cost for us at a price of over $100. Let me just pause here for any questions. Yes. Could you elaborate a little bit more about the range? Why there is a range for at certain oil price? The oil price is I mean, like for instance, for $80 oil, you know, at $80 oil, you have between $2 and $4. What would be? Here, right? We're saying if the average price next year is $80, you would expect that our income tax bill for the year will be equivalent to $2-$4 per barrel oil produced. Yeah. Why there is a range? I mean, it's a tax. You could think about the tax as a fixed number. Why there is like substantial range between? Oh, why the substantial range? Yeah. The range is more to do. There are, you know, timing differences in taxes that we do pay. There's also taxes related to tax credits and other matters that we do manage to optimize our tax base. That is why the range is there. It's us optimizing for effectively a tax bill. Does that answer your question? Yes. Thank you. Good. Any other questions? Yes. Is that a calendar 2023 impact, or is that a run rate impact post-tax reform? That is a full year 2023 impact. Got it. The run rate would be higher if we look forward, or is it the bill is retroactive then for all of 2023? Like, I don't understand your question, sorry. Is the tax reform taking place such that this applies to the full year of 2023? That's right. Okay. Got it. This is assuming our full 2023 production, and again, we pay taxes at, you know, once the end of the year happens, the government will publish the benchmark by which this tax surcharge is calculated. We won't know exactly the number up until the end of 2023 in January when that actual benchmark is published. Right? Throughout the year, we're gonna make an estimate based on where we see oil prices. I think I hinted anything over $82, we get hit with 15%. Between $82 and $75, we get hit with 10%. Between $60 and $75, then we get hit with the 5%. Right? We are accordingly gonna be making the, you know, the accrual for these taxes to be paid, but the cash impact net of any withholding taxes that we paid throughout the year will be felt in April of 2024. Yes. Yes. I had a quick question too. Sure. On the constitutional challenge on the non-deductibility, if the court rules like in your favor middle of next year, how does that impact like the accrual and the royalty payment kinda calculation for the rest of the year? Maybe Alejandra can help me here or Camilo can help me here. I would say if it's an unappealable. Song is laughing at me. Huh? Yes. If a decision is final and unappealable, then it happens before we actually pay the tax, then we don't pay the tax. That's the answer. If it happens after, we pay the tax then, and we'll have to kinda get it back. Hi. Hi. Okay. Just to clarify, you were saying that this ten-year average Brent is moving, that would be defined, I mean, the 82 would be defined on 2023, and once a year, that would set the benchmarks, right? In January, we will get the benchmark. In January. I think that for this year, Camilo can correct me. I think with a lot of kind of certainty. Right. So long as this reform continues to be in place, the numbers that I share with you should be ballpark what they are. Okay. They shouldn't necessarily kind of move significantly, right? 'Cause you're taking ten years worth of changes in oil price to determine these the percentiles. These brackets. that you see here on your left. Okay, perfect. On the non-deductibility of royalties. Yes. --You mentioned $2,800 in royalties in kind. Just to understand the cash payments, are you thinking of it only in base royalties? I mean, in terms of the non-deductibility impact and how much of these ranges that you're putting in terms of total income taxes comes from the surcharge and the estimate percentage points that come from the non-deductibility. Look, what I would say is the lower you go, the less relevant the amount of deductibility is, right? Like, so the higher you go on oil price, clearly, the bigger the impact related to the tax reform and the tax bracket, right? Mm-hmm. The 5%-10% and the 15%. The higher you go, the lesser the impact of that royalty. I think the number is more or less, if you think about the $90 barrel oil scenario, and correct me if I'm wrong, I think it's two-thirds, one-third royalties. Sorry, royalties one-third, two-thirds would be the tax reform. Yes. Okay, perfect. Thanks. I have three really quick questions. One is, you mentioned that. You get only one, Son. The first one. You said that the Brent prices is gonna be adjusted based on the inflation as well? Yes. Did they say it's gonna be local inflation or U.S. CPI, PPI type inflation? U.S. U.S. U.S. inflation. U.S. inflation. On top of that, you get it. Too is that they do realize that Colombian oil is sold on the Vasconia, the discount, whatever. I forgot the benchmark name. As a result, if the world is short of heavy oil and the discount goes into positive territory as well, heavy oil becomes extremely on top of Brent, and you will make money, but that is a mixed message you can always have in terms of tax payments. Look, that goes both ways, right? Right. 'Cause if the differential for heavier crudes actually goes the opposite way, and actually it underperforms Brent, and the Brent prices actually do tend to inch up, so we have the negative effect. But what you said is also true. If the world of heavy gets, and we've seen it in the past, where you get differentials to actually improve and you outperform the benchmark, then yes, there will be a benefit. Yes. It's something that you'll have to manage going forward as a whole. Look, I mean, we have to manage a lot of things. That's definitely one more thing that we need to manage, yes. Just last one. I have also heard that if you pay in-kind royalties, not in cash, that you may not be subject to this royalty deduction. Meaning, those the one national oil company that pays in cash, not in kind, will be the one that a little bit heavy burden of this nondeductibility. There's no discussion on that part? I did not understand the question. Could you please. Effectively, if you choose to pay in oil for the royalties, as many private companies do as of now, then you will still be able to deduct it. If you choose to pay in cash for the royalties, I don't know why, but I've been told that there's one company, one very large company that does it, then you will not be able to deduct that. You get- Look, actually, for us, 'cause I don't wanna speak for anybody else, I think 95% of our royalties are in kind. It also has to do with the proximity to some of our production to actually put into entry points for transport. What I would say, moving forward to next year, I believe 100% of our royalties are gonna be paid in kind. I don't see that impact, and I think the impact of this applies to both in kind and in cash. The non-deductibility, now it's cash or in kind, you're still gonna suffer from this impact. Camilo. Yes. The reading that we are, you know, doing to the legislation is that it will be applicable for both in kind and in cash. That's the reading that most of the companies are having of the draft legislation. There's no difference. I promise this is not the last chance. After we drink a couple of glasses of wine, we can talk more about tax reform. I wanted to give you the space to actually talk about the tax reform. Does anybody else have any more questions? All right. You know, with tax reform behind us, let's move on to some of our key financial metrics. A quick glance of Frontera continues to show a very healthy balance sheet with a 0.3x net leverage and 20+ times interest coverage. We have maintained a high level of unrestricted cash at over $200 million as of September. These balances have been supported by the current oil environment and despite our ongoing shareholder value initiatives, which include $80+ million in share buybacks through September 2022. From a debt standpoint, and excluding our unrestricted subsidiaries, we have only one bond. Our $400 million senior notes issued in 2021. These bonds currently trade at, you know, are in the high seventies. As we shared in our last conference call, we believe these levels are attractive, for us to start considering a buyback. Today, the company is rated B+ by S&P. In August, S&P upgraded our outlook to positive, which we believe recognizes some, but not all, of the efforts that we're discussing here today. Also, we have a B credit rating from Fitch with a stable outlook. All this to say that financial health and discipline is one of our core focus areas, as Orlando pointed out, and helps shape our forward path. Now diving into some of our key numbers. There we go. You probably are very familiar with this chart. This chart is in our package every quarter for investors. As Orlando, you know, spoke earlier about this, he spoke about this part particularly or the part that actually impacts this part right here, which has to do with the reduction in fuel cycle cost, OpEx transport development costs. On this side, you can see particularly the important reduction in development CapEx. We see it right here, this 344 going down to our 144. This is year-to-date, so the run rate will be higher than 2021. The second, it's our production, albeit reduced, continues to generate significant cash flows, as you can see also in this chart right here. I wanted to actually share a very tangible example about our strategy and why our strategy is working. If you look at 2021, and you compare 2021 with 2018, the similarities there are 2021 and 2018 both had around $70 Brent average for the year. Yet in 2021 we produced around 71,000 barrels and generated an EBITDA of $413. That compares with 2018, in which we produced 38,000 barrels but generated an EBITDA of $373. Again, reduced OpEx, reduced transportation costs were the key. Over that time period from 2018 to 2021, even though the difference in EBITDA is around, you know, $50 million, what I can point out is that we had $3 in savings, probably 40% less production, and our G&A also dropped by about $40 million. Again, our strategy is working. All this has been driven by our board-mandated discipline. We just recently spoke about our G&A. To dive further into the numbers, our G&A is another area of key focus. We reduced our costs on average 15% per year since 2018, and today our G&A per barrel is solidly below 3. Similarly, we have seen success in our ability to deal with our portfolio of commitments and contingencies. Following the restructuring, Frontera had in excess of $3 billion of these commitments, and today these numbers are around $600 million. Most notably, as we mentioned during Renata's presentation, we were successful in reaching a settlement related to our Bicentenario and Caño Limón pipeline commitments. These were finalized in 2021. Today we can actually say that we have rightsized our transportation commitments. Again, this is possible thanks to the relentless commitment and focus of the team. I wanna spend a few minutes on our hedging strategy. This is a key area of focus for us as well and where we get a lot of questions from investors. Given the lack of consistency of where oil is, I think this is, you know, very important for us to kind of touch on this. Our strategy actually very simple. We manage exposure to oil prices while not limiting the upside. Our goal is to hedge between 40%-60% of our production, and the goal is to protect our key CapEx activities for the year. Unlike some in our industry who perhaps hedge on a less frequent basis, we are continually monitoring the hedging market and opportunistically looking for opportunities to layer in hedges when the cost makes sense to us. For 2023, we began our hedging program and hedged roughly 15,000 barrels for January at a price of $80 per barrel. This is an update from our conference call that we had with investors, where we actually hedged half that amount. The certainty that our hedging program provides allowed us to effectively plan our capital programs this year. Speaking of our capital program, I would like to briefly touch on our guidance for 2022. As we communicated as part of our third quarter results, we remain on track to meet our 2022 guidance targets, including EBITDA, production, and production cost. Looking forward, the team continues to work on its 2023 plan, and we expect to share an update with the market in due time. While I can't provide many specifics now, as we're still working through it, I can tell you that a few key themes are top of mind for me and our team regarding potential impacts on 2023, including upward inflation pressures, mitigating in part by the recent performance of the Colombian peso. I believe these themes will continue into 2023, and we encourage you to consider them as you start updating your models and forecast. Brent will be glad to take your call on these ones. If not Brent, you can talk to Claudia. With that, I would like to conclude by reminding some of the key points that you heard from the leadership team and me today. First, Frontera benefits from strong upstream EBITDA margins and cash flow capacity. We also have a flexible balance sheet with significant cash on hand. We are financially disciplined and have a robust balance sheet. We have proven that we have the ability to quickly adapt to different industry cycles while maintaining conservative leverage. We also have an active hedging program which protects the revenue generation while maximizing upside. We're also relentlessly focused on driving out cost of the system and improving efficiencies, and this won't change in 2023 and beyond. With that, I'll pass it back on to Orlando for his closing remarks, unless anybody has any questions. Thank you, René. I think I'm going to be brief here to close the session and open up for Q&A. I basically want to finish here with the slide that Gabriel showed at the beginning of the presentation. It is just to reiterate some messages which I think René also covered at the beginning of his presentation. First of all is value over volumes works, has worked, and we are continuing to focusing on that. We are seeing a future of the company in 2024, 50,000 barrels of oil equivalent plus in 2024. That is coming mainly from managing water in Quifa, CPE-6, VIM-1, the liquids-rich natural gas assets, and Ecuador. That without excluding the exploration opportunities. That is the number one message is a production of 50,000+ in 2024 coming from those four main assets. Again, CPE-6, Quifa, managing water injection in Quifa, Ecuador, and VIM-1, and our liquids-rich natural gas assets. That is number one. Number two, we should continue building in our marketing logistics muscle of the company, optimizing our cost structure, driving efficiencies, further efficiencies into our cost structure. I think that is number two. No? We will continue focusing on that, being very efficient in our costs. We should continue on that path. Third, near-field exploration in Colombia and Ecuador. More than 500 million barrels of oil equivalent in resources, in prospective resources. No? 500. 50,000+ production, more than 500 in prospective resources in our near-field onshore exploration opportunities. Guyana still a significant part of what we are doing. That is a transformational opportunity for the company. We are looking forward to drill that well and see how we are moving forward afterwards. Our midstream assets, we have made a lot of progress on that to make a self-sustaining midstream business with ODL and the things that we are doing in Puerto Bahía. Simplifying the story, again, bringing efficiencies into our operation, returning capital to our shareholders, more th.an $290 million through dividends and share buybacks. To continue developing that story, ESG story that we have initiated last year. That's the summary. I mean, that is what we started, that is what we are beginning, that is the messages that we want to convey to you today. That is our focus of all these people that you have with you in the room, the management team of this company. This is our mantra. We are going to keep going and continuing on this path. That's it. That's it for today. Q's and A's. We are open to questions. You have asked a lot of questions already. We wrote them down. Huh? We wrote them down. Yeah. Well. Okay, I'm not gonna let you off. Okay. You go first. That comes with a Twitter as well. That's it. Hypothetically speaking, let's say Wei is a prolific success, the next Liza or your Liza, let's say that. And if you wanted to try to scale to first production in f years, let's hypothetically say that you farm out 50% of the asset and you maintain 50% working interest. What do you believe your cost of capital would be for funding that type of expenditure on a development program? The cost of capital. Look, I think we continue to refer to Guyana as high impact, and this is a company changer. Right? This would mean that we're not only a Colombian oil and gas business with 160 million barrels of oil. Right? We're talking about a platform for growth that has multiples of that. That would certainly change the way that we think about our capital raising and also our funding. It's a little bit premature for us to say that because the markets today, they're what they are. They're sending you a signal, right? You can see where oil and gas peers here in Colombia, where their financing rates are, particularly because they're scared about government reforms and the tax reform that I just explained. We will no longer be a Colombian oil and gas lone company. We'll be a pan-Latin American with very accessible barrels that are in a prolific basin. I would ask for patience as we develop this story because this would literally transform our company. That's the best answer that I can share with you right now. I mean, I just say that because obviously the development would be multiple times your market cap right now. Again, that becomes a big question. It's like how much can you afford to hold on to and still meet those capital calls? That's a very nice problem to have. It's a very nice problem to have, yes. That is everybody here who also equity will be like, "Sweet. You know. Well, everyone is looking, they got their spreadsheets, so we wanna know, you know, the borrowing limit. Talking to Christina in the break. I mean, we are also very excited about Guyana. I mean, we want to. I mean, we look forward to what we with Wei and what is next. We need. I mean, we cannot jump ahead, no. We need to see how Wei goes, be ready for that, be prepared, doing activities, I mean, for a success case, which is what we are expecting to have. The offshore development is, I mean, has to be through phases, no? That is not a near field development. We share that excitement. I mean, we share absolutely that excitement that you have shown, Christina. I know people in the room feel the same. It would be a different company having a success in Guyana. Oriana. Yeah, maybe looking beyond Guyana and for 2023. I understand that you might already be working on your 2023 budget, but just if there are any ballpark estimates, guidance in terms of how we should see CapEx moving? Also taking your comment in terms of inflationary pressures. If there's anything of relevance that you could share with us in terms of how we should think for 2023, and where the investments are gonna be focused, aligned with the updates shared from the exploration side. It is too early, I mean, to talk about the 2023 plan. We have been working hard on that. Actually we have been doing a lot of planning since August. I mean, to try to cope with those inflationary pressures and try to anticipate and start buying things for the plan next year. We haven't published anything yet. I would say, I mean, you see the production levels that we show for 2023, no, with base plus the exploration upside. That is already there. I mean, indicated there. The investment would be around what we have been talking about, CPE-6, Quifa water injection, some activity, drilling activity in Quifa, increasing water capacity injection in CPE-6, Ecuador being one. That's the type of things we are concentrating on, no? That is what you will see in the plan. We haven't published any guidance yet for next year. What I would add is we certainly have put some cookie crumbs for you guys to kinda just follow. The other thing that I would add in, and this has to do with our financial discipline, right? We have a lot of exciting projects, but we are being very strategic in how we invest that capital. You need to blend both those things to start kinda thinking how we, you know, kinda start forming that 2023 plan, which he highlighted. I think you have production-wise, you can look at the graph, which is already that cookie crumb number one. Then you can look at some of the projects that we're talking about. You can look at what we've done in the past, and it will be consistent with what we've done, just with the whole concept of strategically investing in projects that add the most value to our investors. Another general comment on that. I think with the intent also of the presentation today, Oriana, and that's why we put a lot of emphasis on the exploration, is that we also gave you guys a hint, right? That we are drilling several wells kinda like right now, right? The outcome of those wells will also, right, to some extent, right, make us look at, you know, what else, if anything, do we need to do on top of what we have been thinking about. In the right price environment and with the right conditions, yeah. I'd say I think also another view that we share with you, right, from the exploration side. Mike. Yeah. I know you've got your plate full in Guyana right now, but do you plan on being active at future licensing or bid rounds in Guyana, or is that something that's pretty unlikely? We haven't considered that. No, we are concentrated on current year. Yes. Okay. That's it? Very good. Thank you very much. And-