This morning, we will discuss the Guyana-Suriname Basin, the Corentyne Block, and the joint venture's integrated well results. My name is Brent Anderson, and I will be the moderator for today's presentation. This presentation is scheduled for 60 minutes. After the speaker's remarks, there will be a question and answer session. This morning's presentation has been posted on CGX's and Frontera Energy's websites, and a recording will be available through the website later. Next slide, please. Next slide, please. I'm changing the slides. While that changes, I'll run through the forward-looking information. This call contains forward-looking information within the meaning of applicable Canadian securities laws, relating to activities, events, or developments the joint venture believes or expects will or may occur in the future. Forward-looking information reflects the current expectations, assumptions, and beliefs of the joint venture based on information currently available to it. Although the joint venture believes the assumptions are reasonable, forward-looking information is not a guarantee of future performance. Forward-looking information is subject to a number of risks and uncertainties that may cause the actual results of the joint venture to differ materially from those discussed in the forward-looking information. Frontera's annual information form for the year ended December 31st, 2022, and CGX's and Frontera's management discussion and analysis for the year ended December 31st, 2022, and quarter ended September 30th, 2023, and other documents filed by CGX and Frontera from time to time, security regulatory authorities describe the risks, uncertainties, material assumptions, and other factors that could influence actual results, and such factors are incorporated herein by reference. Copies of these documents are available without charge by referring to each company's profile on SEDAR+ at www.sedarplus.ca. All forward-looking information speaks only as of the date on which it is made, and except as may be required by applicable securities laws, each of CGX and Frontera disclaims any intent or obligation to update any forward-looking information, whether as a result of new information, future events or results, or otherwise. Can we move to the overview slide, please? To begin this morning's presentation, I'd like to provide a quick overview. CGX Energy Inc. and Frontera Energy Corporation are joint venture partners in the petroleum prospecting license for the Corentyne Block's offshore Guyana. CGX is a Canadian-based oil and gas exploration company focused on the exploration of oil in the Guyana-Suriname Basin and the development of a deepwater port in Berbice, Guyana. CGX is proud of its long partnership with the government and the people of Guyana and its reputation as Guyana's indigenous oil company. Frontera is a Canadian public company involved in the exploration, development, production, transportation, storage, and sale of oil and natural gas in South America, including related investments in both upstream and midstream facilities. Frontera has a diversified portfolio of assets with interest in 27 exploration and production blocks in Colombia, Ecuador, and Guyana, and pipeline and port facilities in Colombia. I would now like... Next slide, please. I would now like to introduce members of the joint venture who will be leading us through today's presentation. From CGX, we have Dr. Mark Zoback, a member of CGX's Board of Directors and Senior Technical Advisor. Mark is a professor of geophysics at Stanford University, emeritus, author of two books on reservoir geomechanics, and founder and chairman of Geomechanics International, a consulting and software company sold to Baker Hughes in 2008. And from Frontera, we have Regan Palsgrove, Head of Exploration. Regan has more than 33 years experience in numerous North and South American basins, including with Chevron Canada, Talisman Energy, and several smaller companies. She has led Frontera's exploration team, working in the Guyana-Suriname Basin for the last six years. We are extremely fortunate to have such deep technical knowledge presenting to us today. With that, next slide, please. With that, I'd like to turn the presentation over to Mark. Well, good morning, everyone. It's a pleasure to meet and bring all of you up to date. There are four main highlights in this presentation. First, as you know from previous press releases, there have been material discoveries after drilling both Kawa-1 and Wei-1. The well results together confirm the prospectivity of the Northern Corentyne Block. We have proven oil charge, excellent reservoir in Maastrichtian, and it's justified a new focus on that age of formations. There's been significant de-risking and a growth of the block prospect inventory. These discoveries, as you will see, are contiguous and on trend of discoveries by Exxon in the Stabroek block and by Total, that's operating in Block 58. The northern area is on trend with the significant discoveries in both blocks. What you'll hear today is we believe the Maastrichtian volumes underpin the potential commercial development of Maastrichtian aged resources. The prospective resources are estimated to be between 514 and 628 million barrels of oil equivalent, and that's the PM ean estimate of four separate analyses, two of which were carried out by independent world-class resource evaluators. Now, we're gonna use the term prospective resources a number of times through this presentation, and as defined in the Canadian Oil and Gas Evaluation Handbook of 2022, prospective resources are those quantities of petroleum estimated as of a given date to be potentially recoverable from undiscovered accumulations by applying future development projects. The lower drilling time and cost of the Maastrichtian wells are certainly an important factor, and I will point out that the drilling of Wei benefited greatly from lessons learned in Kawa, and that drilling went extremely well. We'll introduce the potential of this Maastrichtian play in, you know, as the presentation goes on, and a conceptual development plan is currently underway. That's with Subsea 7 and Schlumberger. We also believe that there's considerable upside and potential for future development in deeper intervals. That is, the Campanian and Santonian, we think offer additional opportunities which are not quantified at this point. There are movable hydrocarbons proven in the Campanian with easily mappable and thick channels, as Regan will show you. Next slide, please. The text on the left is a fairly good summary of where things are today. You know, Frontera and CGX are the JV partners. You're all familiar with that. We've drilled two wells, Kawa-1 and Wei-1, in January 2022 and June 2023. They're shown on the map in the context of the regional discoveries. The Maastrichtian Resource Assessment, as I said, has been completed by two independent world-class resource evaluators, and the conceptual development is well underway with Subsea 7 and SLB. So we have this sizable resource, sizable area. It's in an extremely active and productive basin, and it's part of both the Golden Lane and, as you'll see shortly, the Silver Lane that's been defined in the region, and we're focusing today on the Maastrichtian reservoirs. Next slide, please. So I want to take a few minutes to explain this slide. It's kind of a zoom in on the Corentyne Block, and the first thing to point out is that the Wei-1 and the Kawa-1 are on trend with the wells, both to the east and to the west, and consistent with what we're finding just to the north. Now, you're probably familiar with the term the Golden Lane and the Silver Lane. Initially, the Golden Lane referred to the wells further from shore, out in deeper water, and the Silver Lane referred to the discoveries in the wells that were more inboard. So it was initially sort of a geographic definition, but over time, that definition has changed because the Golden Lane was, in fact, consistent with discoveries in the Maastrichtian and Upper Campanian, of which there's an estimated 11 billion barrels of oil equivalent. And the Silver Lane was pretty much consistent with being on trend with the lower Campanian and Santonian discoveries. However, these definitions are sort of merging, and what we're referring to in the title of this slide is the convergence of the Gold and Silver Lanes. So let me give you a couple of examples. The Lau Lau well here, which reported discoveries in the Maastrichtian and the Campanian, would, you know, previously be called part of the Golden Lane, whereas the Maka Central well over here to the east is associated with Campanian and Santonian discoveries, and would have been considered part of the Silver Lane. However, our wells, like the well her Lukanani well off to the west, has both Gold and Silver Lane characteristics, in that we believe there's prospectivity in all of these horizons and not, you know, not limited by the geographic position of the wells. So we're quite excited about these resources. I'm gonna turn it over to Regan at this point, and she'll dig into some of the geologic details. Thanks, Mark. Good morning, everyone, and thanks for joining us. Today, we're gonna update you in detail on the results of Wei-1, but also on the implications of the results of both Kawa-1 and Wei-1 and how they influence our view of prospectivity of the block now. Now, this is a technical webinar, so I'll be talking about things that for the non-technical listener will seem quite complex. So I'm gonna do my best to explain things in a really simplistic manner as best I can, while hopefully giving the more technical folks what they wanna hear. So the figure in this slide is a seismic line, so that's like a slice in the earth, and it stretches from block boundary to block boundary through Wei-1 on the left and Kawa-1 on the right. The wells are 14 km apart, and the sticks below the wells show how deep each well went. I've put the ages of the rock layers on the seismic as well. These are subdivisions of the Cretaceous period. You should be able to see some layers on the seismic. These represent rock layers. Some are continuous, some are not. I drew on top some yellow lines. These represent sands, which are potential reservoirs. The yellow lines that intersect the sticks are ones that we actually observed in the well, while the ones in between are interpreted from the seismic. That said, seismic can't see everything. For instance, the sands have to be thick enough to pop out on the seismic. You can find a thin sand in a well, but not see it on the seismic. Now, the dots on the wells represent pay. Black circles are log pay, and black dots are pay with MDT samples. Note the annotation on the side of the seismic line, Golden Lane and Silver Lane. As Mark said, the moniker Golden Lane refers to a trend on a map, certainly, but it also refers to an interval of rock in which most of the discoveries are made, which for the Golden Lane, it tends to refer to the Maastrichtian and the upper Campanian. The term Silver Lane, you don't hear so much, but people use it to describe a trend closer to shore, and the discoveries from this area are usually from the deeper zones, like the lower Campanian and Santonian. The results of our two wells, as Mark said, indicated kind of potential from both trends. So Kawa was a really exciting well. As a first of its kind to be drilled on the slope, it definitely posed some special challenges, and as a result, we didn't get as much data as we wanted to fully evaluate the well. The data we got was very good, but we would've liked more. But despite that, it did give us enough information to know that we were involved in something really exciting and worth following up, and I've summarized that on the right side of the slide. So, you know, number one, we proved reservoir presence on the block, with porous sands found in the Maastrichtian and Coniacian. I mean, the Guyana shelf had been extensively drilled, and the deep water, but nothing really in that in-between area, so this was truly an exploration well. Also, at Kawa, we found indications of hydrocarbons throughout the Cretaceous, with oil and gas shows and 228 ft of log pay. Even in the deepest, hottest part of the well, more than 21,000 ft, we found oil in the annulus mud when the well kicked. So we definitely proved a working petroleum system on our block. At Kawa, we proved up some of our geological and geophysical models and got data that modified others. And lastly, we acquired some critical pore pressure data that we could use for future well design. Which brings me to Wei, the next well, on the left-hand side, right here. In this well, our learnings from Kawa were applied, and so with a better well design, we were able to get the data we needed to evaluate it, as well as Kawa and the prospects in between. This included crucial rock data from the core, fluid data from MDT. So now we could prove hydrocarbon charge into the block and also had the proper reservoir to calculate a resource. We did prove up some geological and geophysical models and learn from others, but I think most importantly, we defined a clear path forward, and that's what we're gonna spend most of our time talking about today. So as we go through this today, please remember this is a two-well drilling program, including a dual exploration appraisal well. So the well results are very closely tied, and so as a result, you're gonna hear me jumping back and forth between Kawa and Wei as I discuss the results and implications of the results from both wells, top to bottom. The biggest learning from our program was the prospectivity of the Maastrichtian on our block. In fact, taking the learnings from both wells, we now know that the Maastrichtian is what we will be focusing on going forward, and that will be the bulk of the conversation. So what has changed? What do we know now that we didn't know before? Take a look at the box on the right. I'm gonna be talking about each of these points today in a fair amount of detail and, and in order, seen here. So you can consider this sort of a table of contents going forward, but let me summarize it now. To begin with, we now have confirmed we're in the right geologic setting. It's the same as the significant Maastrichtian discoveries north of us in Stabroek Block. We know we have good reservoir in the Maastrichtian. Yeah, we only got a thin sand at Wei, but in Kawa, we got a very thick package of stacked sands. We know now the Maastrichtian is mappable. Those sands at Kawa are thick enough to be seen on seismic, and you know, there's equally good or better opportunities even elsewhere on the block. From Wei, we finally have actual measurements of porosity and, more importantly, permeability of the Maastrichtian, and with this knowledge, we have been able to compare our logs to Kawa and go back and revisit that. Also from Wei, now we know we have oil charge into the block, and this was probably the most important thing of all. It's taken time to get this data, but now we do have the information to do a proper resource evaluation of the Maastrichtian on our block, which we've done, and we've verified it with two separate resource evaluators. We're really happy with that block estimate, and coupled with the quicker, easier, cheaper drilling of the Maastrichtian, we believe we have enough resource in the Maastrichtian to potentially underpin a standalone development. So let's focus in on the Maastrichtian. Same seismic line. The red boxes on the well sticks show the Maastrichtian interval, the prospective Maastrichtian interval in each well, and they fall within that Golden Lane window that I've annotated on the right here. They sit right at the base of the Maastrichtian. The top of the upper Campanian is right below those sands. Now, there isn't much significance in this particular boundary. It's kind of like going from Monday to Tuesday. You know, other time boundaries do have more significance, this one, not so much. You'll notice some operators reporting discoveries in the upper Campanian. That just means they are discoveries that are slightly older or slightly deeper than what we've got here in our wells. So you often see operators describe their discoveries in this trend as Maastrichtian or upper Campanian, or upper Campanian Maastrichtian, et cetera. So really, we're talking about the same thing. The well logs on either side of the section are displaying what the Maastrichtian looks like in the red box in each well stick. It's easiest to look at this log here, the orange and yellow one. Orange represents shale layers within the earth. These would be non-reservoir, and the yellowy intervals represent sand layers, which can be reservoir. There are also some layers you see that are kind of in a yellowy orange, and they're exactly what you would expect. They're just sort of, kind of sandy. In general, you can also observe that some sands are thin, some are thick, and most importantly, if you take nothing away, they are three-dimensional. A thin sand in a wellbore can thicken away from the wellbore to the right, or to the left, or into the page. Those kind of sand zones can get sandier away from the wellbore, too. Now, the reverse is true. You may find sand in a well, and when you drill beside the well, it's thinner or not present at all, and that could be a dry hole. But luckily, sands tend to stack up in layers. You can see that on this section here. So if you miss in one layer, perhaps another deeper, shallower one thickens up, expected or not. The other comment is, not every sand contains pay. Some will have water. It may never have been filled up or charged with hydrocarbons, or the hydrocarbons migrated through it and just kept on going, perhaps all the way to the shore, and became an oil seep on land. So it's normal to have some sands that have pay and some that have water. Naturally, you're gonna try your best to place your well in a place that has the most sand, the thickest sand layers, and the best chance of trapping hydrocarbons. So what'd we get in the Maastrichtian in our wells? Kawa-1, on the right, got thick stack sands and 68 ft of logged pay in the Maastrichtian, primarily from these lower two sands. They were logged while drilling, which is how we know that they have pay. The logs were good quality, so we know they had porosity, but we couldn't say much about permeability at this point 'cause we didn't have core. And an MDT or other kind of test wasn't run, so we couldn't say definitively at all what type of hydrocarbon was in them. So turning to Wei-1, on the left, we got 13 ft of pay in a Maastrichtian sand. Although sand, though thin, this zone was absolutely critical to unraveling the block's potential because sidewall core and MDT samples were recovered, and excellent reservoir quality and oil charge was proven. Moving to the next point. I mentioned that we, we're in a favorable geologic setting. The geologic setting we envision is on the upper right. It shows what we think Guyana looked like during much of the Cretaceous period. You see an ocean shelf, a slope, and an abyssal plain, or what we also call a basin plain, basin floor. Now, this part looks like a cliff, and it really isn't. It's a lot gentler. This is extremely vertically exaggerated. But the concept's right. Rivers bring sand to the edge of the shelf. It runs down through canyons and is deposited on the basin floor in channels and fans. The process that brings sand to the floor is called a turbidity current. You see a picture of it here, shown in this little inset box, and these are often called turbidite sands and channels. Generally, sand tends to be deposited up on the shelf in rivers and deltas or on the basin floor, and this area in between sometimes is not as sand-prone, and people call it a bypass zone. So let's compare that model to what we see in Guyana. So on the left is a seismic section that runs south to north and down the length of the Corentyne Block from near shore to deep offshore, and I've annotated the Stabroek Block here in red, and this would be - Sorry, this is the Corentyne Block, and this is the Stabroek Block here. Now, because of a confidentiality agreement with the seismic company, I wasn't permitted to show the line on the right side, but I've left the interpretation on. I've annotated on here the approximate position of some of the nearby discoveries on the Stabroek Block, including one that they're drilling just north of us now, called Bluefin. This seismic line doesn't directly tie all of them. I, I believe it's closest to Haimara, but this is the approximate position where they are sitting. Here's a modern shelf edge as it is today, and the modern sea floor, and you can see where we drilled Kawa and Wei is just outside of the shelf edge. It's on the slope. It's in quite shallow water compared to the wells in Stabroek, which are drilled in much deeper water. But in the Cretaceous, the shelf was way back here. You can see it on the seismic, and it persisted like that for millions and millions of years. Same model, though. Sand brought to the shelf edge, carried down the shelf, and deposited in fans and channels on the basin floor. And this is what deposited those wonderful reservoirs of the Golden Lane on the Stabroek Block. Kawa, Wei, and the wells in Stabroek Block were all drilled in the same geologic setting during the Cretaceous, in deep water, far in front of the Cretaceous shelf. That's your Golden Lane. So although our wells and their wells appear to be in quite different positions today, they weren't back then. The sandy reservoirs that were deposited into Stabroek were also deposited in Corentyne, in the same geologic setting. And this is why we feel so positively about the position of our North Corentyne area during the Maastrichtian. Let's take a closer look at the Maastrichtian sands in Kawa. I've zoomed into a seismic line to show you how it fits on the seismic. The well log has been plotted on top. If you squint your eyes, you can see the little sands there, and they're blown up on the right-hand side. There are three blocky sands and some thinner sands on top, and they span about a 600-foot interval, with individual blocky sand packages up to 60 ft thick. The logs show good porosity in here, between 16% and 26%, depending where you are in those sands. The overall sand package is thick enough to be seen on seismic, which means we can observe changes on seismic that are indicative of the presence of sand. If you're not used to looking at data like this, it may not be obvious to you, but it is. What I'll show you in the next few slides is actually when you see these sands, from the top down in a map view, another dimension, that you really see how these sands were deposited. When you have well data, and you can definitively say what sand looks like on a particular seismic data set, it's extremely powerful. You can start seeing the sands thicken and thin on seismic or disappear altogether. So after drilling two wells now and having a lot more log and core data to calibrate our seismic to, we're in a much better position to predict sand, and we were able to create maps at many layers in the Maastrichtian. Not, not just at one, but many, and identify where the prospective sandy areas are on every layer. And we can actually map those turbidite channels and fans. I'm hoping this makes this last point clear. This shows two seismic lines intersecting, and a seismic map has been generated at a single horizon or layer within the seismic lines. Now, we have 3D seismic, so actually, there's a lot more than just two lines. There's multitudes of intersecting lines that have been used to generate this map, and I'm only showing two. I've also annotated the position of Kawa-1 on this map. Now, because we have well data to calibrate to, as I said, now we know what sand looks like on seismic. We can identify what we call certain attributes of the seismic that show the sand best. This is a map that has chosen an attribute to display that seems best for identifying sand, and for the technical folks, it's a Vp/Vs map. So using that attribute, we can automatically generate a map that shows where we think areas of sand are indicated. In this particular map, greens and yellows and oranges, the warm colors indicate sand, and blues indicate shale, shales. So in the corner, near the intersection of these two lines, you can see an area that appears really sandy, and if you look really closely, there's a little blue thing snaking through it. This is interpreted as a shale-filled channel cutting through a sand body. This is a type of thing that shows you the seismic is showing you real things. It's not just an artifact of the data. It's considered geologic context. Now, this particular sand appears to pinch out up-dip. Up-dip is this direction. By pinching out up-dip, I mean it, it disappears up-dip. It thins and disappears. So this is a sand that could trap hydrocarbons. You can see that the sand was not penetrated by Kawa, and in fact, at this particular horizon in Kawa, there was no hint of sand, even though at the other Maastrichtian intervals, there is sand. So this would be a great target for a well, and in front it is, in fact, it is one of several prospects that we have mapped on this block away from our current wellbores. Okay, so the map on the left is a similar seismic map to what I just showed, but this time it's a map over a different Maastrichtian interval. This is a map of the Maastrichtian interval in which we got those sands at Kawa. So you can see where Kawa is plotted on the map, and remember, greens and yellows represent sands. So Kawa should have penetrated sands here, and it did. You can see them over here on this map. Now, this is a map of the top of the sands, and the whole interval is quite thick, so you would see these sands in maps of slightly deeper layers as well. The sands are distributed over a wide area, which is good. Now, we had an experienced sedimentology expert look at the maps with us to try and identify certain depositional features to give it geologic context, like channels and levees and lobes, and you can see his interpretation on the right-hand side. The most obvious thing is a shale-filled channel running through, which you actually to the untrained eye is really quite obvious on the seismic as well. You can see the depositional interpretation he's drawn for us on the right. So the sands are interpreted as channel levees and splays in a deep-water channel complex. As I said before, this adds context to the seismic, and along with the well data, adds confidence that the seismic interpretations represent the rock types that we think they do. Note that on the seismic map, the sand appears to pinch out into a shale up-dip to the south, and this is interpreted on the depositional map as well, which explains why hydrocarbons are trapped in these sands in the Kawa well. As it turns out, there is a large resource associated with the Kawa Maastrichtian sands, and I've annotated with a white dashed line, the area which we've included in the resource calculation, so you get a feeling for size of our prospects. Important note, this is just one of several sands in which we've included resource in our total count. If you look to the northwest of Kawa, you can see other sandy areas that I haven't drawn anything on. This is a separate depositional fairway, and it's associated with other prospects and leads. I'll show you one more prospect on the next slide. So on the left is another seismic map over yet another Maastrichtian interval. This time it highlights an unpenetrated prospect in the central area between Kawa and Wei. It's bright yellow. It pinches out laterally and vertically, or laterally and up-dip into a shale-filled channel, as you can see on the depositional map on the right. The sand itself is interpreted as a frontal splay. Note the position of Kawa. It did not penetrate this central frontal splay prospect. It did penetrate another area that's slightly green. There were some thin sands at this level in Kawa-1, but nothing exciting and no pay at this horizon, even though there was sand and pay at another horizon. Kawa-1 was not drilled in a position to optimize hitting this prospect. However, an important point, looking at both maps, you get the impression that south of Kawa-1, there are good sands with potential pinch outs near the southern edge of the 3D, or maybe off the 3D on the southern part of our land. Now, not every sand on every level is included as a prospect in our inventory. They might only be considered leads. Some have too much risk, for instance, if we aren't sure we can see a trap. Some just need further work, like improving the southern 3D and looking for up-dip pinch outs there on the southern part of our land. Bottom line, the work never stops. Leads can evolve into prospects with further analysis. So what I really want you to take away from these last few slides is the following: Maastrichtian sands are different thicknesses. They can vary laterally and vertically. Thicker Maastrichtian packages are easily mappable. You can see many depositional features on the maps that show your interpretations make sense. Sands are developed at many different levels within the Maastrichtian, not just one. And on each level, the maps will look very different. Sand may be developed in one area on one level, but not in the same area on another level. Some of the sands seem to pinch out, and some don't, and not all prospects are included necessarily as prospects in a prospect inventory. We only picked the very best ones, for instance, to include in our resource tally. So we know we can map these sands. What else do we know about them? We didn't get core in Kawa-1, so we couldn't say for sure what the reservoir quality of the zone was. However, we did get sidewall cores from that thin oil zone at Wei-1. So now we have a representation of what Maastrichtian reservoir looks like and what its porosity and permeability is. The sand in this core is described as clean, meaning it has very little clay in between the sand grains, and that's a really good thing, as clay can decrease permeability to varying degrees. For the technically savvy, the sand is quartz-rich, moderately sorted, and has medium to coarse grains. The sand, this is what the key thing is, the sand is 23% porosity, approximately, with approximately 1,000 md or 1 d of permeability, which is very, very good. A photo of the core, of course, is shown in top center, and if you look really closely, you can even see some porosity and grains in the rough ends of the core. A thin section of the core is shown below the photo. This is a paper-thin slice of the core looked at under a microscope. The white shapes are sand grains, and the blue is empty space between the grains, which is the porosity. In the reservoir, this would be filled with oil. You'll also see the blue spaces are very interconnected. You can just imagine a wiggly line that you can draw between these, joining them all up. As I pass between the grains, these are called pore throats. The fact that we can move between these grains so easily reveals the permeability. The charts on the right just show some of the analysis of this particular thin section, for those who are interested, with one key point illustrated in the lowest graph, which is showing that most of this porosity is good primary intergranular porosity. Now, it's been publicly reported that the giant Liza field in Stabroek Block has porosity of 20%-30% and permeability of 100 md-2,000 md. So it's very confidence-instilling to know that the Maastrichtian sands in Wei have reservoir quality that falls in the higher range of what was reported at Liza, and there is all reasons to expect similar reservoir quality elsewhere on the block, wherever a clean sand is penetrated. So we have revisited the Kawa well with this knowledge we got from Wei. Our porosity at Kawa is within the same range, and seeing as there's usually a direct correlation between porosity and permeability, we believe the permeability at Kawa is similar to that seen in Wei and in the Liza field. So what else did we learn from Wei about the Maastrichtian? In Wei, we did an MDT test. That stands for Modular Formation Dynamics Tester, and in doing so, we got three samples of reservoir fluid, and by recovering those samples to surface, we're able to send them to a lab and definitively find out what type of hydrocarbon it was and what its characteristics were. The samples were revealed to be black oil, with an API of 24.9 and a GOR of 380. We took the extra step of analyzing for any troublesome components, like sulfur or trace metals, and when said and done, there were no problems, and the results showed that the oil can be further classified as a medium sweet oil. By performing an MDT test on the Maastrichtian and sampling oil, we now know that oil has migrated through the Maastrichtian on our block, and it should be present in any reservoir quality sand on the block, provided there is a trap. For instance, an up-dip pinch-out of the sand. With that in mind, looking back in Kawa, we saw a similar signature in the mud gas that we saw going through Wei. Mud gas is by no means definitive for hydrocarbon typing at all, taken in isolation. But considering we definitely got oil in Wei and see something very similar in Kawa, it's a solid assumption that the hydrocarbon in Wei was oil as well, and that it could be expected elsewhere on the block. It's beyond the scope of this presentation, but we also compared other geochemical characteristics of the mud gas in Kawa with the flashed PBT gas and mud gas in Wei, and in doing so, we saw other similarities, which is providing some of the confidence that you're hearing. In this presentation, I've only shown you two prospects in detail, the one associated with the Kawa sands and the one in the central area, and I gave you a little peek of a third one in that first slide, where I described how we map things. But the JV has many other Maastrichtian prospects in the North Corentyne area at various levels in various parts of the block, in addition to those I've mentioned. The map here shows the prospects, as well as some of the leads we have in the North Corentyne area, where we envision a Maastrichtian conceptual development plan. We also have some leads in the older southern 3D and shallow water, which are maturing. Now, the best of these have been included in the resource assessments we did. The assessments were very rigorous and done separately by two independent, third-party, world-class resource evaluators, and the P mean unrisked resources was estimated to be 514-628 million barrels of oil equivalent. Now, this is a really significant number, and the reason I say that is because this is really based just on our high-grade Maastrichtian prospects in the North Corentyne area alone, not leads, nothing in the southern area, and it doesn't include any resources from deeper horizons, like Campanian or Santonian. So that's a great lead into my next slide on the deep zones in Wei-1. After Kawa-1 was drilled, Wei-1 was designed to evaluate all the horizons in which we'd found pay in Kawa-1. This included the Maastrichtian, the Campanian, and Santonian, and to gain information that would help us evaluate not only itself, but also Kawa-1. In Kawa-1, we had log pay and very interesting channel systems in the Santonian but didn't know the permeability of the zones. So Wei-1's location was optimized to hit similar stacked Santonian targets and get some core, as well as it hit an intriguing channel system in the Lower Campanian.... We were successful in those objectives. The exploration models were correct, and we hit thick channel sands, and we got much needed rock data from core. It was very insightful. I designed this slide to give you a good overall summary, and then I'll delve into the details. But after, I guess to summarize, the Lower Campanian, the porosity in the pay zones was 14%, but with the permeability, 1%-6%. In the Santonian, the porosity in the pay zones were 13%-16%, but the core permeability was 1 md-2 md, and most frequently on the low end of that. These are the details of the Lower Campanian reservoir in Wei-1. Look at the seismic and the red box where we penetrated the Lower Campanian seismic anomaly. The box represents the interval for which we are displaying the log on the right. It consisted of a thick, blocky sand, almost 60 ft thick, and a second set of thinner sands above. The sand is pretty much pay top to bottom with average porosity 14%. There were two cores taken from the center of the sand and less clean sand, and may represent the lowest quality in this sand. The MDT interpretation indicated up to 6 md. As we didn't get much core from this zone, a couple inches of representation from sand, almost 60 ft thick, the image logs were very insightful, and they're plotted at the same scale, right, right beside there. They revealed a highly laminated reservoir, and in many cases, very thinly laminated, as I show in the image on the far right, which is a four-foot interval of the core. And that image, sand bodies are light-colored and shales are dark-colored. It's very possible that had Wei-1 penetrated this channel in a more axial position, a less laminated sand with better reservoir quality may have been found. On seismic, the Lower Campanian sand is represented by this green line. It was one of the main targets of Wei-1, and the results did match the pre-drilling model. A beautiful thick channel was found. Look to the right along the line, and you see another one at almost exactly the same level next to Kawa-1. This one was not penetrated by Kawa, but it's a good potential target, and you're gonna see that on the next slide. Finally, in the central area, there are many other channel complexes interpreted at a slightly lower level, right at the Lower Campanian/Santonian border. This is a central complex. We've shown that to you before, and considering our drilling results matched our pre-drill mapping, that central complex remains a viable target with a large potential hydrocarbon in place. This is a seismic map and depositional map of the interval in which we found the Lower Campanian sands in Wei. It's much like the ones I showed you for the Maastrichtian. Sands are represented by warm colors, green, yellow, and orange, in this case. Shows the location of the Wei Well and the Kawa Well. The Wei-1 well is sitting in the center of a large sand body, interpreted as a series of channels, point bars, and splays in a submarine channel complex, as you can see, interpreted on the right. Also on the right, you can see the inset of the logs we got in this horizon. The brightest sands seem to be wrapping around the Wei-1 location and perhaps speak to the potential for a better reservoir, east and west, in the same sand body. Also shown in this, shown in this slide are some other channel complexes in the eastern side of the block, which Kawa-1 didn't penetrate. I showed that, this to you on the seismic line. These sands clearly have lateral extent and trapping opportunities, and so we're excited about the Campanian, Lower Campanian potential in the eastern half of the block as well. And a little map, just a little further, a little deeper, would show the central complex that we've shown you before. Going even deeper now. Let's take a look at the Santonian, now represented by these four green lines in the seismic section, and the red box, again, showing you the intervals shown in the logs on the right. Pre-drill, we expected a thick channel complex right here at the top of the Santonian interval, and we certainly got that, as you can see on the log on the right. We got a roughly 80-foot thick, blocky sand, proving up the exploration model. The lower Santonian was a very thick stack of amalgamated sands and shales, and was maybe just generally sandier, higher net to gross than we expected. Like the Lower Campanian, log porosity and shows were seen in the Santonian, and the unknown was the permeability until we recently received the data. In the Santonian, we were able to recover and analyze 17 sidewall cores. Now, that's a lot of core. Sounds like a lot, but it was over 800 ft. In this interval, we saw a lot of variable reservoir quality, variable lithology, and then the two cores I've displayed, I've tried to give a representation of the ranges of reservoir that we saw. Much of the zone looked... Much of the cores looked like the top core, with low permeability. Some of the better zones, the pay zones, had slightly better reservoir, as shown, but still low permeability. As it turned out, only a portion of the hydrocarbon-bearing sand that we saw and reported turned out to be included as pay. To conclude this portion of the presentation, I would say the following: at the current time, we do not have enough data to presume what the recovery or producibility of these deeper, tighter zones are, although there's certainly analogs of fields with low permeability being successfully exploited, like the Wilcox in the Gulf of Mexico. I would add that the Lower Campanian, we can see places where we can definitely anticipate some better reservoir quality that could be considered as a deep tail under a shallow Maastrichtian well. Generally, the Lower Campanian is a little easier to drill than the Santonian, but it's pretty clear right now that the best zone to focus on for us is a Maastrichtian. A large resource has already been penetrated, there's tons of follow-up, and a big enough prospective resource to potentially underpin a standalone development. Therefore, we've chosen to model a conceptual development plan only on the Maastrichtian, the zones we feel most confident about. On that note, it's time to pass the torch to Mark Zoback, who will touch on that conceptual development plan and wrap up the presentation. But before I do so, I want to personally thank you for your attention and for participating in this webinar today, and I sure hope I was able to answer many of your questions. Thank you. Thank you, Regan. I'm gonna finish up kind of quickly here, just to give us time to get to some of the questions that have come in. This slide shows the conceptual field development work that's going on now. It's an artist's rendition. It is not a literal representation of the development of the Corentyne Block. It involves an FPSO, a floating production, storage, and offloading system, which is the common method for bringing oil, you know, from the wells to the surface and to markets. So it's a rather involved system. The purpose of showing you this is to give you a sense of the complexity of the infrastructure that has to be developed prior to, you know, the first oil, and bringing production to market. As you can see, there's a reference to a platform here. Most of our development is in about 300 m of water, and an FPSO would be the standard production methodology, as shown. However, it's not impossible that, you know, moving up to shallower water, maybe where the water is about 100 m, there might be an opportunity to, you know, have a fixed platform for production. These are the kinds of things that are being looked at, and an optimal strategy being developed. The reason for going into this is illustrated in the next slide. We've had many questions about, you know, why does it take so long to go from a discovery to first oil? Well, it's not only the appraisal of the resource in the subsurface, the optimization of the development plan from sort of a geological point of view, but it's also the coupled necessity to build the infrastructure that's optimal for the nature of the discovery. And so where we are today, basically at the beginning of 2024, is we're sort of ending the exploration phase and moving into the appraisal phase with these many prospects that Regan defined, with, you know, first oil expected roughly in about 2030, about six years from now. And, you know, this is not unusual. And when you look at these other discoveries, the first in the, in this Stabroek Block, you can see four years, six years, six years for these, these other discoveries. So, you know, a lot is involved, a lot has to happen between now and first oil. So the final slide we want to show just hits some of the high points. You know, we're on trend, we're surrounded by discoveries, we're in just the right geological setting. We've seen thick sands in multiple horizons. Excellent reservoir has been demonstrated in the Maastrichtian, as well as the recovery of sweet oil. As Regan pointed out, there are additional opportunities, not only in the Campanian and Santonian, but additional opportunities even in the Maastrichtian. We are very optimistic, and we're very excited about the potential for a standalone development, just on the basis of the Maastrichtian, with considerable upside, as something to look forward to as we acquire more data and we further understand these resources. So, at this point, I'll turn it over to Brent, and we'll take some questions. Yes, thank you very much, Mark, and thank you, Regan, for your comments and the great color you've both been able to provide all of us this morning. Clearly, you can tell both Mark and Regan are excited about the results, and we appreciate everyone's patience. We'll try to get to as many questions as we can, and we'll run a little bit longer than the 60 minutes we initially allotted for this. With that, that concludes the slide presentation portion of today's webinar. As a reminder, this presentation is being recorded and will be available on Frontera and CGX's websites after. We had a large number of participants join us today, and if anyone joined a little bit late, you'll be able to see the entire presentation from its beginning through that recording. As a reminder, participants can submit questions via email to info@cgxenergy.com, ir@fronteraenergy.ca. ... We've received a number of pre-submitted questions. Thank you to everyone who sent those ahead of time, and we'll try to address as many of those as possible. In the interest of time, some questions may be grouped together according to subject matter. And while we've received many excellent submissions, we'll limit the questions to technical subject matter of the slides and the expertise of our speakers today. So let's get onto the first question. Regan, this one's probably a good one for you, and obviously one that the team has heard in feedback over the last few weeks. It reads, "Why was the initial Santonian pay number so significantly revised in the December 9th results press release? Did the methodology for calculating the pay change, and if so, why? Okay, sure. So let me clear that one up. Hydrocarbon pay- hydrocarbon-bearing sand is not the same as pay, and that's why we reported them separately. But I understand the confusion because you'll notice, even in our basin, that some people report hydrocarbon-bearing sand and others report pay. I mean, take a look at some of the releases in the basin and you'll see that. That's why we reported them separately. So the first release, we reported pay of a certain number. I think it was 77 ft. That was just Maastrichtian and Campanian. The second was higher, 113 ft. It included Santonian and actually went up. I should have addressed it directly, but hopefully from my presentation, you saw that it took a while for us to understand how much of that hydrocarbon-bearing sand was actually pay. I hope that answers the question. Great, thank you. The next question reads, "Prior to drilling Wei-1, the joint venture said its primary targets were the deeper Campanian and Santonian horizons." I know you covered some of this in your presentation, the question says, "But the November 9th press release mostly focused on the Maastrichtian results. Why the pivot to the Maastrichtian, and what does that mean for the deeper horizons?" Regan, do you want to take a stab at that one? Yeah, sure. So, the balance of the presentation reflected the, the way we prioritize things. Obviously, we're very excited about the Maastrichtian, and I didn't spend as much time talking about the Campanian and Santonian. But we're still interested in the Campanian and Santonian. It has a large areal extent, it's very thick. You can see it's very mappable. Our exploration models worked. But, I think right now, with the resource that we're seeing in, in the Maastrichtian and, and combined with those cheaper well costs, it's just clearly the focus, the way we should go forward. I mean, I think I alluded to this in my presentation, but a Maastrichtian development, you know, is gonna be more efficient and, and faster and, and easier than a broader development of both zones. I mean, they might be included as a potential future resource, but certainly to go forward, we would focus on the Maastrichtian. Great, thank you. I've got one more net pay question here, and then we'll, we'll send out to, Regan's way, and then one to Mark next. But Regan, a question reads, "How can 13 ft of net pay in the Maastrichtian underpin an entire commercial development? Oh, okay, so it can't. That really... I'm hoping that that came through in today's presentation. Remember that Kawa got around 68 ft of pay, and we identified all these other opportunities, and so really it's a sum total of the results of the two wells, the thickness of the pay that we got in Kawa, and the indications of hydrocarbon type and permeability, and then the additional prospects between the two, and just the significant resource that's associated with Kawa that's underpinning that development potential. Okay. Okay, Mark, this one's for you. "Earlier this morning, the joint venture announced a resource estimate for the Maastrichtian. What can you tell us about that? And when will the JV or will the JV release resource estimates for the deeper zones? Well, you know, those are obvious questions of great interest. We are working on the deeper zones. As Regan pointed out, the very thick Campanian sands in the, you know, area of Wei are particularly exciting, and so it's a high priority for us. But in reporting the results from the wells as the wells were being drilled and presented, there was a lot of discussion of, you know, hydrocarbon-bearing zones and net pay, as Regan just pointed out. But I hope the listeners appreciated the three-dimensionality of these different sand bodies and the fact that it's the, you know, the volumetric assessment that's really important. That's taken a lot of time to use the wells as calibration points, the 3D seismic as a mapping base, and the integration of all that to, you know, come up with this estimate, again, confirmed by, you know, independent experts, of 514-628 million barrels of oil equivalent just in the Maastrichtian. So I think the JV is extremely excited about that. I mean, this, as a standalone play, makes good economic sense, and the planning is going forward on that basis. At the same time, we have not lost hope that there are potential recoverable resources from the Upper Campanian and perhaps even into the Santonian. It will take, you know, discovery of formations with appropriate parameters to be converted from hydrocarbon-bearing to potential pay zones, as Regan pointed out. Great, thank you. The next question says, and this one, Regan, perhaps you could take. The first McDaniel resource report estimated that the northern portion of the Corentyne Block has a much larger resource number than what the JV announced today. Why is today's resource estimate lower than the original McDaniel's report for the North Corentyne? Okay, so I think the report that's being referred to is the one, prior to drilling either well, so that is a factor right there. It was prior to having any information. I guess second point related to timing of the well, I believe that would've been for the entire block, not just the North Corentyne area, which is all that we've included in our report. And I know for sure that in the earlier report, prospects were considered, all the way through the stratigraphic column, I think even Tertiary, all the way down probably to Coniacian. So I just wanna remind you that our resource report is just for the Maastrichtian here, and so it's natural that our numbers would be lower, and ideas change and focus changes. So on a purely Maastrichtian basis, we have a very good number. Okay, great, thank you. Mark, this one's for you, I think best suited. It says, "What's the status of the farm-down process, and when can we expect an announcement?" The million-dollar question. Well, as we indicated, the CGX Frontera joint venture, with support from Houlihan Lokey, is leading a global effort to consider a farm down. You know, that is underway, and it's. The commercial sensitivity of this process is pretty much obvious. And it's important for shareholders to know that the process is underway, and it would be inappropriate for us, you know, to kind of characterize those efforts until you know, some sort of conclusion is reached. These are negotiations, presentations in progress, and we're, you know, just starting on that process and very enthusiastic about the potential outcome. Okay, fair enough. Next one for you as well, Mark. Why did lab results analysis take so long? Is there anything left to analyze? Well, this is something I have a lot of personal experience with. These kinds of lab studies always take a long time. You wanna do it right, and you also want to take the you know, the limited samples that you obtain and put them in the you know, appropriate geologic context. Regan pointed to an example where we had 17 cores. It looked like we had a lot of data, but that was over a 700- or 800-foot interval. So, you know, it's very important to try to do the test properly, to you know, evaluate the samples that you do have, to understand how characteristic they are of the you know, formations as a whole. To study the fluids, of course, the porosity, permeability, clay content, all of these, all of these issues. It, you know, takes as long as it takes. And believe me when I say, from the moment the samples were obtained, we applied as much pressure as we could to the contractors doing the laboratory analysis to deliver meaningful results to us in a timely fashion. And we've integrated those results into the, you know, larger analysis that Regan described, and that's where we are today. Everything you've heard today basically represents what we know today. Okay, perfect. Regan, a question for you: Is the Santonian still being evaluated, considering the disclosure of 40 ft of net pay? Okay, I guess similar answer to the other one. It's certainly not forgotten. Like I said, a large areal extent, thickness. We've recently got the information that we're, you know, we're still looking at, but I think the story is very clear right now that the Maastrichtian has what we need to go forward, so that is the priority going forward. Okay, thank you. I'll try and squeeze in a couple more questions here. Thanks to many of you who have stayed on for the Q&A process. I certainly appreciate that. Regan, what is the status of the Wei-1 well? Can the well be re-entered, tested at some future time, or has it been abandoned? It has been abandoned safely, all went well. It cannot be re-entered. This is a good opportunity to say, you know, a well that you intend to produce has a very different design and cost, frankly, to an exploration well. So it's not uncommon to drill an exploration well, but not have it prepped or prepared to ever produce from it. So neither Kawa or Wei were designed to be producing wells, so we don't intend at all to reenter them and test them, or do anything like that. Okay. Another one for Regan: How much importance has been given to the interpretation of geological faults within the Corentyne seismic data set, as these minor faults affect the... in placement of the channels, in some cases, thickness of the facies, and lastly, gas or oil water contact at leak points? Yeah, so this is... Well, it sounds like the person who's asking the question is familiar with the basin, and there are some faults in the basin, but they are subtle. They don't displace the strata, at least in the North Corentyne area. But agreed, they do certainly have some hinges and subtle effects on the distribution of the sands. And yes, we have noticed areas where sands seem to be ponded in paleogeographic lows. So that is something that we're looking at for sure. I would say more from a sand deposition perspective than a trapping perspective, in terms of, you know, oil and gas contacts and leak points. I think that's something that we would need more information on to really work out, but certainly we pick the lowest risk locations to drill. I guess I would also say that in terms of our prospects, they are stratigraphic traps primarily. There's a few that have some structural rollover, and that becomes obviously the place you would start first with the well. Okay? Great, thank you. I'm conscious of the time, and I'll try and get things wrapped up at quarter past the hour here. So perhaps one more question for Regan, and then sort of final thoughts from Mark. Regan, did you learn anything with the Wei-1 well design improvements that could be further modified if you were to drill a third well in middle northern Corentyne Block? How does the JV think it can drill future wells without similar delays and costs? Okay. Most of the drilling challenges that we had in Kawa and Wei were in the deeper zones, in the lower Campanian and the Santonian. Pressure changes, hard rock, hot, deep, that sort of thing. For the shallower horizons, for the upper Campanian, et cetera, we learned a lot from Kawa. One thing we did get in Kawa was a lot of pore pressure data, and so with a modified well design, we had relatively few problems in Wei. I know people are aware that we did have problems right at the bottom of the hole. We did have an MDT tool stuck in the hole, which caused some grief. That wasn't related to the well design. Unfortunately, these things happen. I feel like Wei was drilled much more effectively and, you know, when we drill another well, we have a lot more information, and we're drilling shallower. And the Maastrichtian didn't cause a problem in either Kawa or Wei, and so I feel pretty confident that we could drill those pretty deeply, safely, effectively, and get some good data. Great, thank you. Just checking time here, Mark. You and Regan presented a lot of great information today. Thank you for that. Thank you to those who joined us for allocating, generously allocating your time. We appreciate. We've gone a bit longer than anticipated, but wanted to share the information that we could. Mark, to wrap up, are there any things that you'd like to leave this group with? Well, you know, first and foremost, we discovered oil, and we discovered high-quality reservoir in, you know, in the Wei-1 well. And the findings from Wei-1 allow us to reflect and interpret what we have at Kawa-1 in the context of the seismic data, as Regan presented. And so we have a, you know, an extremely exciting, what appears to be commercially viable play in the Maastrichtian alone. And as time goes on, we're gonna learn more, and the opportunities may expand. So, we're very enthusiastic about the potential for a standalone Maastrichtian development and very enthusiastic about the potential of the underlying Campanian and Santonian. But, it's gonna take some time to understand the latter part, but we're, but we're ready to go. We're very excited and extremely pleased by the way in which Wei has expanded the knowledge we obtained in Kawa and allows us to put everything in a geologic context, as Regan explained during the presentation. Great. Well, thank you, very much, Regan and Mark, for your time, and for your patience in explaining very technically complex, subject matter to, the non-technical folks like myself and others on the line. We appreciate it. Thanks to everyone who has joined us today. We had a very large turnout. As we mentioned, the presentation, has been posted to the website, and a recording will be added, later. Thanks, everyone. Enjoy the rest of your day and, we appreciate all the support. All the best. Thank you. Thank you, all. Thank you.