Frontera Energy Corporation (FEC) Earnings Call Transcript & Summary

And thank you for joining us for CGX Energy, Inc. and Frontera Energy Corporation's Information Virtual Presentation. 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 speakers' remarks, there will be a question-and-answer session. This morning's presentation has been posted on CGX's and Frontera Energy's website, and a recording will be available through the website later. Next slide, please. Well 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 31, 2022, and CGX's and Frontera's management discussion and analysis for the year ended December 31, 2022, and quarter ended September 30, 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 plates at www.sedar.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. 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 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 is 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 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 Adviser. Mark is a professor of Geophysics at Stanford University, Emeritus author of 2 books on reservoir geo mechanics 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 6 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.

Good morning, everyone. It's a pleasure to meet and bring all of you up to date. There are 4 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 and Maastrichtian, and it's justified a new focus on that age of formations. There's been significant derisking and growth in 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 and age resources. The prospective resources are estimated between -- to be between 514 million and 628 million barrels of oil equivalent, and that's the mean estimate of 4 separate analyses, 2 of which were carried out by independent world-class resource evaluators. Now we're going to 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 Way benefited greatly from lessons learned in Kawa and that drilling went extremely well. We will introduce the potential of this Maastrichtian play 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 very good summary of where things are today. 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 in June of 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 2 independent world-class resource evaluator 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 zoom in on the North Corentyne block. And the first thing to point out is that the Wei-1 and 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. And initially, the Golden Lane referred to the wells further from shore out in deeper water, and the Silver Lane referred to the discoveries and 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 emerging and what we're referring to in the title of the 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 previously been 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 LUKANANI well here off to the West, has both gold and silver line characteristics in that, we believe there's prospectivity in all of these horizons and not limited by the geographic position of the wells. So we're quite excited about these resources. I'm going to turn it over to regain 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 going to update you in detail on the results of Wei. but also on the implications of the results of both Kawa and Wei 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 nontechnical listener will seem quite complex. So I'm going to do my best to explain things in a really simplistic manner as best I can, while hopefully giving the more technical folks what they want to 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 on the left and Kawa on the right. The wells are 14 kilometers apart, and the sticks below the wells show how deep each well went. I 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 do 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 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, Silver Lane, as Mark said, the moniker Golden Lane refers to 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 2 wells, as Mark said, indicated kind of potential from both trends. So Kawa was a really exciting well. And as a first of its kind to be drilled on the slope, it definitely pose 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 have liked more. But despite that, it did give us enough information to know that we were involved in something really exciting and where it's following up, and I've summarized that on the right side of the slide. So number one, we proved the reservoir presence on the block with porous Sand's found and then stricken in coniacian. I mean the Guyana shelf had been extensively drilled and the deepwater, but nothing really in that in between areas. 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 feet log pay. And even in the deepest hottest part of the well, more than 21,000 feet, we found oil in the analyst mud when the well kicked. So we definitely proved the 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're able to get that data we needed to evaluate it as well as Kawa and the prospects in between. And this included crucial rock data from the core, fluid data from MDT and so now we can prove hydrocarbon charge into the block and also have 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 going to spend most of our time talking about today. So as we go through this today, please remember this is a 2-well drilling program, including a dual exploration appraisal well. So the well results are very closely tied. And so as a result, you're going to hear me jumping back and forth between Kawa and Wei. As I discuss the results and implications 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 going to be talking about each of these points today in a fair amount of detail and in order seen here. So you can consider this sort of a table of content 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. Yet, we only got a thin sand at Wei, but in Kawa, we got a very thick package of stack sands. We know now the Maastrichtian is mappable. Those sands at Kawa are thick enough to be seen on seismic. And there's equally good or better opportunities even elsewhere on the block. From Wei, we finally have actual measurement 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 reserves evaluation of the Maastrichtian block, which we've done, and we verified it with 2 separate resource evaluators. We're really happy with that block estimate. And coupled with the quicker, easier, cheaper drilling of the Maastrichtian and we believe we have enough resource in the Maastrichtian to potentially underpin a stand-alone development. So let's focus in on the Maastrichtian. Same seismic line. The red boxes on the well sticks show that Maastrichtian interval, the prospective Maastrichtian interval in each well. And they fall within that Golden Lane window that I 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 significant in this particular boundary. It's kind of like going from Monday to Tuesday. 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 in 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 share layers within the earth. These would be non-reservoir. And the yellow intervals represent sand layers which can be reservoir. There are also some layers you see that are kind of in a yellow 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 3-dimensional, a thin sand in a wellbore can thicken away from the well far to the right or to the left or into the page. And those kind of Sandy zones that I pointed out 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 engine 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 at a pay and some that have water. Naturally, you're going to try your best to place your well in a place that has most sand, the thickest sand layers and the best chance of trapping hydrocarbons. So what do we get in the Maastrichtian wells? Kawa-1 on the right, got thick stack sands and 68 feet of log pay in the Maastrichtian primarily from these lower 2 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 because we didn't have core. And 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 on the left, we got 13 feet of pay in the Maastrichtian sand. And although sand now got thin this zone was absolutely critical to unraveling the block's potential because sidewall cores and MDT samples were recovered and excellent reservoir quality and oil charge was proven. Moving to the next point. I mentioned that we were 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 a bizzle plain or what we also call a basin floor. Now this part looks like a cliff, and it really isn't. It's a lot, lot gentler. This is extremely vertically -- vertically exaggerated. But the concept is 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 the turbidity current. You see a picture right 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 a 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 lengths of the Corentyne block from nearshore to deep offshore and avanatated this Stabroek block here in red, and this should be -- sorry, this is the Corentyne block, and this is a Stabroek block here. Now because of the 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 are drilling just north of us now called Bluefin. This seismic line doesn't directly tie all of them. I believe it's close to Haimara. But this is the approximate position where they are sitting. Here is a modern shelf edge as it is today and the modern seafloor. And you can see where we drilled Kawa and Wei. It's just outside of the shelf edge, it's on 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, 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 deepwater, far in front of the cretaceous shelf. That's your Golden Lanes. So although our wells and their wells appear to be in quite different positions today, they were back then. The Sandy reservoirs that were deposited in 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 [indiscernible] . So let's take a closer look at the Maastrichtian sands and 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 sand there and they're blown up on the right-hand side. There are 3 blocky sands and some thinner sands on top, and they span about a 600-foot interval with individual blocky sand packages up to 60 feet thick. The log showed 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. And 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 sand thicken and thin and seismic disappear altogether. So after drilling 2 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 in many layers in the Maastrichtian, 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 2 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 2 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 VpVs 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 at the warm colors indicate sand and blues indicate shales. So in the corner, near the intersection of these 2 lines, you can see an area that appears really sandy. And if you look really closely, there's a little blue thing sneaking through it. This is interpreted as a shale field 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 updip. Updip is this direction. By pinching out updip, I mean, it disappears updip, 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 may stricken intervals, there is sand. So this would be a great target for a while. 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. And 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 levies and lobes. And you can see his interpretation on the right-hand side. The most obvious thing is a shale field channel running through, which you actually to the untrained eye, is really quite obvious on the seismic as well. And you can see the depositional interpretation he's drawn for us on the right. So the sands are interpreted as channel levies and displays in a deepwater 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 got in map, the sand appears to pinch out into a shale updip 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 and 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 have included resource in our total count. If you look to the Northwest Kawa/ Wei you can see other Sandy areas that I haven't drawn anything on. This is a separate deposition of 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 -- literally an updip into a shale field 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 the central frontal splay prospect. It did penetrate another area that's slightly green. There were some thin sands at this level in Kawa, but nothing exciting and no pay at this horizon even though there was sand and pay at another horizon. Kawa 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, there were good sands with potential pinch out near the southern edge of the 3D or maybe off 3 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 out 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 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 and make sands. Sands are developed at many different levels within 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 sand seem to pinch out and some don't. And not all prospects are included necessarily as prospects and a prospect inventory. We only picked the very best ones, for instance, to include in our resource tally. So we know we can map the 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 course from that thin oil zone at Wei. 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 courts 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 millidarcys or 1 darcy 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 end to 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 microscope. The white shapes are sand grains and the blue is empty space between the grains, which is the porosity in the reservoir, this should 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 it pass between the grains, these are called pore throats. The fact that we can move between these screens 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 into granular porosity. Now it's been publicly reported that the giant Liza field and Stabroek block has porosity of 20% to 30% and permeability of 100 millidarcys to 2,000 millidarcies. So it's very confident 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 3 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 suite 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 updip 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 taking at all. Taken in isolation. But considering we definitely got oil and Wei and see something very similar in Kawa, it's a solid assumption that the hydrocarbon in Wei was oil as well, and that 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 flash to PBT gas and md 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 2 prospects in detail. The one associated with the Kawa sands and the one in the central area, and I gave you a little peak 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 in Maastrichtian in 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 2 independent third-party world-class resource evaluators. And the Pmean unrisked resources was estimated to be 514 million to 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 that doesn't include any resources from deeper horizons like Campanian or Santonian. So that's a great lead into my next slide from the deep zones in Wei. After Kawa was drilled, Wei was designed to evaluate all the horizons in which we've found pay and Kawa. This included the Maastrichtian, the Campanian and Santonian, and to gain information that would help us evaluate not only itself, but also Kawa. In Kawa, we had log pay and very interesting channel systems in the Santonian but didn't know the permeability of the zones. So Wei's location was optimized to hit similar stacked Santonian targets and get some core as well as hit and intriguing channel system in the lower Campanian. We were successful in those objectives. The exploration models were correct, and we hit stick 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% to 6%. In the Santonian, the porosity in the pay zones with 13% to 16%. But the core permeability was 1 to 2 millidarcies and most frequently on the low end to back. These are the details of the lower companion 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 feet thick and a second set of thinner sands above. The sand is pretty much paid top to bottom with average porosity 14%. There were 2 cores taken from the center of the sand and less clean sand and may represent the lowest quality in this sound. The MDT interpretation indicated up to 6 millidarcies. As we didn't get much core from the zone, a couple inches of representation from sand almost 60 feet thick, the image logs were very insightful and they're plotted at the same scale beside there. They reveal the highly laminated reservoir and in many cases, very thinly laminated, as I show in the image on the far right, which is a -- it shows a forefoot interval of the core. And that app image sand bodies are like colored and shales are dark colored. It's very possible that headway penetrated this channel in a more actual position, a less laminated sands 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, and the results did match the predrilling 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. This one was not penetrated by Kawa, but it's a good potential target, and you're going to see that on the next slide. And finally, in a 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 predrill mapping, that central complex remains a viable target with a large potential hydrocarbon in place. This is a seismic -- sorry, this is a seismic map and depositional map of the interval in which we found the lower Campanian sounds 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 way well and the Kawa well. The Wei well is sitting in the center of a large sand body, interpreted as a series of channels, point bars and displays in a submarine channel complex, as you can see, interpreted on the right. And 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 way location and perhaps speak to the potential for better reservoir east and west in the same sand body. Also shown in this slide are some other channel complexes in the eastern side of the block, which Kawa didn't penetrate. I showed that this to you on 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 not 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 4 green lines in the seismic section and the red box, again, showing you the intervals shown in the logs on the right. Predrill, 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've 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 gross than we expected. Like the lower Campanian log porosity and shows were seen in the Santonian and the unknown was it permeability until we recently received the data. In the Santonian, we were able to recover and analyze 17 site well cores. Now that's a lot of core. Sounds like a lot, but it was over 800 feet. In this interval, we saw a lot of variable reservoir quality, variable lithology. And then the 2 cores I've displayed, I've tried to give a representation of the ranges of reservoir that we saw. Much of the zone look -- much to the cores look 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 of producibility of the deeper tighter zones are. although there's certainly analogs at fields with low permeability being successfully exploited like the Wilcox in Gulf of Mexico. And 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 on is a little easier to drill in 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 stand-alone 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 consensual 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 going to 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 rendition, it is not a literal representation of the development of the North Corentyne block. It involves an FPSO, a floating production, storage and offloading system, which is the common method for bringing oil 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 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 meters of water and FPSO would be the standard production methodology as shown. However, it's not impossible that moving up to shallower water, maybe where the water is about 100 meters, there might be a opportunity to have a fixed platform for production. And these are the kinds of things that are being looked at an optimal strategy being developed. The reason for going into this is illustrated in the next slide. We've had many questions about, 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 as we're sort of ending the exploration phase and moving into the appraisal phase with these many prospects that Regan defined with first oil expected roughly in about 2030, about 6 years from now. And this is not unusual. And when you look at these other discoveries, the first the Stabroek block, you can see 4 years, 6 years, 6 years for these other discoveries. So a lot is involved, a lot has to happen between now and first oil. So the final slide we want to show just hit some of the high points. We're on trend. We're surrounded by discoveries. We're in just the right geological setting. We've seen thick sands and multiple Horizons, excellent reservoir has been demonstrated in the Maastrichtian as well as the recovery of sweet oil, as Regan pointed out there. Additional opportunities not only in the Campanian and Santonian, but additional opportunities even in the Maastrichtian. And we are very optimistic, and we're very excited about the potential for a stand-alone development just on the basis of the Maastrichtian with considerable upside as something to look forward to as we require 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 website after we had a large number of participants joining 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 e-mail to CGX at [email protected], Frontera at [email protected]. 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 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 on to the first question. Regan, this one is 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 9 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 feet. That was just Maastrichtian and Campanian. The second was higher, it was 113 feet. 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 paid. I hope that answers the question.

Great. The next question reads, prior to drilling Wei 1, the joint venture set its primary targets were the deeper Campanian in Santonian and Horizons. I know you covered some of this in your presentation. The question says, but the November 9 press release, mostly focused on 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?

Yes, sure. So the balance of the presentation reflected 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 in Santonian. But we are still interested in the Campanian and Santonian and it has a large aerial 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 the Maastrichtian and combined with those cheaper well costs is 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 is going to be more efficient and faster 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. I've got one more net pay question here, and then we'll send out Regan's way and then one to mark next. But Regan, question reads, how can 13 feet of net pay in Maastrichtian underpin an entire commercial development?

Okay. So it can't that really, I'm hoping that, that came through in today's presentation. Remember that Kawa got around 68 feet of pay and we identified all these other opportunities. And so really, it's a sum total of the results of the 2 wells the thickness of the pay that we got in Kawa and the indications of hydrodecarbon type and permeability and then the additional prospects between the 2 and just a significant resource that associated with Kawa that's underpinning that development, potential development.

Okay. Mark, this one's for you. Earlier this morning, the joint venture announced a resource assessment for the Maastrichtian, what can you tell us about that? And when will the JV or will the JV release resource assessments for the deeper zones?

Well, 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 area of Wei 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 hydrocarbon bearing zones and net pay as Regan just pointed out. But I hope the listeners appreciated the 3 dimensionality of these different sand bodies and the fact that it's the volumetric assessment that's really important. And 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 come up with this estimate, again, confirmed by independent experts of 514 million to 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 stand-alone 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 then perhaps even into the Santonian and it will take discovery of formations with appropriate parameters to be converted from hydrocarbon bearing to potential pay zones as Regan pointed out.

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 on prior to drilling either wells. 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 have 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 want to remind you that our resource report is just for the Maastrichtian here. So it's natural that our numbers would be lower and ideas changed and focus changes. So on a purely Maastrichtian basis, we have a very good number.

Mark, this one's for you. I think that's suited. It's 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. And 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 to kind of characterize those efforts until some sort of conclusion is reached. These are negotiations presentations in progress. And we're 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 want to do it right. And you also want to take the limited samples that you obtain and put them in the 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 it's very important to try to do the test properly, to evaluate the samples that you do have to understand how characteristic they are of the formations as a whole, so the fluids, of course, the porosity, permeability, clay content, all of these issues. And it 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 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 feet of net pay?

Okay. I guess, similar answer to the other one. It's certainly not forgotten. Like I said, large aerial extent thickness. We've recently got the information that 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. So it -- 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 reentered. I guess this is a good opportunity to say 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 crept 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 affected in placement of the channels, in some cases, thickness of phases and lastly, Gas or oil water contact at deep plains.

Yes. 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 and paleographic 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 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.

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 for 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 in costs?

Okay. Most of the drilling challenges that we had in Kawa and Wei, were in the deeper zones in the Lower Campanian and Santonian pressure changes, hard rock, hot, deep, that sort of thing. For the shallow horizons for the upper Campanian et cetera. We learned a lot from Kawa. One thing we did get in Kawa a lot of pore pressure data. And so with a modified well design, we have 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 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 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, first and foremost, we discovered oil and we discovered high-quality reservoir in the Wei well and the findings from Wei allow us to reflect and interpret what we have at Kawa context of the seismic data as Regan presented. And so we have an extremely exciting what appears to be commercially viable play in the Maastrichtian alone. And as time goes on, we're going to learn more, and the opportunities may expand. So we're very enthusiastic about the potential for stand-alone Maastrichtian development. And very enthusiastic about the potential of the underlying Campanian and Santonian, but it's going to 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 our -- 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 and explaining very technically complex subject matter to the nontechnical folks like myself and others on the line 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 the recorded 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.