Good afternoon, ladies and gentlemen. Welcome to the Pantheon Resources plc Investor Presentation. Throughout this recorded presentation, investors will be in listen only mode. Questions are encouraged. They can be submitted at any time via the Q&A tab that's just situated on the right-hand corner of your screen. Please just simply type in your questions and press Send. The company may not be in a position to answer every question it receives during the meeting itself. However, the company can review all questions submitted today and will publish our responses where it's appropriate to do so on the Investor Meet Company platform. Before we begin, we would just like to submit the following poll, and if you'd give that your kind attention, I'm sure the company would be most grateful. I would now like to hand you over to the executive management team from Pantheon Resources plc. David, good afternoon, sir. Thanks very much indeed, and good afternoon to everyone who's joining us on this call. Today we're going to run through the results of the Megrez-1 Top Set 1 test and provide some greater explanation. The key questions that we hope to have answered by the end of this is, why did the Top Set 1 test flow water? Why does the data gathered lead to a more robust analysis and increase our confidence in the prospectivity and likelihood of commercial flows in the five shallower zones? Why does the salinity matter? We talked about it in the press release. Why could we not move immediately on to the next horizon in terms of what equipment is available at on what terms? What would success be during the course of the remaining tests? Before I hand it over to Max to talk through the main body of this presentation, I just want to remind everyone where we started out. Last year, we said we had two major initiatives over and above the existing 1.6 billion barrels of independently certified resources. One related to moving forward with the financing that would seek to minimize dilution to shareholders to the maximum extent possible. That's the activity with the State of Alaska on the gas line phase one, and the associated gas sales process. The other was to drill the Megrez well, and to hopefully add to the resource base. Our main focus today is going to be on that second of those two initiatives. We won't be talking about the gas pipeline unless specific questions from management. With that, Max, can I turn it over to you to present to the group? Yes, thank you, David, and it's good to be addressing everyone again. So only about 10 slides here. We wanna get to the questions and concerns or happy thoughts anyone has about where we are. A few things to sort of calibrate where we are in our portfolio and also very directly to what David said, what robust analysis is leading to increased confidence going forward. I do apologize, I may get quite technical as we go through this. But initially, you know, just as a reminder, go through the disclaimers. What does this company represent? As David mentioned already, 1.6 billion barrels of certified liquids. Doing the math on that, the upside of this company on that aspect of our portfolio is quite vast. We do have a near-term catalyst, which is the bulk of today's presentation, which is Megrez-1, and that presents upside to what we already see as a strong portfolio east of the highway. You know, the news in Alaska continues to be very positive. I'm sure everyone reads the press. Alaska is becoming increasingly important to the U.S. and the citizens of the state of Alaska. The news flow is almost universally positive to support development, both ours and other operators discovering resources in Alaska. The news flow is still very, very positive. One advantage we have over everyone else is the infrastructure, of course, as you all know, runs right down the center of our acreage. It gives a huge advantage in capital costs and infrastructure and speed to commercial volumes. You know, down the road, you know, there's a lot of news flow around the gas line and everyone's reading that. We are in an advantageous position there as well as the first participant. That gives us huge opportunities going forward, not only for gas egress, but also financing for our own developments. So that remains very, very positive. I'm sure you can appreciate, finding 1.6 billion barrels in a remote area takes a highly experienced management team. As I mentioned at the annual general meeting, we're also pivoting this team now from more of an exploration and appraisal mindset to add a development mindset to that as we are on the path to commerciality. No new news there. I think everyone is well aware of that. Equally, where these assets are, everyone's very familiar with the green blobs on top. Those are some of the largest oil fields in the world, certainly in North America. The analogy I always give for this, and I'll give it again, is I spend a lot of time in West Texas. When you fly into West Texas, the development starts about 100 miles east, west, south, and north of the original Prudhoe Bay of the Permian, called the Central Basin Platform. If you flew in there 50 years ago, you wouldn't see anything until you landed in Odessa. The same thing is now starting to happen in Alaska, and that's the resurgence on the previous slide, is people are discovering attractive pools on the periphery of the main fields, and we're leading that effort. The resources just to calibrate, that's the 1.6 billion in liquids, the bold in the center of the slide. A combination of stock tank oil and natural gas liquids. 1.6 billion barrels is a sizable resource, especially a certified resource. Any math you do on that is gonna result to a lot of shareholder value. The number below that 609 is getting a lot of attention from everyone. That was a pre-drill estimate for the Top Sets in Megrez-1. The question is how much of that do we still feel comfortable with and what don't we? That did not include the entire column of the well, just the deeper elements of the column. What's the view now as we go forward of the entirety of this well? Of course, we won't know the full answer to that until we're done testing all six intervals, but what do we think about that? That's sort of the purpose of the call today. You know, again, I think this is the last reminder, which is we actually have three horizons here. We have the very large Kodiak field to the far west. We have our Ahpun right next to the highway, and then we also have the Prince Creek and Lower Sag, which we are just about to test on the east side of the highway. Again, very large amount of resources here for us to commercialize. Okay, so Megrez itself. You guys all read the RNS. There were six horizons that we endeavored to test. Top Set 1, 2 Prince Creeks, and then the 3 Sags, which were all oil-bearing based on the log analysis and core analysis and cuttings analysis. There's no question there's hydrocarbon in these. The question is how mobile and at what rate. The first one was Top Set 1. After we tested that for 12 days, we determined that there were no appreciable hydrocarbons flowing to the well. I'll explain that in a minute. Our view of Top Set 1 was would not be an attractive commercial target going forward based on that well test. Now, the five other ones will be coming here shortly. We'll talk about that in a minute, but I'll come back to that. I need to get technical first. Okay. What you're seeing on this slide on the right is a series of log traces. We draw your attention to the blue one where it says high salinity, medium salinity, and low salinity. To the left of that you see more and more green growing as you go from low salinity to high salinity. What these three things represent are three different analyses of the same resistivity measurement in the wellbore for different salinities of water. What that resistivity log is measuring is the conductivity of the fluids in the reservoir. Oil does not conduct electricity, saltwater conducts electricity very well, but the more salinity you have in the water, the better conductor it becomes. At low salinity, it starts to look more and more like oil. The outcome of that is if you don't know the salinity directly, you can get a conclusion of oil saturations, in this case, from quite low to quite large. Please do not use this log to do any calculations on. It's a pipe log just to illustrate the example. That was our dilemma. Without a clear definition of salinity, how do we calculate with a great degree of confidence what the oil saturation in the reservoir is? Now we've had the flow test, we have a much better view, obviously, because we produce formation water, so we know what the salinity is, and then we can recalculate these more shallower horizons and also calibrate that to non-salinity measurements, like an RST log, to arrive at what we believe would be a mobile oil saturation. At least is it mobile or not, which is what gives us the confidence to test the shallower horizons. I won't go into the details of Archie's equation, which is a very, very standard. Some people call it Archie's law because it's used so often. But that is what the industry generally uses to calculate a water saturation based on the measured resistivity of the reservoir fluids. That's only part one of the conversation. Part two of the conversation is once you know the saturations, will it be capable of flow? Now I'm going to get really technical. This is the area of hardcore reservoir engineering. In an oil and gas reservoir, a classic one like this, you can imagine a collection of sand grains. The sand grains are pushed together, and the space in between the sand grains is, of course, porosity. That's what can contain oil, water, and gas. How easily it flows through with a pressure differential is its permeability. That permeability is not the same for all fluids at all saturation. The physics of it is, one is wettability. One of the phases, oil, water, gas will want to stick to the sand grains. If it sticks to the sand grains, it won't flow through the sand grains. That's the wetting phase. It can be oil or water, and you really would prefer it to be water because you want to preferentially flow well. Wettability is one, but once you know the wetting phase, how the fluid flows is a function of the saturation and fractional flow flowing through the reservoir at the time. There's an irreducible in both cases. If you're water wet, there will be irreducible water saturation that will never flow because it's clinging to the sand grains. It's also true the other way around. There's irreducible for the other phase, and you have to get to that level of saturation to have what we call mobile oil and gas. The question for this well in Top Set 1 was there sufficient oil saturation in the reservoir to flow? It turns out that was not the case because we didn't flow any hydrocarbon. Again, you know the question usually is, "Wait a minute, you said there's oil in the reservoir. Why didn't it produce any oil? The reason being is there wasn't enough oil to get beyond the irreducible level. That could be for a number of reasons. Is it a transition zone, so the oil is getting more and more higher in saturation as you go up the well? Or is it a migration path where oil passed through here on its way to a different trap? There's not much debate, is there hydrocarbon in Top Set 1? The question was would it flow, and at what rate? It would appear on this relative permeability chart. This is not actually the Top Set 1, it's an illustration, but if it was the exact well perm curve for this reservoir, it would indicate that there wasn't enough oil saturation to overcome the irreducible levels required for production. Extremely technical there, but I want people to understand the sort of rigor and the thought process that went into it for us to understand why we got the result we did and indeed what that might mean for the shallower horizons. Only two more slides here, and then we'll get to the questions and answers, which is the important part of today. Our plan hasn't changed. Our plan is there's two wells being considered between now and FID. One is a commercial demonstration well for Ahpun or any of our tight reservoirs, to demonstrate the type curve consistent with an FID that we would then expand to pad drilling. Depending on the outcome of the shallower 5 intervals, in a success case, we would want to drill a delineation well to test the continuity of the successful horizons. That will be obviously pending the results of the last 5 intervals. Which ones do we want to delineate, and which ones are the most commercial? The plan essentially has remained unchanged. The vast amount of value in this company remains up in the Kodiak. The upside of Megrez remains to be seen. This Top Set 1 certainly appears to be an uncommercial reservoir horizon, but the shallower 5 remain to be seen. I'll leave you with where I started, and we'll go to the questions. Essentially, our business plan is unchanged. The value of our resources is unchanged. The only thing that's under question right now is how much and what quality of upside does Megrez-1 represent. We'll have to continue the testing of the five intervals to be definitive about that, which will take another month or two to complete that exercise. I'll leave it at that, and let's get to the fun part, which is the questions and answers. I'll turn it back to you, David. Thanks, Max. As you can imagine, there were a lot of pre-submitted questions, a lot of them asking much the same thing in slightly different ways. If you don't hear the specific wording of your question, don't worry. If we haven't properly captured it in the general categories of questions, please don't be afraid to ask it again on the webinar. First set of questions, Max, and you touched on this a bit, but probably an opportunity to add some more. What equipment is needed for the zones that need hydraulic fracture stimulation, and why wasn't it available immediately? Some supplementary questions to that is, what does this mean for the timing of subsequent tests beyond the Lower Prince Creek? Are there any other horizons that will require hydraulic stimulation, et cetera? That general theme area. I mean, yes. These are great questions, by the way. The most important equipment required for hydraulic stimulation are the hydraulic pumps themselves. A series of trucks with pumps on the back to basically take water and sand from atmospheric pressure to whatever pressure is required to initiate a fracture and propagate a fracture. It's called a fleet. It could be anywhere from 12-18 of these, depending on where you're fracking around the world. There's only one of them on the North Slope of Alaska, which is owned by Schlumberger. It's a precious piece of equipment. At this time of the year, there's a lot of winter activity, exploration activity. People want to use this quite a lot right now, including ourselves. Schlumberger is very congenial, very good to work with, but they do have other customers. We have to work around the activities of other companies to make sure the equipment arrives, you know, at the time we want it and is available for the duration we need it. The short answer is it's that hydraulic fracturing or hydraulic horsepower fleet that's, there's only one of those on the North Slope. What does it mean for the subsequent tests? The only other horizon that requires this is Lower Prince Creek. As we've said before, as you move up the wellbore from the Top Sets all the way to Sag 3, the permeability gets progressively higher. Above the Lower Prince Creek, there's not much of an advantage to fracturing the well. It will flow naturally. The last one that requires this is the Lower Prince Creek, which would be the next interval above the Top Set 1. Okay. What data did we get from Top Set 1? You mentioned earlier the RST in the cased hole. What data do we have from Top Set 1 flow test? How would that impact the assessment of the shallow horizons, that also similar questions around how did we not know whether Top Set 1 would flow oil or water before the test. Again, you've addressed some of these, but you may want to. Yeah. Just a couple more. Why did we keep flowing the zone that was already flowing water? Was that a waste of time and money? Someone's actually added an additional question around, have we considered the possibility of changes in salinity rather than just applying the general salinity we measured in Top Set 1? Do you want to get on those? Again, great questions, everyone. We got two very important pieces of data from the flow tests. One was the productivity of the well, of course. When you drill an exploration well, you derive your expectations of permeability from logs, but you get a much better view of permeability when you actually flood. The well was very strong. It was 1,000 barrels a day. We can calibrate that for our productivity assessments of the shallow horizons. The salinity was the key one, 'cause that's the one variable we didn't have a direct measurement of. We have not a definitive precise number, and I'll come back to why that is with the last question about why we flowed the well so long. It helps us calibrate. We don't want to fall into the trap of we have a definitive answer for salinity in the entire well. It narrows the range, and it helps us assess which intervals will be more likely to have mobile oil than others. That data point is extremely important. Not only does it help us calibrate our resistivity measurements, but also calibrate the resistivity and RST data that we have for these horizons. Very, very helpful. How'd you not know it wouldn't flow oil before the test? Well, that was the same thing. We had a range of possibilities of oil saturation based on salinity and other measurements. That's why we did the test, was to see if we had mobile oil. In this case, there was always a risk it would be below, but certainly the balance of probability was that it would flow oil. That's why we did the test. Why'd you keep flowing a zone that it was flowing water? Is that not a waste of time and money? I've completed hundreds of these wells. In the Montney, you know, Permian, in the Wolfcamp Shale, in Spraberry Formation, and now these. They all have one thing in common. They flow a lot of water before you get hydrocarbon. Now, the reason for that is you're pumping a lot of water into the reservoir to stimulate it, and that water has to come back before the reservoir will contribute. How long that takes is highly variable, but certainly a 7-10-day range is reasonable. We flowed this well for a long time, 100% water, which was expected 'cause it's largely frack fluid. Once you get to 7-10 days, you're starting to look for hydrocarbons. After, I think it was 12 days in the end, at that point, we realized that it still had the potential to produce hydrocarbons, but there was never going to be a commercial level. If we produced this well for 3 years, that'd be a lot of water, by the way, we probably eventually would've got hydrocarbons. At that point, it was determined it's very unlikely there's enough mobile oil for this to be a commercial interval. So the grand summary of this section was, salinity is very, very important. The difference between an exploration well and a development well is if it's a development well, you'd have 100 penetrations, and you have a very good understanding of the continuity of your lithology and your reservoir quality, as well as the saturations in the reservoir. This is an exploration well, so it's the first well penetrated into these horizons, so you have to make assumptions up front. As you gather data, it calibrates your understanding of those variables. Okay. David? Yes. Just a few people, while you were answering the first and second lots, they asked, can we say anything more about the timing of when we think we will get the frack kit? Oh, yes. As we go forward, there's a couple things we need to do. One is we need to fracture stimulate the Lower Prince Creek, but we also have to add cement behind the existing casing. When you cement the casing on your production string, it's very unusual for that to come all the way back to surface. Hydraulically, that's very difficult to do. In this case, when we cemented the casing, the cement didn't go all the way over the top of Sag 3. So we have to put more cement behind pipe, so we have to do that as well as perforate the intervals and flow them. We're considering the best sequence of this. Once we understand exactly which we would do first, put cement behind pipe or fracture stimulate the well, we'll let everyone know. We're still considering, given the availability of equipment and associated costs, what the right sequence is. We know we have to do both. Once you're complete with those two, it gets quite simple because there's no more stimulation required. You essentially set a plug, you perforate, you flow. Once you're done with that one, you set a plug above that, you perf and flow. I know it's like watching paint dry at the moment. It takes a long time because we have to stimulate these wells. Everyone's very antsy for information. As we move up the well, the cycle time of information will get much shorter because the operation itself is much more simple. A set of questions again, sort of technical about operations and what we did and didn't do. I'll run through them, you know, one at a time with you. What other logs did we run, and how do the various tools and techniques overlap to support or cast doubt on the conclusions of our analysis? As we drilled the well, the Measurement While Drilling or Logging While Drilling suite was what you would expect with a Gamma Ray in there, which is lithology between sand and shale, essentially. We had two density tools, one sonic and one nuclear, which is really the bulk density of the reservoir, and then porosity. Of course, we had resistivity, shallow and deep resistivity. I think there's three shallow, medium, and deep resistivity. The only open hole log we ran was a CMR/NMR, which is a nuclear tool, which is also used for saturations. That tool, unfortunately, malfunctioned partway up the well, which is why we ran the RST before we started this to get some overlap between the two. All of these together, petrophysically give you your assessment of overall reservoir quality, both in terms of porosity, permeability, as well as the saturations. Given an exploration well, you don't have calibration points, so you have the direct measurement, and as you get data, it calibrates them. We had a full suite of logs on this. We didn't run an RFT or MDT? That's a great question. The reservoir engineer, our Schlumberger person, is on the call today. RFT is a repeat formation tester. That is taking a direct sample from the reservoir. In this case, I've done a lot of RFTs in my life. They're not very good with tight reservoirs. Of course, this was before my time at Pantheon. It's very difficult to get a reliable RFT sample in a tight reservoir. This is a very expensive tool, and it's very easy to get it stuck, too, especially, this is not a vertical well. It's a deviated well at 45 degrees. In reality, discovering Sag 1, 2, 3, etc., was not fully appreciated until the well was complete. You can't keep an open hole well open forever. The casing went into the ground, and once casing goes in the ground, you can't really do RFT. Would that have been helpful? Maybe. I'd be dubious of getting a result in a tight reservoir, but I'd think it would've been a worse result to lose the wellbore while we're waiting for Schlumberger to fly a tool from Houston or something. in a highly deviated well. Maybe. probably concerned about the cost of losing it in the hole. Yes. You touched on why we didn't run the RST over the entire wellbore, no need to go back to that. Why couldn't we use core analysis to determine water saturations? We only have a full core on Top Set 3. It's not terribly reliable for a sidewall core. These are not pressure maintained cores. You can do certain analysis on the sidewall cores, which you're doing right now, but you would never get a definitive saturation number that would've led us to any other conclusion than the test as well. Good question. In any case, the cores take a while to dry out before you can complete that analysis. Yeah. We haven't got dry core yet. Do we still trust the AVO and VAS and other tools that apparently let us down in Top Set 1? Well, I think they didn't let us down. You know, I think tools are just tools. They're not definitive. What everyone wants in oil and gas is what's called a direct hydrocarbon indicator. In some areas of the world, for example, you can actually see an oil water contact on seismic. That would be very, very helpful indeed. It is helpful. I won't say where they are 'cause some companies like to, you know, say how great their exploration managers are when in reality, they can see the oil contact on seismic. In this case, we can't. These are both tools, and they both indicated that we have hydrocarbons in these reservoirs. That's how we ended up deciding to test them, but they're not definitive in their own right. Exploration is always a combination... Good exploration is always a combination of bottom-up geology. Do you understand your petroleum system? Then top-down geophysics to assist your view of structural geometries and things like that. You need both. These are just two tools, one being seismic and one being cuttings analysis that are helpful. In their own right, they're not singularly determining oil and gas reservoirs. No, we haven't lost confidence in these two, but they remain just pieces of the puzzle. Yeah. Someone asked, did using Oil-Based Mud in this well make formation analysis any more difficult? Not really. I mean, it's Mineral-Based Drilling Mud, but Schlumberger is very used to calibrating for that, so it's not an unusual situation. Yeah. Okay, moving on, we've talked a little bit about the timing of when we expect next tests, but there were questions around what flow rates are we expecting, and what would determine the horizon that we'll be drilling any upcoming appraisal well to be drilled in. I don't think there's any reason to change our guidance. On a success case, we said 200 barrels a day on the bottom and 2,000 on the top and somewhere in between. I don't see any reason to change that 'cause the variable still remains how mobile is the oil. We will find out here shortly, but I don't see any reason to change the guidance on that. Upcoming appraisal well on the development plan slide, there are actually two of them on there. One of them would be a hypothetical delineation well, Ahpun East, i.e. Megrez. That's pending the flow test results. How successful are they and which intervals would we want to delineate at what geometry? That one remains to be seen. The other one, of course, is a commercial demonstration well. Drill a long horizontal well down the heart of one of our reservoirs, likely Ahpun, and to demonstrate to the world that the type curve that we're espousing in our business plan is indeed robust and can be depended upon. Those are the two wells being considered right now. We haven't declared or decided the exact timing of those. We'll be choosing between those two here shortly. Someone's asked, will it be this year or next year? I haven't disclosed that. I'm not sure yet, to be honest. Ideally this year. Either one is consistent with the FID timing in 2027. If we decide we can accelerate that FID timing 'cause of the critical path of regulatory and other factors, we may do it this year, it'd be helpful. We haven't made that decision. Once we've made that decision, of course, we'll disclose that. Additional seismic plan? In a success case, there could be. That would be part of an overall appraisal program for an exploration success. If we declare an exploration success of a high quality conventional reservoir, there's a number of things that would be triggered by that. Further delineation wells, mapping of the reservoir, that could include seismic. There's no plan to that at the moment, but that could be part of an overall appraisal program if we have an exploration success. Where were we? Oh, yeah. Questions about the pipeline. We said we weren't really gonna focus on it, but there was a question around can Glenfarne reach FID this year? I'd suggest that's a question probably best put to them. That can they achieve it without a firm gas contract with us? I think all we'd say is that we're working collaboratively with all the stakeholders to make sure that this gets moved forward as quickly and in the optimum way possible. Technology. A few specific ones around, did we use machine learning? Did we use fractals? What fancy technology do we deploy? I'll let you have that one. Good one. I had to look it up myself how would you use fractals for a reservoir hydrocarbon distribution. I love the question. We haven't done that. I don't think we have enough data to do that. I'm certainly gonna take that one away. In terms of the logging, you know, Schlumberger does most of this analysis. They have all kinds of their own proprietary algorithms, which likely use machine learning and things like that. When you interpret petrophysics, some of it is computational and some of it is interpretive. The right result is a combination of the two. If you have wrong assumptions and you run the algorithm, you're probably gonna get a wrong result. It's sort of iterative, both in terms of expertise as well as, you know, high quality computing and machine learning and things like that. Yeah. I think from memory, the quick look interpretation is an AI-generated interpretation that obviously has been developed through a machine learning approach. As you say, the ultimate interpretation is a combination, as so often of technology and people. There are some questions around our corporate strategy, progress towards listing, that sort of thing. Again, not intended to be the focus of this call, but let's address it. You know, Max said right up front. Our strategy is still to achieve recognized value of $5-$10 per barrel by the end of 2028. In terms of what that would equate to in share price, it depends on what the capital stack looks at the time. If you multiply 5 by 1.6, that's about $8 billion. What are the breakevens? In fact, I think, Max, you covered that. We talked about it at the AGM, and I think we've talked about it a number of times. We still earn a return of some 20% at $35 a barrel, and cash on cash down to $25 a barrel. We're not at the right-hand end of the cost stack when compared to a lot of the other basins in the lower 48. Are we moving ahead to get a U.S. quotation? How does this affect U.K. investors? This comes up in every webinar. The answer is the majority of investors in this company are holders of the U.K. stock directly, and a small proportion hold it through the OTC market maker driven ticker PTHRF. I can tell you that all of the management and board of the company hold stock through the U.K. market. You should rest assured that you and we are aligned in making sure that whatever we do is not going to differentially disadvantage U.K. shareholders. The precise planning around that will be a function of the execution plan for the U.S. listing, which, as we've said, planned for December January timeframe. I think officially we've said final quarter, most quarter, but it'll be somewhere in and around that timeframe. The next bunch of questions were. Oh, yes. There were questions around the Upper Schrader Bluff, so top sets 1 through 9, that is, that's saying that we don't see the prospective prospectivity in Top Set 1. What does that mean for the other topsets? And did we get any indication from the core for Top Set 3 as to whether that should be written off as well? Max, that one's probably for you. Yeah. Top Set 3, you know, has a full core, and the analysis of that is in progress. We chose not to test that at the time because we had a full core, so we haven't finalized our analysis of that. It could very well be that there is a trap on top of Top Set 3, and it will look good to us. We'll do that analysis over time. There's certainly no intention to go back down to Top Set 3 and test it as part of this program. It remains to be seen, I would say on that, and as we complete our analysis of the core. There were some other questions. Were we surprised by the market reaction to the results? There are a few others that are similar that I think fall into the category of investor relations. Our approach to investor relations, you as you know, we've over the last several months been increasing our presence reaching out to investors. We've got a very structured process. Max, now he's on board, but prior to that, Justin and I, as the spokespeople for the company, we do it always with a view to the rules, working with our nomad and our securities lawyers, reviewing presentations to make sure that we are abiding by the requirement to RNS anything that is new information that is price sensitive. Making sure that in any engagements, whether it's with a group or with individual investors, that we are respecting those rules. That's the general process. A lot of people, in fact, an increasing number of people are starting to send questions to contact@pantheonresources.com. I hope those people who are sending them, other than maybe if you sent them there in the last 24 hours, you wouldn't have received a direct answer because it was added to the list of questions for this webinar. You'll, you know, find that no rational, polite question goes unanswered from us in terms of that. As to whether we were surprised or not, I think it's pretty clear that we were surprised by the result because we expected the zone to flow and to flow oil, and it didn't. Were we surprised by the market reaction? I think we've consistently said we try not to judge what the market's reaction is going to be, because there's no reason to suspect we're any better at judging it than any investor is. Other questions that have subsequently come in, some of which look as if they are suggesting that they didn't think their initial question had been asked. Several people have asked the question again, so I don't think it does any harm, Max, for you to reinforce. Why do we have increased confidence that the zones we think are going to flow oil are gonna flow oil, as in the five zones above? Why do we have increased confidence? Yes. I think earlier when I mentioned calibration of our saturation measurements, i.e., resistivity and RST is really important. Having done that, our starting point was an assumption on those things. We got a result in Top Set 1, which wasn't great, obviously, but it has calibrated what's above us. Do we think we have mobile oil above us? Our calibrated assessments say yes. That remains to be seen, of course. There's no guarantees in oil and gas. Based on the data we have, that calibration tells us, yes, indeed, it's probable we have mobile oil. To what extent and what flow rate, there's no way I can intelligently comment on that yet. You know, that's why, as the calibration of the data we received from Top Set 1 was able to calibrate essentially what is on the screen right now. Which is it low salinity, medium, or high, and what does that mean for oil saturations and what oil saturation is required to be mobile into the well bore? That's where that comment came from. Yeah. I think there are a few other questions and the reason I pulled this one back up is because I think there may have been a misunderstanding in terms of the import of what you're saying. It is not that having lower salinity is going to increase the saturations in the zones above. It is that even though introducing a lower salinity into the equation reduces the saturations. It does not reduce them to the point at which you would not expect it to flow. The second thing is it does make the interpretation of Top Set 1 consistent with it not having mobile oil. The increased confidence is as a result of seeing that the impact on the other zones is not sufficient to move them out of the zone of mobile oil saturation. I think what may have been confusing for some people is that the zones above Top Set 1 are higher quality zones. It's not that the reinterpretation of the oil increased the amount of oil within those zones. Is that clear to you, Max, as a proxy for everyone else that- Yeah, I think so. What I would say is that there's no certainty in this. It's not like we calibrated it, and we know definitively the flow rates of every single horizon above us. It just reduces the uncertainty and gives us in the balance of probability we're going to have mobile oil. If the reverse was true, and that analysis indicated there's no mobile oil above us, we wouldn't continue testing. We're gonna continue testing because that analysis now increases the likelihood, all other things being equal, that we're going to get mobile oil. Yeah. You shouldn't, like, double our resource estimates based on that assumption or anything like that. It just means that we believe it's worth continuing testing, because we believe there'll be mobile oil above us. Yeah. I think that there are a few people who've reasked the question, so again, it's worth going back and making it clear that we are not currently attributing resource, or we don't expect to attribute resource to the Upper Schrader Bluff, so that's Top Sets 1 through 9. The original 609 million barrels pre-drill estimate, none of the horizons that those resources were included in are currently expected to yield commercial resource. That doesn't mean there aren't opportunities for further exploration, after we've done further analysis, but for the time being, we're treating that as not being there. Are we ready to change our guidance for the expected resource penetrated by this well? That's the final bullet point on that slide, which is we haven't included any resource from the Prince Creek or Lower Sag in that total resource. In terms of the potential volumetrics, there is every chance that we could end up with a similar resource. I think, Max, you touched on it. I've certainly said it when asked the question. A success in any of these zones would materially add to the resources we have. We have a high likelihood of successful flowing these zones independently. As to whether they will all flow or not, you know, people can do the math on it, but it's a high probability that and that's the reason for our confidence as stated. People are saying we still haven't given specific guidance for the timing of flow testing. I think maybe the best way of answering this is to say, when we get the frack equipment, Max, I think we're going to announce that the frack equipment is on site so that people can avoid having to look out for satellite photos and whatever else. Yeah. Because I saw the question in here, which was actually a suggestion. It was a good suggestion, which is, in this phase where the period of time is longer, we should issue an RNS when we commence activity. That's a great idea, actually. Just to calibrate people's expectations at that point, how long should it take? To do it before you start, there's a huge amount of uncertainty when the equipment's available. When the equipment shows up, there's not much uncertainty. That's, I think, a reasonable suggestion. For the people who want to know when the equipment's gonna show up. Mm-hmm. I suggest you go and talk to the operators who currently have it and ask them when they'll be done with it, which is exactly the same thing as we do, except we do it through Schlumberger. You'll remember at the AGM and subsequently, we've again been very consistent. There are people who have more time pressure than us and people who are therefore prepared to pay more than us. We are not prepared to overpay in order to meet an arbitrary deadline that doesn't apply to us because we're operating on gravel. That's a unique advantage that we have with the location of our current wells. Sorry that you're not gonna get a date and a time right now, but as soon as we know, then we'll be able to share that with the market. I think there's another general question, which was if Megrez's results are successful, and I'm gonna add to that, whether Megrez's results are good or bad, we've committed that we will share promptly the results. As soon as we know something, we share it because as soon as we know something that that's price-sensitive information, that's our obligation. We will absolutely be sharing it. In terms of when we get the frack equipment, we'll put out an announcement, I think, on that, Max. There's a related question, which is, are we still confident about the June timeframe for being done with testing? I forget whether you mentioned the acceleration of the program as we move up the hole. Mm-hmm. Do we think Mudcake will have impeded our interpretation? No. Like resistivity directly is shallow, intermediate and deep, suggesting beyond what would be a filter cake. You know, and since Schlumberger is very good at calibrating for such things. I would say no. It's always something that needs to be corrected for in log analysis, but it's as good as the industry really. It's not a new thing. Yeah. If the next one flows oil, does that mean everything above will flow oil? No. That would be a very positive outcome. I would love that. We just need to treat each of these intervals as independent until proven otherwise. Yeah. We've got no data or interpretation that suggests that they're not independent. They're, you know. Mm-hmm. We can see shale layers between the different, you know, that we'd expect to be sealing. Mm-hmm. I'm interested to hear the thoughts of Pantheon directors at this point about their confidence and, I suppose, the value of their investments. We still feel very confident. As we said, you should not read into anything. We took a view that we're in a closed period for as long as we're through, not whether we've got specific information or not, you know. It's important also not to run the risk of not appearing to avoid trading on inside information. We took a view that we are in a closed period for the duration of these tests. There are some questions about cost and money. You'll recall we did the $35 million bond offering specifically in order to make sure that we had the funds potentially for an additional well in the short term. Depending on well results, what was really important was that we had the capacity to run the business through what might be a difficult period in the markets. You look at the tariff, what someone called it, the tariff tantrum going on in the markets right now. We wanted to make sure that if for any reason, for macro reasons, the markets were difficult, we were funded. We've got plenty of money through for at least the next four months and frankly longer if we had to hunker down. You'll recall we had money in the bank at the end of the year before the bond offering. No shortage of funds to move forward with the program. Taking it back, our priority is to execute the program that you're seeing there. There are options for additional activity if we have additional funds, but at the same time, a plan to be 100% comfortable regardless of short-term events. There's questions around the EIS. Someone put it quite specifically that the Corps of Engineers has fast-tracked the Great Lakes tunnel. Is there a read over for Pantheon? I'm not sure that there's a specific read over, and we're certainly not familiar enough with the EIS for that to make an informed read over. Max, you wanna talk a little bit about the general state of play from a regulatory and political perspective? I would say at face value, the landscape would be consistent with that. The nature of our footprint is quite small, with a lot of support from the federal government. I'm not gonna put myself in the shoes of whatever factors the U.S. Army Corps of Engineers would use to make this assessment. We're hopeful it's probable that it won't be onerous. Really that's a federal government decision. We'll do everything possible to enable that to occur. I wouldn't wanna put a precise probability on that because it would sort of be unhelpful, I think. Yeah. Someone's shown up with a question. Why did we start with the worst zone at the bottom of the well? Do you want to? See, as we said earlier, with the initial assessment of these six horizons, the view was that each one of them would have mobile oil. That's why we chose to test all six. Operationally, it's more difficult to go top-down than bottom-up to the integrity of the well. Every time you put holes in the casing, that's a potential integrity problem if you go below it. You know, every dollar we spend is shareholder money. Everything we own is shareholder property, so we need to be wise with it. The most cost-effective and systematic way to do this operationally was from the bottom up. It wasn't an assessment that we think offset one is the best reservoir. We're going there first. It just happens to be the deepest one we chose to test. Through cycle of all testing, that would be the most capital efficient way of doing it, all other things being equal. That's why we did it that way. Yeah, the cost profile, or I suppose there are two or three questions. The answer to questions about costs of the well, we are still within the range of estimates that we started with, including contingency. In the context of the earlier answer on funding, we've got plenty of money to complete this operation and other activities planned to move the strategy forward. I think there's a question about the Heights bond. We specifically agreed that we would put the money necessary to repay the Heights bond into an escrow account in order to be able to pay down the Heights bond in cash. That is exactly what we intend to do. That's what provided security for the holders arranged through Stifel Nicolaus. You know, I think the important point to make is we don't have the right to prepay the bond. I'm sure there will be ongoing discussions with the holders of the original bond over time, but we've made provision to make sure that we could meet our contractual obligations on that. Sorry, I just thought someone asked a similar question. I think there are probably some questions that we missed. There were an awful lot that came in, but I tried to make sure that we hit the most of them. If anyone felt that their question wasn't answered, or wasn't put in an appropriate way to get the answer you wanted, contact@pantheonresources.com remains our preferred way forward. We look forward to further updating you as we have additional results. Max, any final words from you? Obviously, thanks for your time, everyone. That's fairly short notice. Your questions are extremely important to me. We didn't disclose anything new today, like, you've seen our press release, but at least I hope it's helpful for all of you to see the world through my eyes. How I look at this data, how we use this data, and when you see a statement in an RNS, where did that come from? I hope this was helpful. If you guys appreciate that, remember, I work for you, not the other way around. Your questions are extremely important, and I wanna make sure everyone's informed, as best we can and when we can. Again, thank you very much for your time today, everyone. Perfect. Max, David, if I may just jump back in there. Thank you very much, indeed, for updating investors this afternoon. Could I please ask investors not to close this session, as you'll now be automatically redirected for the opportunity to provide your feedback in order that the management team can really better understand your views and expectations. This will only take a few moments to complete, but I'm sure it'll be greatly valued by the company. On behalf of the management team of Pantheon Resources PLC, we would like to thank you for attending today's presentation. That now concludes today's session. Good evening to you all.