Good afternoon, ladies and gentlemen. Welcome to the Pantheon Resources investor update. Throughout today's presentation, investors will be in listen-only mode. Questions are encouraged and can be submitted at any time just using the Q&A tab situated on the right-hand side of the screen. Due to the significant attendance on today's call, the company will not be able to answer every question received. We'll have the company review questions post today's meeting. We'll publish those responses where it's appropriate to do so. Before we begin, we'd like to submit the following poll, and I'm sure that the company will be most grateful for your participation. I'd now like to hand over to Chairman David Hobbs. David, good afternoon. Thanks very much indeed, Mark. Thank you everyone for joining us today. Today, what we're going to do is explain the outcome of the Megrez well. We're gonna explain why we drilled it. We're gonna explain why we thought we had a discovery on the basis of the data gathered prior to testing. We're gonna explain the well results. We're going to move to talk about the plan for development of our Ahpun and moving the company to cash flow. We're gonna explain why the Dubhe well will be the next well to be drilled. We're gonna explain its linkage to the Gas Sales Precedent Agreement and moving that forward into a full gas sales agreement. We're gonna explain how that links into our plans for a U.S. listing and finish by talking about the overarching strategy of the company going forward. We'll answer those questions that we didn't already address during the course of the presentation. Let's take a quick step to talk about why did we drill the Megrez well. A number of people have submitted questions directly to the company ahead of the webinar, and this was a common theme. Two reasons, really. The first, it was a very high quality prospect that could have materially improved the development economics of the overall Ahpun development if it had been successful. Second, it allowed us to drill from a gravel pad, which meant that we would have real estate available for development activities even while the environmental regulatory process was proceeding. That is part of the reason we're able to be confident about having a short flash to bang time between approval of the development to proceed and first oil. Based on the risk versus reward and the impact it would have on the wider portfolio, the Board decided to move forward with that well, and it's much easier with hindsight, but at the time, the decision was strongly considered to be the right decision to move forward. We did build the pad, we drilled the well, we raised the funds to drill the well. Incidentally, the funds we raised included for testing so that we were in a position to complete that program. We then, during the course of the period between drilling and while we were analyzing the logs and cores and cuttings data, we restocked financially, raising the $35 million bond with Sun Hung Kai. That has provided us with the runway going forward and a stronger cash position than if we hadn't obviously raised that money. The data that was gathered indicated high oil saturations. It indicated that there was a great likelihood that we would see positive oil flows, and we announced those results of the simulation and the ranges that we expected to see flows. We proceeded with the flow program. At this point, let me hand over to Max to take us through the entire story, both corporately and in terms of the specifics of the Megrez well. Thank you, David, and thanks again to everyone for joining us today. We're gonna save a lot of room for Q&A today, so this will not be 45 minutes of an exhaustive presentation. I think where I would start is the investment proposition. This is almost exactly the same slide that attracted me to Pantheon just two short months ago. Only three things have changed in the two months. One of those, of course, is the outcome of the Megrez well, which talks to the upside potential of it that David just mentioned. The second one is we've secured a much stronger financial position due to the convertible bond from SHK. The third one is the news flow around the company continues to improve further. More positive news from the federal government and state administration promoting a gas line in Alaska, in general. The key point is this 2.6 billion barrels equivalent resource remains intact. As we went into Megrez, we were focused on testing Megrez as well as progressing the primary business case, which of course was the path to commerciality for Ahpun and ultimately Kodiak. The mission or point here is the investment proposition remains almost exactly the same. The only difference here is how much upside did Megrez represent in the overall development plan? Speaking of Megrez. When I arrived two months ago, the mission was an apparent discovery with 1,340 feet of net pay. What's the most capital efficient manner of demonstrating its flow characteristics and ultimate commerciality? The outcome of this, to be very blunt, is we encounter no appreciable hydrocarbons in this well, no material oil production or gas production at all, which in some ways is still a mystery, but we think we understand the mechanism at this time. When we went into this, the original plan, as you will recall, was we didn't feel the need to test Tops et 3 because the Tops et 1 result would be indicative of the Topset 2. That turned out to be a wise decision in retrospect. The plan was to successfully and systematically go through six horizons to test each individual interval for its commerciality. The initial test was Tops et 1. The results were released on April 14. The outcome of that was 12 days of flow testing following hydraulic stimulation, during which time we produced essentially no hydrocarbons. No mobile oil or gas came out of the well. The outcome of that was obviously very surprising given the oil saturations we encountered in the logs, the cuttings, and ultimately cores. The question was, why was there no mobile oil here? Is it simply there's no mobile oil? Do we have a wettability problem? That launched a number of tests to figure out what was wrong with this horizon, and was it indicative of the horizons more shallow. At that point, the objective was to move to Lower Prince Creek, which at face value was a more prospective interval, so higher oil saturations on logs and cuttings than the Tops et 1, and we had the benefit of a direct core measurement this time. Direct core measurements from Tops et 1 and Lower Prince Creek, which showed oil saturations greater than 50%. In any normal petroleum system, you would expect to have mobile oil with oil saturations that high. We were waiting for our frac crew, and we talked about this many times, about the availability of that is really dependent upon the activities of other operators, especially in the spring season. To complete the well all the way to the top of Sag 3, we recognized we needed to add cement to the annulus in the casing, per state regulations. While we were waiting for the frac, we chose to do that, and successfully cemented that, per regulation. Because we were concerned about the wettability of Tops et 1 and associated impact on oil saturation and mobility, we decided we would do a conventional test at Lower Prince Creek before expending the money to hydraulically stimulate it. If we get hydrocarbon on a conventional test, that would give us the confidence to move on and fracture it and move on with the program. We produced the well for a number of days at about 200 barrels a day of water per day being nitrogen lifted, and again, got zero appreciable hydrocarbons. Now we were concerned that this was going to be a repeat of Tops et 1. Rather than doing the expenditure of hydraulic fracturing and getting the same result of Tops et 1, at that point, it was decided to test the viability of the system. Rather than going through sequentially all five horizons, if it didn't work in the most prospective horizon, Sag 3, with the highest permeability and the highest porosity, it's very unlikely to work anywhere in the well. After we issued the release on the nineteenth, showing results of Lower Prince Creek being 100% water and no appreciable hydrocarbons, we immediately moved to Lower Sag 3. Although we got a very high liquid rate between 2,000 and 3,000 barrels of liquid per day, it was essentially pure water. At that point, it became clear to the company that all of these horizons had one thing in common, which was there would be no mobile oil moving into the reservoir. At that time, rather than spend an enormous amount of shareholder funds to get the same result in the other horizons, we decided to suspend this well indefinitely, pending further review of why is oil not mobile, and would there be a development potential for this in the future. The outcome of all of that is there's no question there's hydrocarbons in this system. Logs, cuttings, direct measurements of cores. It's also equally clear that it's not mobile using primary depletion. Either through a fracture stimulation or conventional flow, we never, in any of these intervals, had appreciable hydrocarbons. Our guidance at the moment are there are no commercially recoverable reserves in this well, although it is a fully charged system. Down the road, is there a possibility of producing this through other means? Possibly, but not in the short term and not through conventional means. It wasn't the best use of shareholder funds to do those sort of experiments with the live rig and live equipment on the well. We're gonna park this for now and move on to the primary business plan, which is move on to Ahpun and Kodiak. There's a million questions about this, the details of the assessment, which we'll get to in the Q&A. The blunt result is, through all of these intervals, we achieved zero oil and gas production, despite a very robust charge system. The resource position, it remains. Kodiak and Ahpun West, now just Ahpun, account for nearly 1.6 billion barrels of certified 2C resource. The plan from here is to get back to the primary business plan, to continue it, and drill a demonstration well in Ahpun. 'Cause there's plenty of analysis, vertical wells, flow tests, simulations that demonstrate the viability of this reservoir and associated type curves for the wells. The next activity for us is to drill a horizontal demonstration well with a modern completion and demonstrate the type curve underpinning the business case. In time sequence, it looks like this. Again, not a lot of difference what you have seen before, because Megrez was never part of the development program. It was... It just represented upside, and even in a success case, would have been to the right of the time sequence on this chart. Drilling and testing Megrez has already occurred. We know the result. The next primary activity for us is that demonstration well, and then the regulatory process and timing considerations into the Trans-Alaska Pipeline with an FID in 2027 for Ahpun. Again, nothing has changed in regard to our primary business plan. Just dwell on this for a minute because a lot of people have questions about, well, if Megrez has this issue, would the rest of our prospect inventory have the same issue? On the far right of this diagram is Megrez-1, and those little yellow blobs are the topsets that we were targeting originally, as David said, to add Ahpun inventory. Above that would be the Sag horizons. What's in between those and our Ahpun West and Kodiak is the regional seal. That regional seal is a trap mechanism for our certified resources in Ahpun, then Hue Hill down below for the Kodiak Fan. These are on the other side of that. It is a different petroleum trapping mechanism, and, there's no impact or resemblance, to the assets set to the west. We'll have lots more questions about that, but this was not an appraisal well of Ahpun West, or certainly not an appraisal well for Kodiak. It was testing an entirely different, reservoir architecture. Other things, you know, news flow is still remains quite positive. Our Alaska LNG project is moving forward. The governor of Alaska quite recently announced his intention to have first gas production during the Trump administration, which is within 3.5 years from now. That would be a spectacular outcome for everyone. The point is the news flow continues to be quite positive and a lot of growing optimism that through trade negotiations, Alaska LNG will be part of that, enabling this project to occur. Again, nothing negative has occurred in this horizon and of course, we would be a big part of this. Again, news flow is great. The only real difference between this is beyond the fundamentals of the project. Again, given the strong desire of the United States to balance trade, in particular with Asia, this project is a huge part of that. I think you guys are aware of everything else. I think it's probably time, David, to get to the questions. I know the investors have a million questions about the details. Yeah. Underneath that statement. Let's just get to that. Yeah, absolutely. Sorry, the light's just gone out. That's. There we go. I think that there are a number of questions that are all around the same thing, which I think is worth going back and refreshing. I think, Max, if we go to the cross-section, actually. Yeah. Let's talk about it. There are a lot of questions relating to whether what we've learned tracks across. I think you've already explained why the Megrez test well is of a different geological sequence. I think we can go a little bit further to say that the difference in the resources below the regional top seal, we have flowed oil in those resources. We've demonstrated not only the mobility of the oil, but in terms of the tests in the Alkaid-2 well, both into the Alkaid zone and into the topset further up in the Alkaid-2 well. We've demonstrated mobility of oil and on the basis of the analysis, the ability to produce at rates that would be commercial. That's the reason that, Cawley, Gillespie, in their analysis, you know, they went back to fundamentals and came up with the type curves, therefore the recoveries and the economics that they did. In terms of the Dubhe well, therefore, Max, do you wanna talk about what the Dubhe well is aiming to drill into and to prove? Then we can talk about how that links into the gas sales agreement and the onward development plan. Yes. The interval of Ahpun West, which would be southwest of Megrez location, is the heart of our near field. The Pipeline State- 1 discovery well is in that reservoir interval. Again, this is demonstrated part of the reservoir. The intention of Dubhe-1 is to drill a horizontal well down the heart of this reservoir. At its thickest, it's about 500 feet thick. We'll drill a horizontal well through the thickest part of the reservoir with the modern completion. With that, we will establish a type curve which will underpin the economics of the full development. The way that links into the gas sales arrangement, people will remember if they saw it and will be hearing for the first time if they didn't. When Ryder Scott did an analysis of the resources to confirm to the state that we were in a position to offer the gas that we were offering, they talked about the need for a show-me well that they could see the analysis that supported the high likelihood of being able to provide associated gas along with the oil production at rates that would meet the contractual commitments. In fact, they confirmed that they could see a path to doing so. They also, in their statements about additional appraisal requirements, talked about the absence of a show-me well, and that's the purpose for the Dubhe commercial demonstration well. There is some questions around what does, what would a failure of Dubhe mean? I think we can, there's a fairly simple answer, which is if Dubhe fails to support the case for the ability to provide commercial rates of gas, then it is highly unlikely that we will be moving forward in the very short term into a gas sales agreement. What is the likelihood of that? Given that we have multiple penetrations of the target horizon and we have flowed to demonstrate movable oil, we consider that to be very low risk. It's a different risk than the risk that, as to whether Megrez would flow. Because as we always said, it's a prospective resource until you bring oil to surface. That's the reason that we've never talked about Megrez being more than a prospective resource, and that what would convert it to a contingent resource would be successful flow testing. That didn't happen. The risk profile on the Dubhe well is an appreciably different quantitative and qualitative risk than on the Megrez flow test. That well is certainly one that we are aiming to complete this summer in order to keep the gas pipeline project on track. There are some, I think there are a number of questions around communication, Max, and let me just reiterate what I think you summarized earlier. Starting from the last webinar four weeks ago. What we talked about was what's happened since then, and correct me if I get any of the sequencing out, and to an extent it's a reiterating of what you said. We plugged Tops et 1 zone. We reviewed the cement bond log. We had at the webinar said that we were not sure whether we would be cementing before or after the Lower Prince Creek. It would depend upon the cement bond log. We talked about the uncertainty of whether the frack equipment would be available in the short or the longer term, and that we would therefore try and match the program to minimize the amount of dead time that we wouldn't just be standing around waiting for the frack equipment. I think from some of the questions, it's not clear if the difference between the different pieces of equipment are self-evident. We have a rig, which is the ability to run pipe in and out of the hole. It's the pulling unit, for want of a better description. We have the frack spread, which is the high pressure, high rate pumping system. That's a totally different set of equipment. There is the testing equipment, which is the temporary flowing vessels, the separator, the tanks, et cetera. What we were waiting for was the high pressure pumping equipment. There was no change of the rig. The rig was what spans over the well and what allows intervention down the hole to run plugs or to perforate or whatever else, along the way, the temporary testing equipment, including the nitrogen lift equipment. There was no issue about the availability of the testing equipment and the nitrogen lifting equipment, nor of the rig to be able to intervene in the well. It was purely the high pressure pumping equipment that, in the event, has not yet been released to us. Now, having run the cement squeeze to ensure well integrity, the first step ahead of a frack, particularly if you've got a very tight horizon, there's very little point in doing a pre-frack test of the well. When you've got a higher permeability horizon, where you can get useful information for planning and optimizing the frack, it's not uncommon at all to do an initial inflow test to see what you've got and then to frack. At that point, we were still fully expecting that following that initial inflow, we would be getting the frack equipment, and that test happened in preparation for fracking the well. It was only once we didn't retrieve any appreciable amount of hydrocarbon that the decision, as Max said, was taken not to invest the extra money in a 10, 12 or longer day flow test having fracked it, and to preserve capital for what comes next, which is obviously the program around Dubhe and moving forward. That actually all occurred on Friday, Saturday. The earliest we could release was on the Monday morning. At the time of the release, we were perforating and just starting to flow test the shallow zone, the Sag 3. There are a number of questions about why couldn't we have announced it all in one go. As you're aware, again, we were required but also committed that we would release each result as it became available. The opportunity to have announced that we weren't going to have frack equipment coming on onto the well occurred over a weekend. We didn't put out two announcements at the same time, one saying the frack equipment's available, and then another one saying, "But we're not gonna use it because the initial inflow test has demonstrated that it's not likely to flow appreciable hydrocarbons." Completely understand from the outside how the timing of things appears not to have followed the philosophy of what we described. As it unfolded, the steps happened in the order that we expected. I will hold up our hands and say that it would have been possible to have announced that we had done the cement squeeze before fracking the Lower Prince Creek. I accept that with hindsight that would have led to less confusion about operations. To be honest with you, we didn't think that the order of squeezing versus the flow test was significant or material information. Of course, with the benefit of hindsight, people will weigh differently how material they think that information might have been. Is that consistent, Max, with... The other thing I would add to this is following the result of TS1, we were still quite surprised that we got no oil mobility in that well. The question was, is that an outcome of the reservoir or is that an outcome of introducing completion fluid? You flowed that well back 12 days, which we felt was ample. There's still that lingering concern, did the frack water have an effect on the reservoir? When we swabbed and lifted the well, the intention there was to get a salinity test, produce mobile oil, and then bring in the frack crew. By the time we had that result, of course, after just a few days of testing, there's no need for the frack crew. We issued the result itself that the interval was not prospective. The outcome of that, of course, was the reservoir itself not prospective. It wasn't the frack water in retrospect. In relation to that, Max, there are questions around the logs that were run. What was it that gave us confidence in the likelihood of mobile oil and our confusion as to why there wasn't mobile oil in the initial tests? It's really measuring one interval versus the other rather than an absolute. Lower Prince Creek showed better reservoir properties, both in terms of the CMR, NMR, which shows mobility of fluids in the reservoir, but also the prospective oil saturation. Of course, we got a direct core measurement, which showed that the Lower Prince Creek had higher oil saturations than TS1. It was clearly a more prospective interval. It wasn't a guarantee that it would flow mobile oil, but it was definitely more prospective than TS1, which is what gave us the confidence to move forward and test that interval. Someone's asked a similar sort of question that we think that there's oil wettability, but it could equally be a failure of a fault so that oil has just migrated out. I'm not sure it's an either/or situation. Yeah. It's both/and. Do you wanna expand on that a little bit? We covered this in the last webinar about well, wettability and Rel Perm, but in essence, as applied to this situation, if indeed this is a fully oil-wet reservoir, the saturation you require to make oil mobile will be higher than a water-wet reservoir. That may be singularly the issue here, but it could also be that we don't have a seal on this reservoir, and these are all migration paths, and what's left behind is residual oil saturation. If it is indeed oil-wet, those saturations would be higher than you would see in a water-wet system. I think. It's an and, it's not or there. Yeah, exactly. I think the other thing is, it would be easy to have the impression that oil-wet versus water wet is a binary switch. It's actually, you know, you start at one end, which would be 100% water wet, and it gradually becomes more susceptible to oil wetness. So it's not as simple as there's a binary switch. All reservoirs are either one or the other. It's a gradational thing. Can you talk a little bit about other reservoirs that have been oil-wet and have been producers? There's a bunch of them around the world. It's usually associated with carbonates. I don't know all the reservoirs in the Middle East by name, but in the Middle East, there are quite a number of oil-wet reservoirs. I believe the Wilcox field in Oklahoma is. There are others. Being an oil-wet field does not mean immobile fluids. If you have 100% or a very high oil saturation, and it's oil-wet, it just means you ultimately will produce more water and require tertiary mechanisms to get ultimate recovery, like CO2 and things like that. They're rare, but they're not super rare. Don't read that an oil-wet reservoir means a non-prospective reservoir. It just means that the relative permeability between oil and water will be different at different saturations compared to a water wet one. Back to what we said in the press release on the 19th of May, we thought initially it might be a transition zone. I think partly because we saw higher oil saturations above it, and so it's possible, if it was a continuous column, that what we were seeing at the bottom was lower saturations moving higher. Subsequently, it's clear that we didn't have a single hydrocarbon column. Do you wanna talk a little bit about the independence or linkages between columns? Yeah, I think the initially when you're in the deepest part of the reservoir and you have higher water saturations or immobile oil, it's either a migration path or a transition zone. The way you test that, of course, is you go up the wellbore. You wouldn't have a transition zone all the way to the top of the reservoir. That's why we began moving up the wellbore. I think I would say pretty confidently that it's not a transition zone because to be a transition zone, you have to have a free oil phase at the top of it, and we certainly never discovered that. When you're in the deepest part of the reservoir, that is a possibility. At this stage, that seems quite unlikely now that we've tested all the way to the top of the reservoir. Yeah. I think that at this point, that's the majority of the questions around Megrez. Let's move on to Dubhe. In the Dubhe well, are we going to drill a pilot hole to choose the optimal landing zone? We're scoping the well right now. We're not prepared to describe the entirety of the well design, but that is a standard thing to do when you enter a new horizon. Because when you drill into the reservoir horizontally, it's very difficult to establish lithological control where you are in the reservoir. The wisest thing to do is to drill a pilot hole first, pick the most prospective interval, and then land in the reservoir. I suspect we will do that, but we'll announce the full design and intentions in due course. In terms of the geometry of it, again, roughly, not a commitment subject to, as you say, describing the full design, how long a horizontal or lateral? I'd say as long as practical. Again, we'll do the final well trajectory and design in due course and convey that. I would say it's between five and 10,000 feet, the lateral. Okay. What are the objectives for the well? The ultimate objective is to establish a type curve. First and foremost is land the well, land successfully, do modern completion and extended flowback to, A, get a established type curve, but, B, understand our fluid properties better. The PVT and concentration of gas, natural gas liquids, and oil that emanate from the reservoir fluids. This helps us not only design our facilities in a capital-efficient manner but also underpin the gas contracts. In terms of costs of a well, and I think it probably links into our funding, rather than separating those questions. Do you want to address that? Again, just sort of depends on the final scope of the well, and once we do that, we'll communicate that. In broad terms, a horizontal well would be on the order of $10 million, and a frac should be on the order of $15 million. Once we get the final scope of the well defined and contracts in place, we'll have a more precise figure and an AFE generated. I mean, it was with an eye to that, the additional funding was lined up ahead of the testing on the Megrez as well to put ourselves in a strong position financially, so that we were resilient to the outcome. That brings us on to financing questions. A key part of our financing strategy, I think we've announced in previous webinars over the last 18 months, has been to look at the range of opportunities to minimize dilution to shareholders. I don't think we've ever said there'd be no dilution. We've said there was a possibility of achieving that, but our strategy was to seek to maximize the retained value for existing shareholders. That continues to be the case. If you remember at the start, back in late 2023, we said we were gonna explore vendor and offtaker and potential strategic partnerships as the path forward. During the first half of 2024, we announced that our strategy was to focus on the offtaker financing as a result of the gas sales precedent agreement with AGDC and ASTAR Alaska. That continues to be a key part of our strategy. No change there. At the same time, we've previously said we have investment banks working on pre-U.S. listing funding in the form of strategic transactions, whether that's farm out or other asset related transactions. The sums necessary to get to FID are consistent with what we've previously announced. That from where we are today, we think it's going to take about $150 million from FID to first production. We think that the maximum cash draw after first production to get to self-sufficiency is about another $150 million, so $300 million in total. We've talked about the amount necessary to get to FID, the vast majority of which is covered because it's the step that we talked about was the need for this Dubhe or the Ahpun demonstration well. I think that probably covers as much as we can say on any of the specific financing questions. In terms of progress on environmental and regulation and connection into the Trans-Alaska Pipeline, Max, do you want to talk about the work program that's been going on to move the development planning forward? One bit of very good news this week is everyone is worried about the regulatory path to putting gravel pads on the tundra for developments. We recently received our permit from the U.S. Army Corps of Engineers for the Dubhe-1 pad. That's a huge success for us in terms of well preparation. For the Trans-Alaska Pipeline, we're in negotiations with Alyeska on that. We have our location identified. It's now a matter of engineering to achieve the goal of a hot tap on the line. No new news there, but no showstoppers in sight to achieve that goal at this time. Sorry, have we booked fracking equipment for the Dubhe well? Not just yet, 'cause we don't have the window to do it. Strictly speaking, we may not use conventional frack equipment on the North Slope either. We're gonna consider what hydraulic horsepower equipment we need when we want it. The window for doing that is too far away to contract specifically, because people have very narrow windows for these things. Once it becomes clear what the drilling schedule and completion schedule are, we'll book that at the appropriate time. Certainly couldn't do it at the moment. We'd have to have a 60- or 90-day window at this point. I don't think anyone would be prepared to black out that long of a horizon for their equipment. Yeah. We have begun steps logistically to secure the sand, et cetera. There's sort of a multidisciplinary planning process to make sure that all the pieces come together at the same time. That's underway. The effectiveness, I think probably that means efficiency of frack are we expecting with the Dubhe well? I would point just back to, we saw the Alkaid Zone frack efficiency calculated out at about 25%. That in the top set, we saw a better than 50% frack performance. Our modeling of the type curve has been based on not doing much better than that, although we would expect typical frack efficiencies up near three-quarters to 80%, when compared to other basins and the use of the most modern frack designs. We've addressed whether the Dubhe well has an impact on the gas sales agreement. There were a number of questions pre-submitted that related to the Sag test. Obviously, that's not relevant, given the news that we announced this morning. We've addressed why we targeted Megrez ahead of development. Timelines, Max, I think you've sort of partially covered it. Timelines related to progress on the pipeline. Our aim is not to be the laggard in terms of being ready for when FID for that might be taken. What is the scope if our gas isn't available for the pipeline to go ahead without us? Well, that's a question for the pipeline operator, I think. We're the only source I'm aware of that can ship as drawn in that pipeline. Everything else requires some degree of acid gas removal. I think they would be partially dependent on us, but they would be seeking alternatives, I'm sure. I think we're their preferred supplier. I think that while Point Thomson has probably gas that would meet the pipeline specification initially, there's additional capital, not just for the spur to get to Point Thomson, but also that development is a gas field with condensate rather than an oil field with associated gas. The economics of that development probably mean that it would be very difficult to provide gas at the price that our gas would be available. AGDC have announced that they are making provision for backup gas in the expectation, incidentally, not that it's instead of the Ahpun and Kodiak gas, but it's to increase reliability of the system overall, to make sure that there's always gas available. What are we going to do to rectify the mistrust in the market around our Board of Directors' decision-making, and how does that affect our plan going forward? Is that a question for me? Well, I think it's for both of us. I mean, the correct answer is by continuing to use the best available information to consider it carefully, and to deliver on what we say we're going to deliver. I think it's worth pointing out. Operationally, over the last two years, we've delivered operations in the time frames we talked about delivering them. We can't control geology, we can control what we control. There's no doubt at all that you know, the outcome of the Megrez well came as an unwelcome surprise. Max, you want to talk a little bit about the peer review and other things we did to assess before making announcements. I might just contemplate what the alternative would be if we hadn't shared the data and analysis as presented to us by experts. I would start with the opening question. I think it was two months ago, I was asked that very question. I joined this company to get on the path to commerciality, to pivot from exploration and appraisal to development. I said, "What you should expect out of your CEO is activities and results." The first activity, of course, is a disappointing one. There's no mobile oil in this reservoir, but I hope everyone appreciates that that outcome was done in the most capital efficient manner possible. Had we gone through all six intervals with exhaustive testing, we would have the exact same result and spent an enormous amount of shareholder money. The objective here is to be as capital efficient as we possibly can. Along the way, we engaged a lot of experts, be they from Schlumberger, Core Labs, and everyone was as surprised as we were that given what we saw in cuttings, core and logs, that there was no mobile oil. So along the way, there was exhaustive testing in every imaginable way to understand this phenomenon, which ultimately led to the decision-making to expedite this, given what we saw was a very repeatable phenomenon through the horizons, I would say. Yeah. I think. Look, the Board takes its obligation very seriously to disclose information. If we had all of the internal analysis and the external, peer review of that, analysis saying, "We think there's a high probability of, mobile oil being produced in the test," and we had chosen not to share that, and to say, "Notwithstanding that there are lots of people who think this is, a very high quality, a very high likelihood outcome, you should treat it as being zero," there'd be as many people complaining that we were not, you know, fairly and even-handedly, sharing that information. What we promised was not that we could guarantee positive outcomes. What we promised was that we would be candid with people, that we wouldn't hold back bad news. You know, it doesn't get better with age. That we would make sure that you were in a position as far as possible, allowing for time zones and anything else, to have the same information in summary form that we were using for making the decisions that we made. You know, we will commit to continue doing that. You know, we can promise you candor and an honest appraisal of where we see we're at. There are some questions about the U.S. listing and I want you to come back to that, because at the start, we said this is what we're going to discuss. It's quite clear that a. When we talk about why we drilled the Megrez well, you know, there were reasons linked into the development program, but there were also reasons linked into the market story for a potential U.S. listing. That having that well, and in the success case, that would clearly provide a huge following wind into a U.S. listing. There is nothing that changes the view that this story is best presented, and particularly as it de-risks and with the Dubhe well, that becomes clearer to the market, that the right place for this to be traded and to be listed is on a U.S. exchange. We're still moving forward. Again, the program is predominantly based on minimizing the costs up front and then contingent costs based on the success of that listing program. We are still targeting a end of year, start of next year timetable. Nothing about that has changed. When we look at the progress we've made. There were a number of steps required in terms of implementing and documenting controls that would be Sarbanes-Oxley compliant. Most of that is just good governance, whether we were listing or not, and we would have done. Because as we move from drilling one well a year and the systems that are resilient to that to a full development, absolutely no point in trying to build a full development on a you know on a foundation of sand. It needs to be a solid foundation for building that. In terms of other steps, the restatement of our IFRS accounts to U.S. GAAP that would be necessary for U.S. regulatory filings is a relatively small cost in the overall scheme of moving to the U.S. listing. The large costs are obviously underwriting fees for the capital raised and legal fees in writing the regulatory filings and handling all of that. Those are costs that we have not yet incurred, and we absolutely will not incur unless we believe there's a high likelihood of success in a U.S. listing. The U.S. listing continues to be a key part of our plan, moving forward to provide access to capital and hopefully the rating that's necessary when aligned with the rest of our funding strategy, which is to progress on the monetization of the gas, to progress on strategic transactions that would provide funding, and to put ourselves in a position where to the greatest extent possible, we're not raising money when we need it, but when we decide to. That is consistent with the plan under which we raised an additional $35 million of firepower back in February of this year, and the progress of the plan going forward. Max, is there anything else you want to say in relation to that? No, I think just as you said up front, the Megrez is a disappointing result, but all other aspects of our business plan, including that, are intact. I think that brings us. We're just coming up on 50 minutes. We intended to keep this to less than an hour. The message we would like you to take away is we absolutely understand and feel personally the disappointment at the result of this well test. It's not what was expected based on the technical data. However, we now have removed that uncertainty and that step in the process towards commercialization. We are 100% focused now on the steps necessary to deliver the path to cash flow self-sufficiency that we laid out 18 months ago that we are moving forward to de-risk the gas availability through the Dubhe well drilling the show-me well that was talked about in the documentation around the gas pipeline and taking the steps forward to a U.S. listing and ultimately in 2028 with the hope that with the following wind from regulators and the administration that timetable may be brought forward to delivering oil into the Trans-Alaska Pipeline at the earliest opportunity. Max, is there anything else you'd like to add before we hand back to Mark? No, I would just say that, if you step away from this well needed to be drilled. As David mentioned, it represented proximal inventory on the other side of the highway, very capital efficient if it worked out, and there's a structure above that. It's very disappointing that despite a very strongly oil charged system, we were unable to get primary oil mobility. That just represents upside in the plan. All aspects of what we want to achieve remain. What you should expect from me and the board is to get on with it. Onto the path of commerciality and free cash flow self-sufficiency. Mark, just before handing back to you, there are a number of questions that were either relatively niche or came in quite late during this discussion. We will attempt to aggregate to cover the broad themes and provide written answers to those questions on the IMC website. If there are general questions that are of a more long-lived nature, we will post them also to the Pantheon website. There are a number of questions which, honestly, the way that they have been framed, we're not going to respond to, nor indeed will those questions be published on the website. I would ask that at a minimum, whatever disappointment people may have about the results of the well, that civility is no bad thing. With that, Mark, back to you. That's great. David, Max, thank you once again for updating investors. If I could please ask investors not to close this session, as we'll now automatically redirect you to the opportunity to provide your feedback in order that the company can better understand your views and expectations. Only takes a couple of moments to complete, but I'm sure it'll be greatly valued to the company. On behalf of the management team of Pantheon Resources PLC, we'd like to thank you for attending today's presentation and wish you all a good rest of your day.