Good afternoon, ladies and gentlemen, and welcome to the Pantheon Resources Plc investor presentation. Throughout this recorded presentation, investors will be in listen-only mode. Questions are encouraged and can be submitted at any time using the Q&A tab situated on the right-hand corner of your screen. Just simply type in your questions at any time and press send. Given the significant attendance on today's call, the company will not be able to answer every question it receives during the meeting itself. However, the company can review all questions submitted, and 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 the company will be most grateful for your participation. I'd now like to hand over to Executive Chairman David Hobbs. Good afternoon, sir. Good afternoon to everyone. Good morning if you're in a time zone where it's morning. It's a great pleasure to have an opportunity to talk through the results of the Netherland, Sewell report on Kodiak and to provide some additional context around it and update you on operations. You'll see that there are a lot of presenters today because we wanted to make sure we covered everything that needed to be covered. Without further ado, let's move on in. Please take a moment to read the disclaimer. You can read it in your own time as the presentation has been posted on our website. That'll be available there. We've got a pretty full team to address a wide range of topics. We will take the opportunity to finish addressing the questions that we first started dealing with when we announced the pivot on strategy that has been ongoing for the last couple of months. Today we'll hopefully cover everything that was originally asked. We will do our best to answer any other questions that come up during the course of today's session. As told, we can't guarantee that we'll have enough time. Since we've made a lot of progress over the course of the last couple of months, it's worth just restating to remind everyone what our strategic goal is. That is to deliver sustainable market recognition of $5-$10 per bbl of recoverable marketable liquids by 2028, at the minimum possible dilution of value to existing shareholders. That's what we're on track to do, and the steps that we've taken over the last two or three months have moved us forward in that regard. This webinar will update you on further progress towards that goal. Our agenda today will be to address the results of the Netherland, Sewell & Associates report. In addition to that, Bob and Jerry will be sharing the potential upsides from further appraisal that key off the NSAI Netherland, Sewell numbers. Bob will be talking about the characterization of the fluids, and then Michael talking about the test in the Alkaid-2 well at the Shelf Margin Deltaic zone, and progress towards that. Tony Beilman will be talking about the development planning work. And then between the team, we will address the five contingencies that were referenced in the Netherland, Sewell report, which are the steps that will be necessary to reclassify from resources to reserves in due course. And then finally, Jerry and I will update you on progress against some of the milestones, and we'll move into the Q&A. Bob, can I hand it over to you to talk about the Netherland, Sewell report? Thanks, David. Thank you. Welcome everybody. Look, before we talk about the upside, which we'll get into in a minute, I just wanna review the results from the Netherland, Sewell report. You know, it took us a year to get to this. You know, it's working with Schlumberger, our team working with Schlumberger. Sorry, SLB and Netherland, Sewell. A lot of work has gone into this, and it's a small table, but those are big numbers. Just to, you know, highlight it again, we've got nearly 1 billion bbl of total marketable liquids in the 2C. Our 3C estimate, we have almost or approximately 2 billion bbl of total marketable liquids. This is a great result for us. You know, we should, you know, regard this as, you know, the result of a lot of work, a lot of effort, among a huge number of geoscientists and engineers to get to this point. Next slide, please. Again, you know, what I'd like to do is, you know, is highlight what is actually going on in the reservoir because, you know, that report discusses, oil in place. Sorry, oil numbers, NGLs, condensates and gas. I'd like to take you through a very simple story of actually what is happening in the reservoir. All the information we have, all the test data we have tells us that we have an oil reservoir, a light oil reservoir. The charts you see here are from GeoMark. It says that the source rocks are in the oil-generating window. That we have light oil, that all the gas we've seen is associated gas, which means it's dissolved gas in the reservoir. The complication becomes slightly. This statement is what happens when we are actually beginning testing the well and we drop the pressure in the reservoir below what's called bubble point, which is, you know, the dissolved gas is coming out of solution. That will be addressed by our engineers in a few slides down the line here, and they'll be discussing what's going on after we drop below bubble point and we're testing the well. Simple story, we have black oil, associated gas, oil. The source rocks are in the oil-generating window. Next slide. Again, this is a picture of every single test that we've made, you know, on all our reservoirs. All of them show the same thing. We have black oil, light oil between 35-38, 39 API oil. The gas is associated gas. Next. I'm gonna turn it over to Jerry, and what we're gonna do now is discuss, you know, the appraisal upside on Kodiak through drilling as we go and start appraising this and drilling into what we call the chimney, the recent acreage we picked up in the last lease sale. I'm gonna turn it over to Jerry now. All right. Thanks, Bob. What I wanna talk about here is a model that we've constructed to extrapolate reservoir from known subsurface control at Talitha, Theta West up dip into the chimney and in the western part of the Kodiak Field. Our data set, our subsurface data set is really dominated by two data points, Talitha and Theta West. Of those two, Talitha- A has the denser by far data set. It's got a full set of LWD, wireline logs, FMI, and also sidewall core samples. Theta West, because of hole conditions, we're really restricted to LWD logs. That I think imparts somewhat of a bias on our subsurface description, and what we wanna do is counter that bias by forecasting what porosities and permeabilities, how they should behave going up dip. The next slide. This model is really based on simple geological principles. It's built on compaction, and the principle is simply that a porosity decreases with burial depth. As we go up dip from Talitha- A up to the northwest, we're getting shallower structurally, modern-day structure, but also in the maximum burial depth. There's been less section eroded off up there, so we get a double benefit there. Average porosity will increase from about 9% at Talitha- A, this is across the gross interval of the Kodiak Fan Complex, up to over 12%, almost 13% up in the northwest part of the chimney. If you go to the next slide. I think more importantly, what we can do in this exercise, I'll show you in a minute, is we can calculate the percentage of porosity that's greater than the conventional reservoir cutoff of 0.1 millidarcies. This is a standard cutoff that's employed to determine conventional versus unconventional, and we can calculate what percentage of the gross rock volume is greater than that cutoff. Now I think it's worth spending a few minutes walking through how this is done. This is a series of animations. The first one, now we're gonna look at porosity and permeability relationships. We need three things. We need to be able to relate porosity to permeability. We need a Dmax, and we need a line, a slope that a compaction slope. How do we do that? Well, first we'll do the... In the yellow oval, that's the porosity-permeability relationship. We look at perhaps our closest analog just to the northwest, Meltwater and Tarn. We also have more local samples at Pipeline and Talitha. Those give us a cutoff of about 12% porosity, which would translate into 0.1 millidarcies. We have that. We can go to a more subregional relationship here, that's plotting Dmax versus porosity. You can see the increased porosity to points on the left there with decreasing burial depth. If we can construct a line like that locally at Kodiak, and we can reconstruct Dmax, then we can calculate for every point in the Kodiak Fan what the porosity distribution is, and hence what the where that. How much of that rock is above 0.1 millidarcy. To do that, to get Dmax, we go to the map in the middle. That's based on published USGS data. What that shows is how much of the section has been eroded off. It's missing section that's not present now that we need to add to the modern-day depth to restore to Dmax. That variation is pretty significant. It's about 1,500-2,500 ft difference from north to south. We want to get the slope. The way we do this now, the technique, is to plot up all the log data points at Talitha and Theta West. That's not really a vertical line, it's a whole. It's all of the porosity log points plotted up at their Dmax. We connect the means, that's the red line there, and that's our slope. With that slope and a Dmax, we can calculate anywhere what the average porosity is, and we can calculate what the distribution of those porosities would be. Here's how that looks in practice. On the top left, that shows the actual porosity distributions for Talitha in red and Theta West in blue. That's just a histogram in one percentage point bins for each well. Then in the center, what we're showing is the Theta West actual. It's the blue curve. Then the red one is Talitha using this model, moving it up dip to the Theta West Dmax, and you can see it's almost a perfect match in terms of average porosity. With that same principle, we can just... We can go ahead and calculate porosity everywhere in the Kodiak Fan Complex. The plots on the bottom show is that while we're doing this, remember we're projecting every single point in the porosity log along that slope, the decompaction slope. At Theta West, only about less than 5% of the gross interval is greater than 12% porosity. It's just that little green on the bottom. On the next plot to the right, if we project that up along the slope, the compaction slope, we get to the Theta West location, where about 24% of the porosity is greater, samples are greater than 24%. Sorry, 12%. As we move up to what we'll call the Theta West location, which was on the previous slide, then we're getting up to about 37% porosity. You can see the procedure. It's like an integration of the distribution curves as we move these porosity points up dip. Here's what that looks like. We can take a collection of points that span the depth interval of the Kodiak Fan Complex from deepest to shallowest. The average porosity, so just the average, thinking of those histograms, it's the average porosity is linear, as you'd expect using that linear function. The percentage of porosity, the percentage of gross rock volume that's greater than the 12% or 0.1 millidarcy is non-linear, and it's steeply increasing as we go up dip due to shallower structure, but also less Dmax. As we get up to the northwesterly part, much of the chimney, we're at more than 50% of the reservoir should be considered conventional or more than 0.1 millidarcies. That's a summary. I think with this will have it great implications on recoverability as we move up dip from the known subsurface control at Talitha and Theta West. I think turn that over to Bob. Just make a comment about Jerry's work. What we're gonna see as we, you know, cross over and start appraising the chimney is we're gonna see, you know, better reservoir deliverability, which is gonna give us, you know, probably higher recovery factors. In the case of what Jerry's describing, you know, an increase in volumetrics as well, in place volumetrics, 'cause we're gonna have better porosities and permeabilities. This is really a placeholder for work done by Roger Young. We planned to have Roger present his work in detail, but he had some medical issues that he had to take care of, and he's been out of commission for several weeks. I'm gonna do a poor man's job and summarize Roger's work. Later on, we will have a bit of a webinar so Roger can actually show this. Second factor that's going to impact, and in this case, it's gonna impact our understanding about reservoir deliverability and recovery, is the fact that the reservoir we're looking at in the Theta West fan in the Kodiak discovery is a very thin-bedded, laminated sand and shales. Which means that when we examine the data in detail, when we have it, such as like an FMI or a whole core, what we see is centimeter scale beds. Now, our logging tools that we have, the MWD and all the electric logs, tools that we have, are actually gonna be averaging a lot of that data over a foot or 2 ft. Basically, we're kinda smearing and averaging out the information in these thin beds. Now, that's not gonna affect our gross rock volumes, but what Roger's been able to do, going back, looking at the whole core data pipeline, looking sidewall cores and looking at the log data is we are not seeing the higher porosity permeability beds. They're being smeared into an average background, which just basically means that you know, what we can expect to see is almost two-five porosity units above this average background that we're getting in the conventional logs and the wireline logging tools. As we go up dip to Theta West, we expect to see in the higher porosity zones, up to 15%-20% porosity range, and permeability is much better, 0.5 millidarcies. The only way we're gonna be able to see all this is take whole core. It's incumbent on us when we're drilling our next well that it's not just a test of flow rates, but we need to collect significant amount of data to verify what we've been talking about over the last you know, few slides. You know, getting this whole core data is gonna be hugely important for our reservoir characterization. This one slide here is telling us, with the work that Jerry's also done, is that we can expect to see better recovery factors and better reservoir performance as we move to the north into the chimney. I think turn it back over to you guys. Mute. Agreed. Thanks. Not quite sure who was muted. The next thing we want to address are the five contingencies from the NSAI report on Kodiak. In this section, you will hear from Michael Duncan. Michael, welcome back. The last time you saw him, he was one day removed from some very serious knee surgery. Welcome back to the walking, Michael. Thank you. Good to be back. From Pat Galvin and Tony Beilman. In section one, technical data that demonstrate sufficient rates and volumes to sustain economic viability, and we've got questions about that, Michael Duncan will do that. The field development plan and regulatory permits, that'll be Pat Galvin. Viable gas and water utilization and disposal methods, Tony Beilman will take care of that. Our ability to market our oil and our NGLs and condensates, no one better than Pat Galvin to take on that task. Then David and I will comment on all of the work that we've been really doing the last really two months to fund the complete development project, and as David said earlier, with the least amount of dilution for our current shareholders. With that, I will turn it over to Michael. Thank you, Jay. Happy to be here a little further removed from surgery, as you mentioned, and recovering appropriately. Glad to be walking again. Yeah, looking forward, obviously our next steps that we've discussed and the things we're really excited about operationally are showing our path towards the true economic viability of these reservoirs. Upcoming is the Shelf Margin Deltaic tests, and that is a quest to understand new fracking techniques. It's a quest to understand the PVT data in the reservoir a little better. As we go, you know, a lot of this determination is based on our pressures that we see. It's another opportunity for a piece of the puzzle in our virgin reservoir pressure campaign. Those three commence soon. We are applying a new fracture technique to the Shelf Margin Deltaic. Tony might discuss that a little more, but it's finer proppant, it's thinner fluid. It's the next step, as Tony's mentioned, in our frack generations and more correlative to what you see present day in, say, Permian or other places. We're applying that frack to the Shelf Margin Deltaic tests. To give a quick operational update on what's happening, we still believe we're on schedule to start in September. We're really at the fun part right now for the camp analogy. We're all packing our bags and making sure we have all our gear before we head up there. Equipment's descending on the slope. People are beginning to descend on the slope. We have boots on the ground with the early operations, and so that's happening right now. In parallel to that, we do have ongoing analysis with Schlumberger. We're looking to future development plans and modeling how these new frack designs will propagate in the development. Looking forward to that, and as Bob said, of course, operationally, whole cores are gonna be very significant to our future. Bob, I apologize for this. I might pass this to you really quick to talk over to Tony about the recombination of fluids. Tony or Bob, would you guys like to take this one? Sure. I think as everybody knows, the reservoir fluids that we're dealing with here, unlike water, is highly compressible. A clear understanding, as we talked about earlier, Bob mentioned and Michael mentioned, was having some PVT analysis done as we move forward. For those who don't know, PVT analysis really just means pressure, volume, and temperature analysis with these compressible fluids. The volume is highly dependent on the pressure and the temperature and as fluid changes in pressure and temperature from the reservoir moving forward, that's a big consideration, and we wanna make sure that we understand that. As Bob mentioned earlier, on the Alkaid #2, GeoMark Research was retained to start that process. They looked at the fluids that came out of the Alkaid #2 and kinda gave us some good reservoir numbers to work with. We took those numbers and that data and provided that to Schlumberger, who has an active simulation model where they could model what they were seeing and take that fluid and put it back to a reservoir condition. What the conclusion of both GeoMark and Schlumberger is, we are, as Bob mentioned, a solution gas drive reservoir. We're not sitting in a gas reservoir, it's just a solution gas drive reservoir. We're currently producing below the bubble point. Those are the numbers that we're seeing. Based on that, this slide here shows you some of the snap views of what Schlumberger's modeling did. Based off that analysis, they matched the GOR, which was a big number we needed to match of what we were seeing off the Alkaid #2. We're pretty confident we have a good handle on what the reservoir is looking like. Then moving forward with the test that we have on the Alkaid #2, we're hoping that we'll have a good understanding of what's going on in the SMD formation as well. Before we move on, would you just maybe give a little more color on the frack versus the frack we put on the horizontal portion that we're planning now, Tony? Sure. What we've done different on the frack job, we've done a little bit more selective perfing, perforation selections. We've changed the fluid type of fluid and the chemical add that we're adding to it a little bit better to help with the flow back. We've moved to a 100 mesh sand. We've gotten away from the 30/50, which we believe kinda hurt us a little bit on the sand flow back as well as. We've also doubled the rate. I think we're somewhere around 400,000 lbs and about 11,000 gal going into this stage. That's kinda becoming our horizontal model, and we've kinda taken it to put it in this vertical section. Incidentally, Schlumberger did a pretty detailed analysis of all the fracks that we've done, and this is kinda sitting in the middle of where they recommend that we sit as well. What we're trying to do is determine the efficiency of this new frack design. That's correct. We need to find out what the frack heights are doing and how the reservoir's behaving with these new jobs. It's not really ideal to maximize production. We're probably gonna flow this back slowly so we can get a better feel for how the fluid's behaving. We're gonna run some bottom hole pressure data so we can see what the reservoir pressure looks like. Great. Thanks. Pat, over to you. Thank you, David. I've been asked to just give an overview of what permitting will look like going into a development project. Really, this is fairly standard for any project on the North Slope, but we happen to have the minimum aspect of it because of our location. The primary driver is going to be the unit plan of development, which comes from the Department of Natural Resources, done in conjunction with a plan of operations. That will be sort of the overview across the entire development plan. Because we're going to initially have pipelines that will connect our facility to the hot tap location, we're going to need to get a right of way for those pipeline locations along whichever route is best determined for those. The hot tap itself is going to be approved by the Regulatory Commission of Alaska. That location you can see here on the slide is located really within sight lines, just a little around a mile from the Alkaid pad that we're proposing. Finally, we got an air quality permit requirement that would be part of any development that has emissions. We're intending to minimize those air emissions, so we don't expect the air quality permitting to be significantly onerous. The one thing about this slide to note is really what's not on this list. Typically, historically, with any North Slope activity, you would see a wetland development permit or wetland fill permit from the Corps of Engineers. Because of the recent Sackett decision from the U.S. Supreme Court, that has changed the entire outlook for wetland permitting on the North Slope. Previously, we would've expected nearly all of the land that we would be developing would be subject to a wetland determination and a wetland permit. With the Sackett decision and the new initial proposed regulatory changes, it's actually flipped it around to where we expect very minimal designated wetlands. Likely, we can avoid a federal permit requirement across most of our development acreage, which significantly changes the overall permitting expectation and may even avoid the environmental impact statement process that most other projects have to go through. We're watching that one closely as that develops and the wetland rules become more known and applicable, and we're seeing significantly positive movement on that. I think that's the primary overview right now. Yeah. Back to you Tony. Sure. As Michael mentioned, we were working with Schlumberger or SLB, and it's getting hard to switch back and forth, so. Anyway, their work is taking forward the data that we had. They're modeling the best development practice or the development plan that we can come up with and how we can maximize both the production reserve and minimize the cost of development. We hope to have that done the first quarter or quarter two of next year. We've actually engaged them, and we've already started that process. Hopefully we'll get that data done. They're taking the data and putting it in a dynamic model, which is really handy because we can watch it as, you know, you can simulate different sensitivities that'll help address all those questions that are coming, which includes how we're gonna handle the gas, how we're gonna handle the water and so forth. Really excited about the report coming out. Handling the gas and water is critical because we're gonna have a lot of excess gas, and we will produce water throughout the life of the Yeah, water is not unexpected. The gas is not unexpected, but, you know, it's a good thing. It's kind of a double-edged sword. The gas is providing some very valuable liquids that are really enhancing us, but we still got to get rid of the gas. A lot of energy too. A lot of energy. We'll be able to, and we're pretty excited about the plan that's gonna come out as well, so. Great. Can I add? Yes. In terms of getting our product to market, it's important to note, as we've covered in previous webinars, that our entire marketable liquid stream, including the NGLs and the condensates, are all going to go with the oil down the Trans-Alaska Pipeline. As we've noted, Trans-Alaska Pipeline is a common carrier pipeline, which means it's open access, regulated by the Federal Energy Regulatory Commission, to allow for new shippers like us to bring our product to market. The NGLs will be transported along with the crude and included in our stream and in the valuation of our stream, which gives us the opportunity for uplift associated with our higher value NGLs that are going in with the oil. As we've covered in previous webinars, the entire stream is evaluated and broken down to its individual components. Each of those components is then priced separately, and there is an adjustment on basically what you put into the pipeline versus what you get out, depending upon the value of those individual components in your stream in comparison to the others. Our initial analysis indicates that, really from a conservative standpoint, we're looking at about a 90% of the current stream value. Which means that in the end, if we put in 100 bbl at the input to the pipeline at our hot tap, we would right now anticipate getting out about 90 bbl at the terminus when we take it out. Great. Okay. Where are we in terms of going toward our goal of between $5 and $10 of value for Pantheon, based on our resource estimates? Going from left to right, you can see we're starting to shade some of the areas. That means those that we have started to have progress on. The big thing, of course, that we haven't talked about today is how do we finance the $350 million that we've talked about, or David has talked about all in the past. In reality, we don't really need to raise all of that $350 million today, and we're pretty certain that we won't need to raise all of it in the future from our shareholders. That is what we have the team here in Houston this week working for. We've been meeting with investment banks, the resource groups of investment bankers. We've met with the service providers to talk about how can we partner with this great project and reduce the amount of capital that's required. The amount of capital that's truly required to get to first significant production is about $120 million, not the $350 million that's the headline number. That's what we're moving toward. We're working very diligently on that. We've had some great meetings. We will have some more. In addition, as you know, we have a data room that's open. We have some interest in companies coming and looking into our data room. We are moving on all fronts to finance what's ahead of us. As you've heard, we have the NSAI report on Ahpun that probably will spill over into the first quarter of next year as they get very busy toward the end of the year doing end-of-year reserve reports for others. We have the Alkaid-2 reentry of the Shelf Margin Deltaic test coming up. That's an exciting time for us and all of the work that's going on behind the scenes technically and with moving toward potential U.S. listing and getting a permit to put our crude or our liquids into the Trans-Alaska Pipeline. David, would you like to add? Sure. Yeah. No, thanks, Jay. Just to reiterate, every conversation that we're having is about how do we reduce the call on equity, because that will end up being the balancing item. Talking with lenders about what they will need to see before we're able to draw on financing facilities. The $350 million, don't forget, was based on $300 million associated with the initial production and $50 million associated with the further appraisal of Kodiak. That $50 million will be invested in the timeline that leads us towards the FID in 2028, as mentioned, and based on how we can assemble the project to ensure trouble-free operations and to gather all the data that we need along that way. Coming back to the $300 million, which is the residual for bringing us to cash self-sufficiency. That is the point at which we don't require any additional capital, whether it be debt, whether it's equity, whether it's mezzanine, whether it's lender financing, whatever it may be. Drawing back from that, we anticipate that the need for around $120 million that won't be fundable from reserve-based lending by the time that it's being spent. That, if you recall, was made up of a very conservative assumption of $20 million for the hot tap, $20 million for the upgrade to facilities to add to the existing facility that we already have, adding a chilling unit. I know every time I say $20 million worth of facilities, the team looks at me and says, "Man, you don't trust us. We know we can do it a hell of a lot cheaper than that." We want to make sure that we plan conservatively, because if you ever need a dollar, that dollar always costs you more than you expect it to, whereas if you plan for it and I don't need to call on the money, that ends up being much cheaper money. Although we have a pathway and we've described the pathway down to $13 million per development well in today's terms, obviously escalation over time because this is a 10- and 20-year drilling program. We're assuming that those initial wells are gonna come in at above that budget, and so we need to make sure that we've properly funded ourselves for that. Of course, there's some overhead to keep the business running to maintain the engineering studies and development planning and regulatory planning. That's where we get to the total of $120 million. Every conversation we're having is based around how can our partners in this development help reduce that quantity down to something. Ultimately, it may be possible to get it to zero. There's absolutely no promise, but our goal is driving towards zero. Every night, Justin, Jay, and I go to bed, our separate beds but thinking the same thought, which is how do we make sure that we can raise the funds on terms that ensure the minimum valuation to our shareholders? Some of the things that we've done over the course of the last few months, we've identified where our office is going to be in Houston. In fact, it's right next door to where we're sitting today. We're borrowing an office all together here in order to move forward with this webinar using the conference facility there. We have begun the process of those financing discussions. In order to reduce the supply of equity or loose equity into the market, you saw we did the deal with IBKR. We are working on a daily basis, to ensure that the ability to bet against the stock because there is an assumption of supply of stock is an unsafe assumption, to be made. I would just like to add, you know, the market obviously reacted very favorably to that, we believe. Yes. Because the share price has- Yes. ... moved up smartly. That's right. I mean, the steps we're taking, you know, there's a lot of boring stuff going on. They're all small steps that lead to a point. As I said, in an earlier webinar when people said, "Gosh, 2028 is a long time to wait for the value you're talking about." When we get to the point at which that value becomes inevitable, we expect that to be reflected in the market sooner. That's why we're doing all things to put in place the steps necessary to deliver that goal in 2028. The advisors are at work, expected to report shortly on the tax implications of either a U.S. or a dual listing or a change in domicile of the company. We absolutely recognize that there are implications for different groups of shareholders of the decision we take, which is why we're not trying to take that decision lightly, and make sure that we've considered all of the angles, on that. In summary, we will arrive at the point in late 2025, we hope, and at worst, early 2026 where we're in a position to take FID on the approved development with all the permits we require from the state, with all the financing sorted out. That's the point at which, resources will be classifiable as reserves if all of those other, contingencies are addressed. To move forward during that period of build-up of production, to make sure that we've got the Kodiak FID in 2028 and to continue building up to what we think is going to be one of the most exciting projects in the last couple of decades onshore in the United States. I would just like to add that many of the meetings we've had this week have been surprisingly positive. So, for first or second meetings, very positive. In no small measure, but because by being able to bring the Netherland, Sewell report- Yes. ... to the table, it means instead of just being the latest guys to show up in Houston saying, "We've got a great project," the right people are opening the door, and engaging in a serious way. Let's hand it back to Paul, and then. David, thank you so much, and to the rest of the team from Pantheon Resources. Ladies and gentlemen, please do continue to submit your questions just using the Q&A tab situated on the right-hand corner of your screen. Just while the team take a few moments to review the questions you submitted already, I'd like to remind you that a recording of this presentation, along with a copy of the slides and the published Q&A, can be accessed via your Investor Meet Company dashboard. David, if I may invite you just to open up the Q&A tab. It's on the right-hand corner of your screen. You'll see questions from investors. Firstly, thank you to everybody for your engagement. If I may, David, if I ask you to just read out the question and give responses, obviously, where it's appropriate to do so, and I'll pick up from you at the end. Thanks very much indeed. So the first one, is there any correlation between the Alkaid-2 upcoming flow test with the 88 Energy asset, they're planning to test this winter? Assuming both Pantheon and 88 Energy flow well and commercial rate, is there any chance of a merger of both companies or JV or asset acquisition? Well, let me just handle the first bit first, and then ask Bob to comment. The first bit first is, we're not going to talk about any potential transaction or speculate about that, whether with 88 Energy or any other. We have got a very good working relationship with 88 Energy. Bob, let me hand that over to you to talk about. Yeah, thanks, David. We do have a very good working relationship with 88 Energy. You know, over the last several months, we've been working together, very collegial relationship, you know, sharing data. Obviously, I can't, you know, express any opinion at all on their data at Hickory. We're under confidentiality. You know, as a general statement, you know, we're working towards helping them in any way possible to get a positive result down there. Anything positive that happens down there is good for us. We're certainly, you know, working, you know, just getting as much information as we can to make that happen. The next question is, what kind of results from the upcoming SMD testing would unequivocally demonstrate to industry participants and potential farming partners that the SMDs/Alkaid are unquestionably a resounding commercial success, leaving no room for doubt? Although the trite answer to that is, there is no result that could possibly leave no room for doubt. In simple terms, if we can improve the quality of data, demonstrate the efficiency of the frack and the utility of the revised and updated frack design, that will only add to the perception of the likelihood of success. What I can tell you is that the perception that it is uncertain is more widely held among the investor community than it is among the industry community. We're certainly not finding that people are in doubt about the likelihood of the viability of the asset in the conversations that we're having with them. Well, let me just add also that we're not planning for a headline flow rate. That's not the purpose of the re-entry and the test. As Tony and Michael have said, we're about data gathering and determining the efficiency of the new frack design. We need to remember that our intent is to understand the reservoir fluid and how they're behaving and how the frack performs so we can plan future frack jobs. That's really the main driver behind what we're doing. Yeah. Next one is, you've been talking about having an asset quote for some time. You've been very positive in conjunction with an institutional investor roadshow in the U.S. Is that something that's progressing? Justin, do you want to just respond to that? Yeah, sure, David. I think you touched upon a few of those points previously. There's two parts to that question. The first is the listing, and the second is the roadshow. Addressing the first on the listing, like any relationship, it's important to get it right and to make those right decisions. We're meeting as many groups as we can to choose the group that's relevant, that believes in our story. That we believe has got the capability, not only on the equity market side and the investment banking side, but also project finance and those kinds of things. And as David, I think you mentioned, having that Netherland, Sewell report in our hand has really increased our credibility going to any of those meetings. We're certainly being taken very seriously. That's that. There's a question about which exchange we're listed on, Nasdaq, NYSE, which level on those exchanges, or do we perhaps migrate up to the London Stock Exchange main board? Dual list, we're considering all those things, and we've appointed, you know, very serious firm of tax advisors to assist us with our structuring to make sure we get that right, because as everybody's heard, the size of the prize here... Well, the right size, the price here is enormous, and it's very, very important to make those decisions and plan for them appropriately. On the second part of the question on the institutional roadshow, the answer is we haven't done one yet, but we will be doing it shortly. The reason for that is obviously we wanted to get the Netherland report in our back pocket, and also we wanted to put this webinar into the public market to allow us to have more serious conversations with all those people. The answer is we're doing a non-deal roadshow pretty soon. It'll be not a one-off. It'll be a program that we repeat from at a regular interval to just build up those relationships. Yeah, our broker in London, Canaccord, is preparing for that at the moment. Thanks. The hedge fund is short your stock in size. Does this worry you? Nah. The bears on your stock say the oil is not commercially recoverable. Can you give a percentage of probability on your oil being commercial? Again, we're not in the business of offering percentages. You can read into certainly my view on the basis of my investment in the company. The advisors we're working with are in no doubt as to the commerciality of it, but nothing is ever a certainty in this business. The IAR has a dynamic modeling. What else will the level of detail and SLB reports support other than a farm-out process? When do you currently anticipate the additional reports being finished and their conclusions shared by RNS? Well, certainly, we've already talked about the likely delivery for the Aberdeen reports. Tony, do you wanna just say a word or two about how we'll be using the SLB work in development planning? I know you already mentioned it. Sure. As I mentioned, you know, part of the project that we have ongoing with Schlumberger is to do a project development plan, which includes how we're gonna handle all of the streams and stuff. That is still anticipated. The plan conclusion should be around the first quarter, second quarter of next year. Great. Bob, I think this one's for you. The information released to date appears so far to be confusing regarding what was found above the Theta West- 1 lower basin floor fan. Was this done on purpose because of the 2022 lease form? Yes. The answer is it is confusing. I mean, what we've seen in the upper basin floor fan is, you know, one set of data from the AVO is telling us, you know, something about it, and our log analysis is telling us something slightly different. What we found in all our tests is when there's a correlation, one-to-one correlation between the AVO and the log data, we've had success. Everything we've tested when that happens has been, you know, positive. At this stage, we're still analyzing that and trying to understand why we're seeing these differences. Eventually, somewhere in the future appraisal of, you know, Theta West, we're gonna be banging into the upper basin floor fan again and hopefully, you know, maybe do a test in it. Right now, we, you know, we don't have plans to target any well for it. Bob, I'll combine a couple. How are eSeis predictions performing? If the 3D attributes at the Theta West- 1 location predicted the upper basin floor fan to be hydrocarbon pay, what lessons were learned? You sort of addressed the second half there already, but go ahead. In terms of eSeis, again, I think their predictions have been pretty much spot on. Particularly at Theta West, at Alkaid #2, we've had very good correlation. We certainly can see light oil in reservoir. We've talked about. Well, you've addressed whether VSP and the physical logs are consistent in predicting hydrocarbon pay. The upper basin floor fan has not gone away. It is part of future appraisal, but it is not part of the resource that we're describing as Kodiak for the time being. Correct. The orientation of the new chimney leases suggests a slope apron fan turbidite-like or forced regression. AVO shows some seismic lines to define prospect limits of the new resource add. I think I should take that question. I'll answer it by saying, Brett, at this time, we're not gonna do that. I'm assuming that must be from Brett. I think we'll pass on that one. The possible sandwich reservoir in the huge shale has different oil than the lower basin floor fan. Any implications for development? Again, Bob, if you want to deal with that. Again, this has to do with the upper basin floor fan. You know, again, what we are seeing are differences in there in terms of the hydrocarbon content or the presence of reservoir. It will have implications when, you know, when we appraise it in the future. This one's for you. The Kuparuk River is east of the chimney leases. Will this make ice road building or development more challenging? I guess that's probably my question. Should I take that one, David? Yeah. I guess the most correct answer is yes, it'll make it more challenging. If the implication is, will it make it so that we can't develop it, the answer is no, that it won't preclude us from further appraising or developing it. All right. What we believe. Can I make a... Yes. Can I just interject a statement there about that Chimney acreage, and just to highlight something about it, again. That's the work that we've done, that Jerry's done, the work that Roger has done, all of that is highlighting that acreage, you know, will have substantial amount of the reservoir is gonna be what we, you know, would be considered conventional reservoir, substantial amount. You know, we're gonna have better recovery factors and, you know, it's gonna impact, you know, particularly Jerry's work is gonna have an impact on the oil in place, hydrocarbons in place. It is a very cool piece of acreage. Yeah, thanks, Bob. Is there only a small section of the west 900 ft pay that was perforated and fracked, given the operational constraints? Does management believe the well could have produced at near commercial rates from this vertical well bore had more sections been tested? I'm guessing, Michael, do you wanna address that? Sure. Yes, there is viability of the concept that we could have connected to more rock. You know, we're always dealing with timing and resource constraints in the winter. As far as what we would have hit had we stimulated more rock, I don't know that it's appropriate to speculate towards that. Yes, there's absolutely viability to the concept that with time and resources and without some of the constraints of winter or ice operations in one season, and with even some of our new approaches, that there's a lot more rock we could have stimulated and a lot of excitement for what that could mean. Thanks. Bob, can you comment on the implications of 88 Energy's testing program for Pantheon's projects, and should any of the resources be unitized with 88 Energy? Well, I'm gonna pass on the unitization part and just answer that again, you know, a positive result there will have a positive implication for us. Again, we're working towards that and, you know, to help as much as we can to ensure that happens. Thanks. Next question was around the $350 million. I think we dealt with that in the webinar. Another question, in a recent interview, you said the Netherland, Sewell report would allow us to have high-value conversations. Are they ongoing? We talked about it definitely causes doors to be opened less skeptically than otherwise might have been. We are talking with a number of people, industry, finance, service organizations, regulators. The key point is that it provides that validation of the development case that we've been talking about. That means that counterparties see it as being a good investment of their time to engage with us. Indeed, we are having high-value conversations with a number of different organizations. On the resource table slide, the discussions focus on oil and NGLs, but the residual gas resource is not discussed in the valuation sense. Why is that, and is there any value to be created from the gas? Let me just give a quick answer to that, which is that our base case and all our economic analysis and the argument for the resource being commercially developable lie upon three basic foundations. The first is that the fluids are the same across the entirety of the resource base, even though there's reason to believe that we will see proportionately less gas in other locations in our acreage. The second is that the reservoir rock is all as poor as the zone of interest in the Alkaid-2. That is, by all measures, the lowest quality rock we have in our development. We are absolutely confident that if we can economically develop those rocks, then everything else is going to be proportionately more valuable and more commercially attractive. The third tenet is that we will have to reinject all of the gas and water that we produce, the water into aquifers, not into the reservoir, the gas back into the reservoir. We have allowed for one injection well for every three production wells that we have. You can add that up over the 2,000 or so wells that we would expect to have as part of this development, and that tells you that we're going to be investing $5 billion-$6 billion over the course of the next 10 and 20 years to handle gas reinjection. There are other options for handling that, not least of which is to take that gas to the north, and building a pipeline to where gas injection is needed and where gas injection is easier, may well represent an optimization that we haven't even begun to factor. That will be part of the development planning work that Tony and Michael are undertaking with SLB. Furthermore, should there become a gas offtake route, and there are in the public domain discussions about gas offtake from the North Slope, whether to an LNG plant on the North Slope itself or an energy offtake down in Nikiski on the south coast. Of course, that would materially alter the economic outlook. That I think in simple terms is what the gas means and the opportunity for us. I'll answer that. Yeah. How accurate or confidence percentages are handling with the porosity extrapolations? Are there any key assumptions? Bob, do you or Jerry want to take that? Well, I'll take that one and say, you know, so far predictions from Talitha to Theta West looks pretty good. The geologic model that Jerry is actually talking to is, you know, pretty standard stuff of, you know, as you go deeper, your porosities and permeabilities go down. If we go shallower in the other direction, which is what we're continuing to do from drilling Talitha to Theta West to a Theta West two location, we're gonna continue going up dip. We'd certainly expect the porosities and permeabilities to improve. Let me just add something to that. The model I showed was based solely on compaction. We also expect as we go up to the north and west that we should see improved reservoir facies development as well as we get closer to the sediment source. That's not shown in the numbers that you saw today. All of your data really is based on empirical data. It's just an extrapolation of empirical data. Yeah. It's just, again, a very straightforward application of porosity versus depth relationship. Correct. I think the key point is this is not a unique hypothesis based on Pantheon's acreage or Pantheon's activities. This is just generally well-accepted geotechnical analysis. Correct. Kodiak looks compelling. Current commentary is that we won't be drilling this for five years. Given the size and scale of this field and the current economics, are you sure this isn't going to drill for so long? The answer is that, Kodiak, we will be getting to as quickly as we can get the relevant development consent. Of course, moving away from the Dalton Highway, requires additional work than just, putting pads alongside the Dalton Highway. The answer is, once we've got to the point of having development consents and financing in place and cash self-sufficiency, we will have a portfolio of some 2,000 development locations. But in terms of economic optimization, whatever one does, it will be to choose the next highest value opportunity for deploying capital. Our current plan says, yes, we start off alongside the highway, developing our boom, and then we move gradually, and we get to Kodiak in due course. The answer is, as soon as we have consent for that, then Kodiak enters the portfolio of investment opportunities, and we optimize to maximize value in terms of the risk value added for every dollar invested. We're certainly gonna be appraising, you know, Kodiak, you know, sooner than. Sooner than that. Yes. Yes. Yeah. Prior to 2028. Yeah. We're gonna be appraising this very soon as soon as we can. Will the updated CPR include more detail on commerciality in comparison to the Kodiak CPR? The simple answer is that the initial work on the development economics will be done in conjunction with SLB as part of the contract we've let to them. In due course, as we remove contingencies related with the assets, as noted in our earlier discussion, then it will make sense for an independent expert to opine on the value. Of course, if we need that in relation to financing, then of course we will do that. For the time being, we're seeking to spend the minimum amount of money to move the project forward as far as possible. At every step we're taking, the question we ask ourselves is, does this investment of effort, of time, of money move us nearer to our objective of delivering $5-$10 per bbl, nearer to the objective of becoming financially self-sufficient so that we become a price maker, not a price taker? If the answer is it doesn't move us there, then we don't do it. If it does move us in that direction, then we do it. Does the gas in solution make the Alkaid reservoir an unlikely target in the future? No. The gas in solution has positives as well as negatives in terms of supplying energy for development. In any case, the gas delivers around about 100 bbl per million cu ft. That adds to the economic attractiveness of development. Yes, we see that the Alkaid zone of interest and the other horizons in the Shelf Margin Deltaic, which make up the Alkaid field, will be attractive propositions. Do any of management have any personal financial requirements as they did last year that could lead to a sale of shares, no matter how small, or options? I'm not aware of any member of the executive team having personal financial requirements, nor would I expect to ask them to declare them on a webinar with other people. All directors are subject to the share code that we have for Pantheon senior management and will be handled through all the regular processes. We're unaware of anyone wanting to sell, and I would be surprised if anyone wanted to sell. Certainly I can answer for myself, no. The impending CPR for Alkaid, will it include the Alkaid Deep as well as the original Alkaid anomaly? Bob, you're probably best placed to talk about the scope, for the initial and then subsequent updating report. The answer is what it's gonna have is the Alkaid anomaly, Alkaid Deep and the Shelf Margin Deltaic. Sorry, at the Alkaid anomaly and Alkaid Deep. That's what the next thing from Netherland Sewell will be. It won't include the Shelf Margin Deltaic because they'll be still evaluating that from the test. The first thing out is Alkaid and the Alkaid Deep. Thanks. Tony, I think this one's for you. You mentioned 2,000, 3,000 cu ft per bbl earlier, and you've indicated 500 in the slide today. Can you just explain? It's an artifact of how the analysis is done, but go ahead. Absolutely. As again, that slide came from Schlumberger, and that was calculating where the reservoir stood at a saturation point. If you, everybody will recall, I mentioned that we were producing and the reservoir was below the bubble point. For that, so that number is reflective of what the reservoir would be at its bubble point. For that modeling, Schlumberger determined the bubble point to be somewhere around 4,500-4,700 lbs. That number reflected to what it would be if the reservoir was at 4,700, 4,500, 4,700 lbs. In fairness to Tony, just before we started, Tony said, "We picked up the that slide from SLB." Yeah. If someone's gonna be confused by that, and I said, "It's too late." The presentation has been uploaded. You may have to explain it, so thank you, Tony. We actually believe the reservoir is slightly below- Yeah. ... the bubble point. Whatever. That, you know, that makes it even more complex. Yeah. Final one that we've got here. Do the team see any engineering risks in re-injecting gas into a relatively tight reservoir? Tony, do you wanna speak to that? Can you say that question again? Do you see engineering risks in re-injecting gas into relatively tight reservoirs? I do not see the risk as far as re-inject. Obviously, we produced quite a bit out of the Alkaid #2. I think what will happen, as you mentioned, David, we'll probably have a combination of re-injection. We may have to take some of that to some of the more permeable areas of the reservoir, but that's part of the model that'll tell us what we need to do with it. That's part of the task that Schlumberger has been given to. It'll typically be a horsepower issue. It will be a horsepower issue. Yeah. It's more an economic question than it is an engineering question. Yes, that's correct. Thanks very much. Listen, I'm gonna hand you back to closing remarks. That's great, David, and to the whole team, thank you very much indeed for your engagement. Thank you once again to all the investors for your questions and your engagement. David, if any further questions do come in, obviously, we'll make those available, and we can add any responses to the platform if it's appropriate to do so. I know investor feedback, particularly with the number of investors on today's call, will be important to you, and I'll shortly redirect those on the call to give you their thoughts and their expectations. David, if I may, before doing so, if I could just hand back just for a couple of closing comments, and then I'll redirect investors for feedback. Thanks very much. What has been presented to you today has been closing out a process that's been going on for two or three months, where we said we would sweep up all of the historic questions that had been asked prior to other webinars. Going forward, we will continue to use the Q&A function in relation to these webinars as we have anything to update. Anything that's price sensitive will be released through an RNS as you would expect. The steps we've taken, none of them have been large, transformative, flashy steps that would cause any kind of rerating. They are the things that we need to do, both in the eyes of the industry, potential partners, potential providers of funding, and service providers, in order for the project to be treated with the seriousness that we treat it. We have no doubt, as a board, that we're embarked on the right course of action. We hope that confidence will build over time among investors and that you'll come along with us on the journey. That what you've seen is that we're taking thoughtful steps in relation to financing to ensure that we are not the wrong side of the curve in terms of needing to access funds from a position of weakness, and instead, to build a position of strength. We will continue that work on an ongoing basis. We will plan conservatively, and we will make sure that we have all the pieces in place to deliver on the plans that we set out. Just as we said, that we had anticipated mobilizing the All American rig during September. There's work going on, but we will only put the rig on site at the point that everything is available, and that right now looks like it'll be next week during the final week of September as we thought it would be. In terms of when we will drill the next appraisal well on Theta West, in that further up-dip location within the Kodiak field, that will happen again when we've got all the right pieces assembled to make sure that we gather the data that we need that moves the development forward. I'll just leave you with a thank you for joining us for this webinar. Don't hesitate if you have any questions that didn't have an opportunity to be asked here, then contact@pantheonresources.com is the place to send them to. We will ensure that we respond to anything with you as quickly as we're able to. We will, at a minimum, sweep up questions and respond to people at least on a weekly basis. I look forward to addressing you from Houston once the U.S. Embassy in London has completed the visa process. I'm led to understand that should be in early November. The team is getting together here on a regular basis already. Thanks very much, and over to you, Paul. That's great. Thank you very much indeed to David and to the team from Pantheon Resources. Ladies and gentlemen, please could I ask you now to close this session as we'll now automatically redirect you for the opportunity to provide your feedback in order that the company can better understand your views and expectations. This only takes 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'd like to thank you for attending today's presentation. Good evening to you all.