Good afternoon, ladies and gentlemen. Welcome to the Pantheon Resources Strategy and Operations Update. 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 just situated on the right-hand corner of your screen. Just simply type in your question and press send. Given the significant attendance on today's call, the company will not be in a position to answer every question it receives during the meeting itself, though the company can review all questions and will publish those responses where it's appropriate to do so. Before we begin, we'd like to submit the following poll, and if you give that your kind attention, I'm sure the company will be most grateful. I'd now like to hand over to CEO Jay Cheatham. Good afternoon. Oh, thank you. Thank you very much. Good afternoon, good evening, good morning, wherever you are. I'm Jay Cheatham. I'm the CEO. David Hobbs is also on the presentation now. As we promised, we are giving a strategy update. We promised that we would be transparent and give strategy updates regularly, and this is one of them. I'm gonna put up the disclaimer. I urge you please to read the disclaimer. It's very important. If you've watched our webinars before, you've seen this. This is an outline of our acreage in the blue. We are in on state lands. The yellow are the legacy fields. They are all pre-Brookian fields. You'll see the kind of pinkish color with the green flowing through them. Those are the Brookian fields that are coming on stream in the near future. On the left-hand side, we have a type log, and this shows all of the reservoirs that are in our acreage, our 193,000 acres, from the Decker D, which is a top seal at the top, down through the bottom seal, which is the HRZ, and that's over 3,000 ft of oil column. It is a huge column of oil sitting there, all trapped by that upper Decker D seal. As you can see, we are, as I mentioned, on state lands. The red outline is our proprietary three-D seismic, and you can see the Dalton Highway and the Trans-Alaska Pipeline traverse our acreage on the eastern side. Our Ahpun field, this is all of the reservoirs from the Decker D top seal down to the Hue Shale, which is both a seal and a source rock, comprising several reservoirs. The top is the SMD and the bottom is the Alkaid Deep. We have estimated over 481 million barrels 2C recoverable. That's a company estimate on, in these. Netherland Sewell is currently working on an independent expert report on Kodiak, and we expect that report to come out in mid-2024. As I mentioned, we have previously estimated almost 500 million barrels recoverable there. About 200 million barrels or 250 million barrels of that is recoverable from pads that we can place along the Dalton Highway and the remainder on pads that we would place west of the Dalton Highway. Our second field is the Kodiak field. Netherland, Sewell issued an independent expert report on Kodiak, and they gave us 963 million barrels of marketable liquids. It is the reservoir from the Hue Shale down to the HRZ, which is a combination source rock and seal. The Kodiak is a huge field comprising almost 100,000 acres. I failed to mention that the Ahpun field is about 65,000 or 70,000 acres. They're both very large and huge areal extent and large columns, about between 600 and 950 feet of column in the Kodiak field. As I mentioned, the Ahpun field at current estimate from the company, 481 million, 200 million barrels ultimate recovery from along the highway. We estimate $300 million of net cash investment to achieve a positive net operating cash flow, and David will go into more detail on that later in the presentation. $120 million to first production, which consists of a $20 million upgrade to our permanent production facility on the Alkaid-2 pad. Three wells for about $20 million each. $20 million to lay a pipeline a mile and a half north of Alkaid to where we plan to tap into the Trans-Alaska Pipeline and place the pumping and metering equipment at that location. $20 million of general and administrative. As I mentioned, additional pads would be up to 5 mi from the Dalton Highway corridor, 200 million+ EUR from those. On the Kodiak field, and the Kodiak field has been defined by two wells that we drilled, the Talitha A and the Theta West wells. They were 10.5 mi apart in such a large area that we believe three further appraisal wells are required to reach FID. That's about an additional $50 million of investment. Multiple pads required up to 10 mi from the Dalton Highway and Trans-Alaska Pipeline. As I said earlier, Netherland Sewell put 963 million barrels recoverable contingent resource. On that field, the development CapEx will be funded from the operating cash flows generated from the Ahpun field, where we estimate we will do final investment decision in late 2025, with production coming on stream in 2026. We also have other discoveries, the slope fans, in the Ahpun area, the upper basin floor fan in the Kuparuk, in the Kodiak, and part of that is in Ahpun. Thanks very much, Jay. Let's take a look at and refresh in our minds the strategy that we laid out at the end of June and that we're starting to execute on. That's the purpose of this webinar, is to add more depth to the information we previously shared, tie the whole story together, because of course, as we've released it a chapter at a time, it's important to remember that not everyone has read all the first chapters before they get to where we're at. This is an attempt to tie it all together and to talk through in more detail where the numbers come from for the financing requirement, how we intend to fund it, and what steps we're taking. Here I'd just like to let you know that the two positive steps that have happened since the last time we did a webinar, we have now got a Houston office out near the Galleria. We have begun a process of transition to become Sarbanes-Oxley compliant in order that whatever the final structure is, whether it's a dual listing or a U.S. listing, we are in a position to move forward. The next news on that is likely to be the appointment of a U.S. investment banking advisor and lawyers to take us through that process. Jay talked about the Netherland Sewell assessment of Kodiak, and our company estimate previously released has been 1.78 billion barrels. Jay also talked about three wells required to get to FID. The reason for those additional wells is that in terms of the certainty about where the heart of the resource lies, how far west it may extend, how far up dip, and therefore how much outreach you can have from pads. These are parts of the development planning process. We're looking to drill additional wells to prove up the reservoir quality as we move to what we think will be the best part of the reservoir. You'll remember that in the last webinar, Jay talked about our expectation was that the most likely outcome for the total recoverable resources of Kodiak would be nearer what Netherland Sewell came up to as the high estimate. The reason we ran through, if you remember, was that as we moved to shallower reservoirs that haven't been buried as deeply, they have better porosity. As the porosity increases linearly, as you move upwards in the column, the permeability increases exponentially. We get to a point at which in the far northwest of the resource, in the new acreage that we picked up last time, the likelihood was that as much as 50% of that reservoir could be conventional. That has enormous implications for both the recoverable volumes, the recovery factor, because the higher permeability rocks for the same porosity will typically have a lower water saturation and therefore more original hydrocarbons in place. Also you'll be able to recover a greater proportion of those. That's the reason that we want to drill those wells to be able to demonstrate that as we move from the Netherland Sewell analysis, which was based on effectively capping the properties at the best seen in Theta West, to provide additional data points, to provide full whole core that would allow detailed analysis of the exact structure of the reservoir and would allow us to demonstrate larger volumes which would underpin our then development planning. The heart of what we're gonna be presenting today is going to be around what the cash flows look like in start up of the development and then how we're hoping to be able to fund those costs. We've said repeatedly that our strategy is to minimize the amount of equity required, and that means maximizing the non-equity funding options. What we're going to be discussing is what's the planning basis for the development wells that we're gonna drill? What does the field development plan look like, and what regulatory permits are we gonna need? The ongoing analytical work by SLB, how we're going to export the liquids and the potential for gas offtake. And then finally, as we mentioned, funding that leads into the final investment decision. I want to kick off with the planning basis, which is pulling up what we showed in those early webinars in July, following the analysis of the Alkaid-2 well test. What you'll remember was we talked about the recovery from the Alkaid-2 well based on the frack that we had and the 5,000 ft of lateral that we expected to be able to recover around 300,000 bbl from that well based on the material balance. That's measuring how much fluid we took out, how the pressure behaved as a result of extracting that amount of fluid, and then being able to extrapolate that to the end of a likely production life. Our contention at the time was that a 500 bpd initial rate and with potentially 300,000 bbl, that by doubling the length of the lateral and by doubling the efficiency of the frack, which was mostly to do with keeping more of the frack in the reservoir interval and therefore getting more lateral extension, which would mean a larger swept volume, because what you're doing is you're producing between the frack legs, almost linear production between those frack traces, that we would be able to get a 4x uplift from the 300,000 bbl. That would give us 1.2 million barrels. We have taken a 20% haircut on that, in order to make sure that we've got a planning basis, which is as conservative as needs to be to ensure that we're not gonna be surprised at the downside. Similarly, by doubling the length of the well, and by doubling the reservoir area exposed in the frack, you don't quite get a 4x increase in the production. We have assumed that we only get a 3x increase in the production because you get pressure drops along the longer well bore. That's the basis on which we've modeled is that 1,500 barrels per day of marketable liquids, it declines by 60% in the first year. We've assumed that all of the wells, even as we move further west where the reservoir quality improves, where we could be drilling some of the early development wells, we've nonetheless used as a planning basis for liquidity planning and for funding strategy a basis with 1 million barrels per well and an initial rate of 1,500 barrels a day, which with the 60% decline, leads you to a little under 1,000 barrels a day average during the first year. We've talked a little bit about the cost assumptions. We've said that there are always snafus when you start up, even though we can see a clear path by simply doing the same job we did in the Alkaid-2 well, but not having to do any of the one-off things that you have to do for a single appraisal well, because you don't mobilize and demobilize the rig every time. You don't mobilize and demobilize the frack spread. You don't have to do a pilot hole. You don't have to run wireline logs in addition to LWD, et cetera, et cetera. We can get down to $13 million a well. We've assumed that the first 3 wells are gonna cost $20 million each, and subsequent wells will cost $15 million each. Because again, it's important that we plan on a basis where we're sure that surprises are gonna be to the upside, not the downside. As we've scheduled in those wells, we've assumed that we start with 1 rig. After we've drilled the first three wells, we'll move that rig to the second pad, the Theta pad, and we'll start fracking those initial three wells, and there'll be a recompletion of the Alkaid-2 well as an injector. We'll move a second rig in to begin drilling, so we'll have simultaneous operations through until the 15th month of two rigs before we mobilize a third rig. We'll use batch completions to make sure that we're using equipment efficiently. What does that look like? Well, our planning basis is on the left-hand side of this chart. The planning basis is saying rather than taking the flush production at the start and seeing it decline over the course of the year, let us just use the average for the first year as we bring on wells, and then it drops to the average for the second year. From 950 bpd to 470 bpd, and that we just add wells on the schedule that I've just described, starting with one rig, going to two rigs, and ultimately to three rigs. What we see is that we get to around 15,000 bpd by the end of 2027, start of 2028. We've also mentioned if you had a chance to read the press release we put out just before this webinar. We've also taken the analysis that was done by SLB, and we've applied our own view, again, taking a more conservative view than SLB's base case to create what we think is our best estimate, as in the most likely outcome on a per well basis. What that shows is the wells kicking off at a higher initial production rate because we think we can do better. In fact, in the Alkaid-2 reentry, we had a better frack outcome than just a doubling from the 20% we estimated from the long-term test. That leads us to the profile on the right-hand side. Here we've got wells that average around 1,500 bpd during the first year and in terms of their ultimate recovery, they recover around 1.65 million barrels over their life. You can see this makes an appreciable difference where we get above 20,000 bpd. These numbers on the vertical scale are the number of barrels per month, which we've used for the cash flow planning that I'm about to show you. You can see how the additional wells phase in. This is to show you what we think the most likely outcome is, but let me re-stress, this is not the basis of planning. The basis of all of our liquidity and funding planning is on the basis of the left-hand side, that 1 million barrels per well and less than 1,000 bpd average through the first year. That then takes us to what do the cash flows look like? What you can see if we continually drill and complete and we throw in, you can see that every third month is an additional well being put in there because it's effectively four wells in three months when you've got to two rigs operating. Then as we get to the third rig operating, you could have a slight acceleration. We haven't accelerated it, but you could have a slight acceleration in terms of how quickly you turn them out. What you see on that planning basis, and we've provided the detailed numbers in the press release to show you how that's made up. You've got the additional cost in that second month of production, where you've got the funding of a second set of facilities and a second pad. That's the Theta West that we talk about. Then after that, it's just drilling costs through this planning horizon. What you see is we max out at around $220 million cumulative net negative cash flow. That's the basis from which it gradually comes back to full payout. Each well has around a one-year payout at $70 a barrel and less than a year at $80 a barrel. This is the point at which we can begin to borrow, so that the actual net cash position is improving once we've reached the point where we've got sufficient wells to be able to borrow against. If we look at what our expectation case is, our best estimate, what you see is that in an $80 a barrel world, we could be in a position where we have achieved payback on the full investment of getting to financial self-sufficiency within 12 months. Think about how resilient that development is and how different it is to have a total cost to get to first production of $120 million versus more than $1 billion, an order of magnitude larger for the Pikka development and nearly two orders of magnitude larger in the case of the Willow development going further west. The reason that the Pikka development has a smaller capital to get to first production is because they're making use of pre-existing facilities in the Kuparuk field in order to save some of that capex at the start. They're very different developments because, in reality, our development plan looks like a very cold version of West Texas rather than more like a typical North Slope development that looks like a big offshore development, where you've got an enormous amount of capital before you can begin your first production. We may come back. I'm sure there'll be questions around that when we get to the Q&A session. We wanted to present to you what the financial anatomy of this project is in order that when we talk about funding, you can begin to draw your own conclusions as to what is the likelihood and scale of potential equity funding required over and above the other channels that we're going to be talking about today. Jay, can I turn it over to you? Yes. Now, thank you, David. Here we're looking at the Alkaid-2 pad. You can see in the foreground is our permanent production facility. You can see the tanks. The wellhead is to the right. Further to the right, you can see the Dalton Highway, and it's buried, but the Trans-Alaska Pipeline is just opposite the highway on the right-hand side, but actually crosses the highway a little north of our location. We propose to hot tap into the Trans-Alaska Pipeline about 1.5 mi on the east side of the Dalton Highway, north of our location. There are major milestones. One, we need the state to approve our unit development plan. We see no impediments in the state approving our unit developments. The state is our partner. We work with them every day, through multiple agencies, and we have a great relationship with them. Of course, we have Pat Galvin on our staff. We will need a state pipeline right-of-way lease to have our pipeline go up on the west side of the Dalton Highway. We need hot tap design approval. That work is underway. We'll need a federal permit for that from the Federal Energy Regulatory Commission. Hot taps are done all the time in the Lower 48. This will be the first one on the North Slope. However, it is an open access pipeline, so we cannot be denied access. We are planning on 18 months and $20 million, which is way more than it should cost. An air quality permit, and you've heard us all talk about our plans to be zero emission, zero air emissions in our development by burning natural gas on location, reinjecting all of our excess natural gas and our CO2 back into either the production formation or another formation. Of course, we'll reinject our water as well. We see no impediments from any of this going forward. Now, we are currently working with SLB and have been working with them for more than a year, and they have developed, you've heard all of us talk about a more than 13 million cell model, working as a dynamic model to do well level analysis to estimate production. They'll estimate production forecast for the full field. They'll put together a conceptual field development plan with our people, and that final report is expected in Q2 of 2024. We will get ultimate recoveries and well spacing and scheduling. We'll get P10, P50, P90 production forecasts, and we'll get the complete report from the output of that dynamic model. That'll include gas and water injection well analysis. As David has said, and I have said in the past, we're currently planning on one injection well for every three production wells. On to you, David. Yeah, sure. Just on that last point about injection, the profile of gas production obviously will need to be revisited in the light of the Alkaid-2 reentry. All our planning for the time being is being done on the basis of what we saw in the original long-term production test. Until we've got analysis back from GeoMark, and we've managed to convince ourselves that the situation is more favorable in terms of quantities of gas to reinject, all of our planning is being done on the basis of what we saw in the long-term test. We've talked about previously access to the Trans-Alaska Pipeline. One of the points that we raised in the press release and to stress to you now is that there are a variety of ways in which the agreements for moving liquids off the North Slope can be structured. We could become a shipper in the Trans-Alaska Pipeline. We could be a lifter of oil at Valdez. There would be consequences of that in terms of a nondiscriminatory tariff. We might have to wait until we'd filled a full Aframax tanker to be able to take it out of Valdez. That would delay revenue and make revenue much chunkier. We might be able to combine lifting with other marketers of crude. We might be able to sell to one of the existing shippers. We have, for the time being, when planning liquidity, we've assumed that we have the lumpiest, most delayed revenue possible, so that then any deal we might do with one of the existing shippers is going to be potentially would need to be a better deal than doing it ourselves. You'll see this has been the theme throughout. We've made sure that our base plan is something that we can execute without relying upon the goodwill of anyone else. Any improvement from that is gonna be on the basis of mutually win-win deals with third parties. That would be the case in terms of liquids. In the news, what you've seen on a number of occasions over the last few months is that Alaska has been progressing a gas export option. This is being driven more than anything else by the growing or the looming deficit of gas down in the Cook Inlet and South Central Alaska, which is where Anchorage and most of consuming industry in Alaska is going to require natural gas down there. That's bringing an urgency to the development of a pipeline from the North Slope, where in the legacy field, there's some 40 trillion cu ft of gas mostly being reinjected into the Prudhoe Bay reservoir. In addition, there's around 10 trillion cu ft out of that 40 is in Point Thompson, where gas is being recycled in a condensate development there. The plan involves LNG exports that would also involve a large carbon capture and sequestration plant up in Deadhorse. The most recent public statement from the Alaska Gasline Development Corporation has been that they're looking for their FID in 2025 to go ahead, and they have been talking with potential partners who are gonna come in to fund that development. We are anticipating that as a potential producer of natural gas along the pipeline route, and with a common interest in that, we will have gas available for sale probably sooner than any of the existing gas producers. Also there is a benefit to us in terms of reducing the costs of gas reinjection by potentially reducing the number of gas reinjection wells. There ought to be a basis on which we can benefit from the gas pipeline, while the gas pipeline would also benefit from our being able to provide gas at very competitive prices. In terms of what does that mean, you can see there's a big bar, well, not a big bar, but a bar about halfway down, which is financing for the Ahpun development. The pillars of our intended financing are to talk to vendors, to talk to offtakers, to talk to banks and other lending institutions. I think Jay has been leading on some of the vendor financing discussions. Maybe, Jay, you can provide a bit of an update on that. Yes. Well, when you're talking about a development that has literally up to 2,000 wells, and we are looking for partners. We're looking for a partner to, in the drilling side, in the tool side, in the fracking side. It's easy to see how a combination of the working interest partner and partners on those three could see a way for us to get some early vendor financing from one or more of those, and it would be beneficial to both of us. I urge you to read the RNS that was out this morning on how that benefits both parties. Both parties can come out ahead on that. It allows us to accelerate what we would do. We're well advanced on discussions with all of the usual suspects that you can name. We are undertaking those, and we expect that we will hopefully have something to report in the new year. It's a pretty exciting time for us in that regard. In terms of offtaker financing, there are different time frames for different potential offtakers. Clearly, once we get to nearer the point at which we will have production coming into the pipeline, one can be talking with oil trade houses, with some of the marketing companies who have typically been prepared to provide VPPs. This is not cheap financing in terms of the coupon or the APR, if you like, on that financing. But it is very cheap financing when compared to potential dilution at lower valuations of the equity. We'll come back to the equity, whether that's through the asset or through the corporation in a moment. In addition, if we are able to secure a place in the portfolio of gas going into the pipeline, that's likely to provide bankable offtake contract there as well. Whether we transact directly with the offtaker in terms of some kind of acceleration, or we are able to take their covenant, their balance sheet, if you like, as the security for the gas offtake to a lending institution, that would be the other part of that. When we get into reserve-based lending, we've said several times before, but it's worth repeating here, that the degree of diversification of our revenue stream simply needs to be broad enough that the risk committees of these lenders are not concerned about an individual well or two wells falling over and undermining the basis of the credit. We have planned that comes at around 6-8, even potentially nine, production wells. That's the reason why when we looked at our cash drawdown, we have said, "Yes, it takes us $120 million to get to first production." There may be some larger negative net cash flow before we can get to reserve-based lending. Once we get there, then we should be able to draw down $250 million pretty quickly against the value of the reserves that would then be proved producing reserves. That would leave for us between $100 million and $150 million that needed to be funded prior to being able to draw down on debt, reserve-based lending. If we look at, as Jay said, with the scale of contracts we're talking about, we're anticipating spending with the three major vendor packages. That's the drilling contractors, it's the downhole tools and directional drilling, and it is the completions. We're expecting to be spending up more than $100 million during the course of the first year. That's the sort of scale of what's in play in terms of the discussions that we're having. In terms of offtake, again, we're talking about three digits, not two, in terms of the amount of financing we may be able to raise against the offtake. It's not saying there won't be any equity call, but it's also saying that we can't guarantee there will be an equity call when we put the whole package together. Our timing is, as Jay says, to look to be in a position to share detailed and in some cases, executed arrangements by the end of the first quarter of 2024. Jay, do you wanna talk any more about the scheduling here on this? Yes. I think it's instructive. We are planning the Ahpun full FID in late 2025, with being on production as you can build it up from David's graphs in 2026. The FID on Kodiak in 2028. The three additional wells, we would drill them toward the end of that time period and be on production soon after that. It's easy to see how we build it up from one rig to two rigs to three rigs and on. As David mentioned, we would ultimately do batch drilling. The batch drilling would be, we would have a spud rig that would drill down to surface casing, move over and drill down to surface casing on the next well, and your directional drilling rig would come in behind the spud rig. You have a spud rig, a directional drilling rig, two directional drilling rigs, one spud rig, three and one et cetera, and then you come in with your frack equipment behind that. It's completely ultimately a batch. As David mentioned, it's Permian Basin North. That's the way we get our costs down. That's the way we would ultimately develop it, and we would pick the best locations that give us the highest present values for the next well. In that context, Jay, I neglected to mention earlier that Jay and the team have already begun looking at the long lead time items, making sure that the program comes together so that if we do achieve FID at the end of 2025, it's not a question of then starting from zero, it's actually being able to have the bit hit the tundra, you know, at the very start of 2026. That's the basis on which we're showing the production build up during 2026. That's- Yeah. There is a lot of work to getting sand, tubulars, horsepower, both the fracking horsepower that we want, 'cause we want the ultimate frack units to be all electric, and the pumping horsepower just for our own internal use, going into the Trans-Alaska Pipeline, the reinjection. There's a lot of horsepower necessary for all of that. Thanks. That really takes us through, I think, pretty much to the end. Here's just a restatement of where we're, you know, where our strategy is. I think with that, Mark, if I can hand it back to you while we move into Q&A. That's great. Thank you, Jay, David, for updating investors this afternoon. Ladies, 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 guys take a couple of moments to review your questions submitted already, I just wanted to remind you that the 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 hand back to you. We did receive a number of questions from investors ahead of today's presentation and several throughout it, so thank you to everybody for your engagement. If I may, David, just hand back to you to read out the questions, and I'll pick up from you at the end. Certainly. Thanks, Mark. The first question actually speaks straight back to the financing. Why do you not have an equity partner as one of your main three pillars of financing? That's very simple in that there are, of course, four pillars of financing, but in terms of the basis on which we would find an equity partner, whether that is at the asset level or at the corporate level, would be from our perspective in shareholders' best interest to do so from a position of strength. That means having brought forward financing from non-equity sources to the greatest extent possible so that that way we were dealing from a position where we weren't requiring 100% of the finance from an equity partner. Under those circumstances. There's another question, which is, are we worried that we haven't attracted a potential farm-in investor? The main issue holding that back is our perception of what this is worth, knowing that financed, it is worth considerably more than the stock market currently values the assets at, and therefore being able to change that perception, deal from a position of strength and get offers that reflect a fair value for shareholders. When we started out with this refreshed strategy, it was on the basis that we were seeking to minimize the value dilution for existing shareholders, not to take the easy path of just say, "Well, hell, you know, divest 50% to cover our capital and then, you know, financing is behind us." We think we can do better than that, and that's what we absolutely intend to do. Jay, there's one I think for you, which is, we've talked in the past about using Alkaid-2 as an injection well in 2019. We talked about suspending Alkaid-1 suspended and freeze protected as a future development well. Will Pantheon ever re-enter Alkaid-1, Alcor, Merak, Talitha or Theta West? Well, certainly we have plans to use the Talitha wellbore. The Alkaid-1 wellbore is available. I haven't talked to the operating group about Alcor and Merak. I'm not even sure how they were plugged and abandoned, so we'd have to review that. All things are possible. Michael and I were talking earlier this week, and the eleventh commandment of oil and gas people is never plug a well until you have to. We'll keep the wellbores available until we decide we cannot use them. Again, back in 2019, Michael Duncan talked about trucking production to Pump Station 1. Jay, you've reiterated it at various times, but we've decided to go for a hot tap. Why is that? Well, we did truck 10,000 bbl of earlier this year and some last year, and the cost was just prohibitive. We made a joint decision that we are going to use a hot tap. It fits into our development plans well, and we won't have to pay the exorbitant amounts we paid to actually pump our oil into someone else's tank. It's basically there is more value lost in terms of access charges than the cost of delay? Yes, absolutely. Yeah. Without naming names, how many different entities are we talking to about vendor financing? I think sort of cuts into a more general topic of, you know, are we talking to a few people or a large number of people? Before I hand it over to you, Jay, I know I was trying to count up when I saw this question, how many NDAs we've got currently extant, and I know that it's at least six in relation to people who are talking about funding with us. But That, yeah, that's about the right number. Less than 10, but growing. Yeah. Someone said, if they send you an old ARCO hat from their dad's collection, will you wear it in one of the videos when we start drilling for good luck? Gladly, I will wear it. Yeah. Absolutely. I have fond memories of my 30 years at ARCO. I think more than just your dad will be happy that something ARCO discovered in 1988 will have turned into something big. There are more questions about actively seeking a partner. Jay, I mean, we've discussed this at length in the past and in our internal discussions that we're absolutely not against the idea of bringing in a partner, but it's gotta be on terms that are reasonable for our investors. It's gotta be something that adds value over and above what we're capable of doing ourselves. Jay, do you want to comment on that? I had this discussion with one of the people that's in the data room, and I just said, "You know, if you're thinking you can come in based on our current market cap or any, you know, or even some uplift from that, we're not interested." I was assured that they are looking at a project level, and anything that they would do would be at a project level. If someone comes in and wants to be a partner with us and can look at it from a project level and see the kind of value we see, obviously we're interested in talking with them. Yeah. I think that's the key point. People coming into the data room and doing deep analysis are investing several hundred thousand dollars of their time and effort, and cost. We just don't think it would be ethical to allow them to spend that money in the expectation that they were gonna be able to trade on the basis of market cap. We've had those conversations. We mentioned in the presentation that we will be updating a lot of our development planning to incorporate the reentry into the Alkaid-2 well, particularly the lower measured, and hopefully recombination sample calculated GORs will give us a clearer idea. Jay and Netherland, Sewell have already, you know, stated that that'll be a big part of their evaluations going forward. The one on Ahpun, in fact, that's the someone's asked why has the original guidance on the Netherland Sewell report on Ahpun slipped from the end of 2023 to the middle of 2024. Part of the reason for that, we mentioned it in the announcement today, that when we started out and Netherland Sewell were first contracted, it was thinking about different reservoirs. As it's become clear, planning for the regulatory process and the development that we need to look at Ahpun as a single field, we're asking Netherland Sewell to address Ahpun in its entirety. They couldn't obviously start that until we've done the reentry and tested those shelf break zones. We certainly didn't want to pay premium prices to have Netherland Sewell be pushing through the busiest time of year for year-end reserve reporting for U.S. publicly listed companies. So we were prepared to let that pushback in terms of getting something in a timeframe that was appropriate for our development planning without spending money unnecessarily on that. There's a question about the number of injection wells. We don't think, Jay, in terms of the one injection well for three, even with the lower gas oil ratio, we're not planning, are we. Yeah. We ultimately think that there'll be fewer than that required simply because that's based on a pretty low permeability and porosity regime. Of course, as you've mentioned, the gas pipeline will solve a lot of those problems going forward. Yeah. Certainly remove a lot of cost. Someone was exploring porosity in Alkaid and Theta, which I mean I'm suggesting means the wells, but we haven't given detailed information in the presentations. I would say we have, in that we've shown graphs that actually probably we've shown more detail than many people would show in those situations. We've shown them at a level that I remember before joining Pantheon, I was able to scale off average porosities and permeabilities. Particularly what you've seen is in the chart we showed earlier. In fact, I can just flip back to it for a second. Well, we showed that in more detail in the last webinar too, David. Yeah. Exactly. No, I was gonna say. How that was built up, in fact, with the statistical analysis. The averages and the depths and the formations are accessible in this chart here. Someone has asked about what's the lowest price at which the Ahpun project would remain commercially viable for FID. I know from the modeling we've done on the basis of the minimum type curve of 1 million barrels starting at 1,500 bpd you would get down to around a 20% rate of return post-tax at around $65 for ANS. If you use our best estimate case then the number goes down into the forties. If you don't need to drill as many injection wells because there's a gas offtake then that number could even start with a three. It's too early really to be getting into flexing about how resilient to low oil prices we are until we're further along the way in terms of our development planning, because for the time being, we're stress testing at the technical level, rather than planning for what's the minimum oil price. Jay, actually, we've got Bob standing by to be able to answer some questions. Bob, maybe you should unmute and unblock your video. There's a question around what are we expecting to learn from the flow tests at Hickory this winter? Good question. Well, that's a good question. You know, I think we're very focused on their slope section. What we're hoping, you know, the first thing we're hoping to see is what kind of fluids they get out of it and, you know, obviously what kind of frack job they use to test. I'm hoping they focus on their slope and the Shelf Margin Deltaic myself. They've announced the results for the Basin Floor Fan, and I think it's consistent to what we thought they would have there. You know, well, you know, we're waiting to see. I think the position that they're in terms of where they're testing the well. All our acreage is updip from where they're testing. So I'll just leave it like that. Well, that'll be important information for Netherland, Sewell, as well. Totally. It'll certainly contribute to our Ahpun analysis. Yeah. Sure. On a similar vein, you know, are there options that involve a joint venture with 88 Energy for developing our fields or for borrowing? I think it's far too early to even begin speculating about that until there's a good deal more work. Yeah. Done on the front. I'd just like to make one point about that, is that we have had a good working relationship with them and their analysis. It's been a very mutually supportive. There's a question, slight change of pace about just about listing on a major U.S. stock exchange. We talked in the presentation about working to become Sarbanes-Oxley compliant in order that we would be able to have a listing on. Our preference is probably the Nasdaq. The question, the outstanding question really is whether it's a dual listing or just a U.S. listing. That's part of what we're working through. Either way requires the implementation of control processes and that sort of thing, and governance to become Sarbanes-Oxley compliant. There's a question about a 50-year development at 20 wells a year. I just shake my head. I'm speechless. How are you segregating acreage for initial farm-in partners? I think there's a misconception there. If we achieve the kind of manufacturing processes that Jay described as spud rigs and multiple rigs, Jay, how many HRZ wells do you reckon each rig could probably drill per year? Well, I think we could get between 15 at a minimum, David. Yeah. That's my guess. Once we get into a manufacturing process. Yeah. Maybe 20 or. Yeah. With five rigs, that's 100 wells a year. We're talking about, you know, a program of drilling out over 10-20 years, depending on how many wells we actually require. Right now, it looks like for the combination of Ahpun and Kodiak, you could require a couple of thousand wells. Obviously, as we move to better reservoir, more connectivity, the number of wells you may require as you move further west is reduced. We're thinking in terms of a 10-15 year drill out of the full field, which is consistent with many fields in this part of the world. Next one is about the process of getting approval for a hot tap into the Trans-Alaska Pipeline. Pat Galvin also hiding but could maybe unmute. How difficult is it to get the approval? What's the process? Is it just technical, or is there more to it than just showing it can be done safely? Does politics play a role? Has a tap ever been denied? If so, why? Anything else you'd like to add, Pat? Well, the process is really two parts. The first part is on the regulatory side, it's fairly straightforward. It's not that difficult. From a technical side, we have to get the current pipeline owner, the Alyeska Pipeline Service Company, to really drive the process. That's where the open access pipeline component really plays a part, that they really can't deny us access, but they will provide sort of a technical oversight to the design and the implementation of it. We have to go through their process, which can unfortunately be even more bureaucratic than going through a government agency. It's a process that has an ending. We know that we'll ultimately get it approved. The issue is just making it through that process. You know, we're confident we can get it. The timeline is going to be a matter of working with Alyeska. Thanks, Pat. Jay and Bob, maybe can you talk about the learnings from the Alkaid-2 reentry? What did we learn in terms of future well designs? Were there any surprises? I'll let Jay answer that part. I'd like to answer the first part, which is from a geologic standpoint, we absolutely proved that the shelf margin deltaic is light oil bearing, right? You know, there was always a question about that beforehand. We've got a little oil out of it when we tested it at Talitha, but you know, we had an issue with the well bore when the season ended. We've definitely shown the shelf margin deltaic is light oil. Secondly, the GOR is significantly lower than you would anticipate from what we saw at Alkaid in the Alkaid-2 test of the Alkaid zone. Which is gonna have a significant impact on our resource assessment and how we develop the field. Val, leave it like that and pass it over to Jay. What we learned, of course, is that the limited entry frack, the redesign that we placed on it with fewer perforations, lower concentrations, finer sand, definitely improved the frack. We estimate 50% of theoretical efficiency. As we've mentioned many times, we've only estimated that we would double our efficiency from 20%-40%. I feel confident that we are going to achieve 50% or better efficiency over time because we will learn as we go. Just like the industry has learned in all the other basins where the horizontal wells and the multi-stage fracs are going on. Great. Thanks. A question, why didn't the other directors participate in the recent placing? Actually, let me answer a question that hasn't been asked, but I've seen being asked around, which is why did I not participate directly in the placing? There's a very simple answer. That is, the majority of my investable funds are in a U.S. 401(k) retirement plan. The manager of that plan won't let you invest in new shares issued by a company without going through a several-month due diligence program, whereas buying shares that are already owned by someone else, they'll allow to happen straight off. I asked IPGL whether they'd allow me to participate that way, and they were happy to facilitate that. It's purely just an administrative process to allow things to move fast. On director participation, I think this is probably the last time I'm going to, you know, read out that question on a webinar in that different directors have got different financial situations at any particular time. It's not a condition of employment that they invest. There will be times when they will invest, and there'll be times when they're not in a position to do so. Jay, I think we were trying to add it up the other day. In terms of how much money you put in over the past several years, what's your cash investment in the company? Well, including what my ex-wife owns, it's, I think, almost 3 million. No shortage of investment there. Bob, I know that you put substantial money in both through your involvement in Great Bear and subsequently in fundings that we've done. It's typically been the case that the directors have participated in funding because their general preference would be to contribute to the company's success by making sure the money's going into the company rather than to the hands of someone who doesn't believe in the company. Because by definition, if you're selling the shares, you're voting against the long-term future of the company. I mean, I don't feel at any time that anyone is expressing a lack of confidence. I'll tell you that when I bought the first million shares after becoming chairman, it was purely that I just thought I wasn't prepared to wait until a funding in order to participate in the share price as it then was. Maybe greed was my sin there. Another question. Can you operate year round according to an analyst, the permafrost melts every year, and the winter operating window is getting shorter and shorter. Well, I'm not gonna name names. Look, I think at some point we all say something that, with the benefit of hindsight, we wish we could have back because we misspoke. I don't think that the analyst concerned meant the permafrost melts every year any more than I think. Actually, Jay, earlier you talked about Kodiak when you meant Ahpun. When we review the video, we'll see that you misspoke. I think people who want to attack for you know misspeaking, God bless you, but it's not where we're at. Just to reassure you, yes, of course, we can operate year round. We'll operate from gravel pads with gravel roads between pads. We will have, hopefully, highline power running from a central power generation facility that allows us to recompress the exhaust to be a zero emissions development. Which incidentally is gonna be important for funding, that there are many pools of capital that couldn't fund us if we didn't have a low environmental footprint. Of course, the air quality permit will be much easier to get if we're not intending to put out emissions long term from the development. Another question is, do you think that all the controversy on social media and bulletin boards has an impact on the attraction of Pantheon for institutional investors? What did you talk about with Oilman Jim, who reported a positive discussion with David Hobbs and Justin Hondris? Well, firstly, we're not gonna talk about specific conversations, but I can reassure you that any conversation we have with any investor or any commentator, and we are generally open to talk to anyone, whether they're a supporter or a naysayer or overtly hostile to the company, doesn't matter from our point of view. We will engage in a productive way because it's only through dialogue that you're gonna get an understanding from each other. I'm sure that controversy doesn't help, but at the same time, I'm also sure that it's not come up in any of the conversations we've had with service company vendor financing, with potential banks, with potential farm-in partners. No one's ever mentioned it. Those conversations, for obvious reasons, are always going to be similar to these webinars based on what information is already in the public domain. If it involves helping to explain something that's in the public domain because it was being misunderstood, we're happy to help understand. This webinar has mostly been about trying to make sure that the whole story is told in one go, so that it's not likely that people will trip over and think just one part is the whole story or another part is the whole story, but to see the whole thing together. Actually that leads us into another question. What's new in the webinar? Well, the answer is there's nothing particularly new in this webinar in terms of specific price sensitive information. We've simply tried to tell the whole story and to put numbers into so that it's easy for people to understand what we've previously announced in terms of likely flow rates, in terms of we've shown decline curves. We've talked about costs before. I would just add, if you read the RNS and go through these slides that we have here, it's an incredible amount of information. We've been told by others that we supply more information than any company around. Yeah. The risk, of course, is someone somewhere is gonna find that, you know, we've got a number wrong somewhere. I guarantee you we'll have some numbers wrong somewhere in our planning. By planning on the most conservative possible basis, it should mean that we've always got headroom. There's a question. Have any counterparties been given exclusivity ahead of other parties? Jay, do you wanna talk about that? Yeah. No, we have not given anyone exclusivity ahead of other parties. It's, everyone has been on a first come, first serve basis. Particularly with vendors, we've tried to make sure that we're not allowing anyone to get too far ahead of anyone else, so that everyone's got a fair crack at making a proposal. On there. That's been important, I think, for some of the people you've spoken with, Jay. Absolutely, yes. Yeah. Bob, maybe or Jay, when do you think the Alkaid reentry PVT data will be available? Bob, have you spoken to GeoMark lately? I have not. I'm hoping in the next few weeks. Yeah, it was a few weeks away. Yeah. It's, you know, not gonna reach very many people over the last few days, so, it Yeah. I'm hoping, you know, next couple of weeks. Yeah. During the last webinar, apparently I said I wasn't concerned about shorts. With subsequent share price weakness, would I like to reconsider? The answer is no. We can't control what the share price is on any particular day. There will be people who will have their own reasons for deciding to buy or sell, and the share price will be determined by something other than what we tell people it ought to be. We're trying to focus. You know, we've got a very clear idea of what our strategic objective is. We ask ourselves every day when we're faced with a decision, does taking this decision in the way we intend move us closer to or faster towards our strategic objective? If the answer is no, then we don't do it. If it's something we can't control, and if it doesn't make a difference to our ability to make forward progress, then we don't spend a lot of time worrying about it. Our share price, I think, Jay, you talked earlier about you know, industry partners are investing time and money in the certain knowledge that an offer based on our share price is not going to be acceptable, and they still choose to invest time. Vendors similarly have not mentioned our share price at any point. We're not focused particularly on what our share price is along the way. There is a question about the story over the years, vision strategy, the ability to exploit the opportunity seems to get stronger, and the confidence of the board and the executive team seems to be increasing. What's the equity market missing? I think that the equity market, it may or may not be missing anything. You'll only know with the benefit of hindsight. What we've heard most commonly is a perception that there is going to be more stock available tomorrow, and therefore there is no need to be a buyer today. Our job in terms of bringing non-equity financing forward is to challenge that belief. If we demonstrate to the equity market that we can fund a significant, you know, in a perfect case, all of the development costs without equity, then presumably the equity market would arrive at a different answer. Jay, there's a question around why don't we describe the Netherland, Sewell report as talking about potentially recoverable resources rather than recoverable resources? Are we being too promotional? I would just instantly, before you answer, I'd just say, we generally talk about recoverable contingent resources, and contingent resources are resources that have a number of contingencies, and therefore, by definition, are potentially. Jay, do you want to? Oh, yes. Well, obviously they are potentially recoverable. It's just I guess I just don't get my head around when we talk, as you said, when we talk about contingent resources, that we need to qualify them any more than they are contingent. They're contingent on lots of assumptions. That's why they're 2C and not reserves. Yeah. There's a question about will we provide NPV tables for Ahpun and Kodiak at $70 and $80 oil using the base investment case and the best investment estimate models. The market needs assistance understanding the upside potential that such calculations come up with. I would point everybody at the State of Alaska's North Slope cash flow model, which can be downloaded from their website. We've provided enough information to run it yourselves. I think we will probably at a future webinar run through what that looks like. For the time being, we've run cases for Ahpun, and we've run a very basic case for Kodiak without any assumption beyond Ahpun level of well productivity. What I'll tell you is that was the basis on which the $5-$10 per barrel target was set. That if you take just under 500 million barrels of recoverable marketable liquids in Ahpun at $70 a barrel and a 12% discount rate, you get about $2.5 billion of present value. If you take $80 a barrel and a 10% discount rate, you get around about $5 billion, hence the $5-$10 per barrel as a sort of range. Our guess is that you could apply much the same to Kodiak, but that is something we'll look at in the future, whether we can just show a mechanical run using the assumptions that we previously shared, so that then you can see how that tracks forward, along the way. There's a question around production build-up. If we're at 15,000 bpd by the start of 2028, where do we think we'll be by the start of 2030? We haven't done the detailed scheduling because obviously it matters when you move from 3 rigs to 4 rigs to 5, whether you have 2 spud rigs and a sixth directional rig and that sort of thing. What I can say is that our planning basis for the hot tap is to be looking at 200,000+ bpd of total capacity. Our objective is to be at peak production within a decade of starting the development. If we can get there economically quicker without overextending our ability to execute competently, then we will certainly not shy away from acceleration. There's a question, if Pantheon was to be listed in the U.S., would U.K. shareholders have to sell their shares? The answer is no. There are a number of U.K. vehicles through which you can hold international shares in the U.K., and certainly no U.K. shareholder would be forced to sell their shares by the company. A U.S. listing would simply replace the share that was held with a share in the U.S. It's too soon to say there won't be a U.K.-quoted stock. That's for further down the line and there may well be some kind of transitional arrangement. Let's have a look. What does offtake look like for Kodiak? Is that a pipeline to TAPS? Jay, do you wanna talk about that? Yeah. When we originally looked at Kodiak, we've estimated 80,000-120,000 bpd. This was some modeling we did a year or a year and a half ago. It would come through the same tap, which since we're gonna apply for up to 200,000 bpd, we would pipe it over to our facilities along the Dalton Highway and up the corridor to the hot tap 1.5 mi north of the Alkaid pad. That's the plan right now. I don't know why we would try and do another hot tap further south unless there was a very valid reason to do that. Yeah. I think that the other thing to think about in terms of there's not a clear blue line between Ahpun and Kodiak development. That essentially once we've got all the development approvals we need and we've got the facilities in place and we've got the ability to choose what's the next well we drill, we'll be looking at the overall portfolio of individual wells and packages of wells and identifying which investment delivers the highest incremental present value to the portfolio by choosing to drill that well next. That means that we may well be moving from east to west and adding additional pads and drilling out 40 wells on a pad before moving to the next pad. It may mean some bigger step outs that allow us to get to higher quality reservoir quicker, but with a longer road and pipeline connection to that more distant pad that we'll subsequently backfill in due course. That will be sort of a detailed portfolio management process after we've got to a point where we're cash flow positive in the development. Yeah. In fact, some of those further west wells, you might have a very, very wide road, and you just drill them along that road since we'll be drilling more conventional wells there. Yeah. There are many ways to do it. It's probably too early to say. There's a question, how should we think of the price per share in 2024-2025 given the outline plan, assuming approvals are granted? We don't have a specific share price target. What we're talking about is what we think we can deliver by way of transparent asset value. You have to overlay that with how the market will view that. Our job is to progress. You know, do the boring things right in the right order, so we get to a point at which the present value of the future cash flows becomes almost inevitable. Typically, companies will trade nearer their asset value when you've removed risk than before you've removed risk. Perception will change over time, and we're anticipating that sometime before 2028, when people see progress on financing, progress on consents, progress on costs, et cetera, that they'll be able to form a view. Jay, have we secured or how close are we to securing a dependable supply of Alaskan frac sand, rather than shipping it in from miles away? Okay. We have not secured that, but we are working on it. There are several avenues. We'll work with some of the vendors that we're close to on the North Slope. Pat's probably as good as anyone to answer that because he's been involved in some of the discussions. We think there are several avenues to sourcing sand in Alaska, Fairbanks and on the North Slope. That's one of the long lead time items. Pat, do you wanna add anything? Just to note that there's a variety of options that we're investigating, both that are, as you say, Jay, on the North Slope, or that would be further south and would have to be trucked up, both in terms of just mining existing sand or getting crushing equipment and other equipment that could generate the quality of the sand that we're looking for out of existing rock that we have available to us. Thanks. Pat, while we've got you. Now, you turned off too quickly. Do you have any preliminary views about what the cost per kilometer of pipeline to the hot tap is gonna cost? I suppose that speaks to just generally, you know, metrics for per kilometer of pipeline, because moving from one pad to another, that's gonna be a couple of miles. Do you have a sense? We don't currently have it, but in the grand scheme of the overall project development, the pipeline's not gonna be a major component of the cost, because our distances are fairly short with the Ahpun project. We're in the process of securing an engineering consultant who will be generating that initial design work. As I mentioned earlier, the hot tap itself is something that will be designed by Alyeska as part of our application process to them. A few years back, we had some sort of conceptual engineering done for what a hot tap ought to cost, and that came out at, I seem to remember $5-ish to the nearest $5. Yeah. Five-ish. I mean, yeah, something. It was fairly modest in- That would imply that the cost per kilometer is sort of million maximum, $2 million a kilometer. That's why the overall development isn't terribly sensitive to what the actual cost is, 'cause you're talking about each incremental pad is only adding 2 or 3 km of pipeline. From the initial entry point, we're talking about a couple of miles, aren't we? Correct. Yeah. How can shareholders work out how to value the incredible amount of information we've provided without us giving NPV guidance? Yes, I sympathize. I think that there is a general reluctance from a regulatory perspective to give valuation guidance specifically from the company. But as I say, if we take an industry standard model from the State of Alaska and the assumptions and we just run that through, I think that's probably a fair request that we can help them understand, you know, the value. There's a question. Do we have clear visibility over our shareholder base as to who are the long-term holders, who are the day traders, et cetera? I think the simple answer to that is we've got a pretty clear idea about where large portions of the shareholder base are. The two investors, IPGL and another investor that we just placed shares with, are both supportive long-term shareholders. Someone said, "Why didn't we describe the second one as supportive?" The answer is 'cause it was in the sentence before. The investor concerned said, "I hope no one thinks I'm not supportive." I can tell you in both cases, neither has sold a share for as long as they can remember, nor do they have any intention of doing so. Is there any preferential state financing we could access for any of the infrastructure pipelines, et cetera? Pat, maybe it's just easier if you stay there looking pretty, between questions, Pat. I wouldn't say there's a preferential state financing, but there are some options that are available that other projects have taken advantage of through state entities. The problem is that they come with significant backside strings and other limitations and you get yourself involved in the state political process, and that comes with a cost on the backside. I think what we're looking at is the private markets first, and we would fall back on these other options if we can get something that's more advantageous than what we can get in the private markets. Thanks, Pat. There's a question which I think was asked at the last webinar, and the answer is the same, which is why should you buy shares in Pantheon? The answer is you should buy shares in Pantheon if you think that they're gonna go up and you want to make sure that you've bought them before they go up. If you think they're gonna go down, you probably shouldn't buy shares in Pantheon. It is absolutely not the case that you can guarantee there will be no news between now and the end of the first quarter. We will announce news as it becomes, you know, as it becomes news. It's our obligation to report anything price sensitive that would otherwise, if not disclosed, lead to a false market in the shares, and that's part of the reason that we're providing as much information as we are, is to make sure that no one can claim that they weren't informed. We can't, you know, tell people what they should or shouldn't take a view on, and everyone's personal circumstances are different. You know, I personally think the share price is going up because I wouldn't have just put a quarter of a million dollars into it. If I thought that I could have waited until December or January to get shares cheaper, maybe I would have done. I am in a position where I know the progress we're making and when we get to a point at which we have commitments on any of the matters we've discussed as being discussions and negotiations right now, we will be announcing those as we go along. Jay, is there any other answer you want to give there or are we getting close to- Yeah, I think that's a very good answer. Yes. Obviously, you know, if we sign something that's price sensitive, we'll announce it immediately. Yeah. Mark, maybe we can hand it over to you to draw it to a close. Well, listen, thank you to you all. I mean, thank you for such a thorough Q&A as well. Also thank you to all the investors for your questions submitted this afternoon. We'll make all these questions available post today's meeting as well. Jay, I know investor feedback will be particularly important to you and to the rest of the team, and I'll shortly redirect those on the call to give you their feedback. I wonder before doing so, Jay, just one final time, if I may ask you for a few closing comments. Yes. I just wanna thank everyone for spending the time. We've been on for almost an hour and a half. A lot of information. As I've said earlier, I urge you to read the RNS that we published just a few minutes before the start of the webinar. A lot of information in there. We promise to give you regular updates, and we're doing that, and we will continue to do that. We're all pretty excited about what we have. You know, we got the Netherland Sewell report on Kodiak. We expect the Netherland Sewell report on Ahpun in 2024. The Alkaid well results, the PVT analysis. We have lots of things happening. Of course, we're working on all those long lead time items that we'll need to have FID and production in 2026. I just wanna say thank you, everyone. David did a great job. Pat and Bob, thanks for being on, spending time, help us get through the webinar. That's great. To you all, thank you once again for updating the investors this afternoon. Can I please ask investors not 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 may take a few moments to complete, but I'm sure it'll be greatly valued by the company. On behalf of the management team at Pantheon Resources plc, we'd like to thank you for attending today's presentation, and good afternoon to you all. Thank you.