Pantheon Resources Plc (PANR) Earnings Call Transcript & Summary

Good afternoon, ladies gentlemen. Welcome to the Pantheon Resources Strategy and Operations Update. [Operator Instructions] And I'd now like to hand over to CEO, J. Cheatham.

Thank you very much, and good afternoon, good evening, good morning, wherever you are. I'm J. Cheatham. I'm the CEO, David Hobbs is also on the presentation now. And -- 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 going to 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 on state lands. The yellow are the legacy fields, they are all pre-Brookian and fields. And 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 tight log and this shows all of the reservoirs that are in our acreage are 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 feet of oil column. And 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 3D seismic. And you can see the Dalton highway in the Trans-Alaska Pipeline for first, our acreage on the Eastern side. Our Ahpun field, and 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 D. We have estimated over 481 million barrels to see recoverable. That's a company estimate 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 will 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 huge sale 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 are both very, very large and huge aerial extent and large columns about between 600 and 950 feet of column in the Kodiak field. As I mentioned, the Ahpun field, a 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, 3 wells for about $20 million each, $20 million to lay a pipeline of 1.5 miles north of Alkaid to where we plan to tap into the Trans Alaska pipeline and place the pumping and metering equipment at that location and $20 million of general and administrative. And as I mentioned, additional pads would be up to 5 miles from the Dalton Highway corridor, 200 million plus the EUR from those. On the Kodiak field and the Kodiak field has been defined by 2 wells that we drilled, the Telitha A and the Theta West wells they were 10.5 miles apart. It is such a large area that we believe 3 further appraisal wells are required to reach FID. That's about an additional $50 million of investment, multiple pads required up to 10 miles from the Dalton Highway in Trans Alaska pipeline. And as I said earlier, Netherland Sewell put 963 million barrels recoverable contingent resource. And on that field, the development CapEx will be funded from the operating cash flow is 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 and the Kuparuk in the Kodiak and part of that is in Ahpun.

Thanks very much, Jay. And let's take a look at and refresh in our minds, the strategy that we laid out at the end of June. And we're starting to execute on, and 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. So this is an attempt to tie it all together and to talk through in more detail where the numbers come on for the financing requirement, how we intend to fund it and what steps we're taking. And here, I'd just like to let you know that the 2 positive steps that have happened since the last time we did a webinar, we have now got a Houston office on -- near the Galleria, and we have begun a process of transition to become Sarbanes-Oxley complaint 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. And the next news on that is likely to be the appointment of U.S. investment banking adviser and lawyers to take us through that process. So Jay talked about the Netherland Sewell assessment of Kodiak. And our company estimate previously released has been 1.78 billion barrels. And Jay also talked about 3 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 PATs, these are parts of the development planning process. And so 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. And 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. And the reason we ran through, if you remember, was that as we moved to shallow reservoirs, reservoirs that haven't been buried as deeply, they have better porosity. And as the porosity increases linearly as you move upwards in the column, the permeability increases exponentially. And so we get to a point at which in the far northwest of the resource and 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, but also you'll be able to recover a greater proportion of those. And 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. So the heart of what we're going to be presenting today is going to be around how we -- what the cash flows look like in startup of the development and then how we're hoping to be able to fund those costs. And we've said repeatedly that our strategy is to minimize the amount of equity required, and that means maximizing the non-equity funding options. As we work through, what we're going to be discussing is what's the planning basis for the development wells that we're going to drill. What does the field development plan look like and what regulatory permits are we going to need the ongoing analytical to 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. And so 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. And what you'll remember was we talked about the recovery from the Alkaid-2 well based on the frac that we had and the 5,000 foot of lateral that we expected to be able to recover around 300,000 barrels 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 line. And our contention at the time was a 500-barrel per day initial rate. And with the -- with potentially 300,000 barrels that by doubling the length of the lateral and by doubling the efficiency of the frac, which was mostly to do with keeping more of the frac 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 frac legs almost linear production between those frack places that we would be able to get a 4x uplift from the 300,000 barrels. 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 going to be surprised to the downside. Similarly, by doubling the length of the well and by doubling the reservoir area exposed in the frac, you don't quite get a 4x increase in the production. And so we have assumed that we only get a 3x increase in the production because you get pressure drops along the longer well [ bore ]. And 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, and 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 were nonetheless used as a planning basis for liquidity planning and for funding strategy basis with 1 million barrels per well at 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 frac 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 going to 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 going to be to the upside, not the downside. And then as we've scheduled in those wells, we've assumed that we start with one rig. After we've drilled the first 3 wells, we'll move that rig to the second pad, the factor pad, and we'll start fracking those initial 3 wells and there'll be a recompletion of the Alkaid-2 well as an injector. And then we'll move a second rig into begin drilling, so we'll have simultaneous operations through until the 15th month of 2 rigs before we mobilize the third rig. And we'll use that 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. So from 950 barrels per day to 470 barrels per day and that we just add wells on the schedule that I've just described, starting with 1 rig going to 2 rigs and ultimately to 3 rigs. And what we see is that we get to around 15,000 barrels a day by the start of -- or end of 2027 started 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. And 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 frac outcome than just a doubling from the 20% we estimated from the long-term test. And so that leads us to the profile on the right-hand side. Here, we've got wells that average around 1,500 barrels a day during the first year. And during the -- sorry, 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 barrels a day. These -- 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. And 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 restress. 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 barrels per day average through the first year. That then takes us to what do the cash flows look like. And 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 4 wells in 3 months, when you've got to 2 rigs operating. And 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. And what you see on that planning basis, and we provided the detailed numbers in the press release to show you how that's made up, you've got the additional cost in that first -- in that second month of production, where you've got the funding of a second set of facilities and the second pad. That's the sector pad that we talk about. And then after that, it's just drilling costs through this planning horizon. And what you see is we max out at around $220-odd million cumulative net negative cash flow. That's the basis from which it gradually comes back to full payout each well has around about a 1-year payout at $70 a barrel and less than a year at $80 a barrel. But 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 borrowing it. But 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 in order of magnitude larger for the Phecda development and nearly 2 orders of magnitude larger in the case of the Willow development going further west. And the reason that the Phecda development has a smaller capital to get to first production is because they're making use of preexisting facilities in the Kuparuk field in order to save some of that cash sink 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 slip development that looks like a big offshore development, where you've got an enormous amount of capital before you can begin your first production. So we may come back. I'm sure there'll be questions around that when we get to the Q&A session. But 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. J., can I turn it over to you?

Thank you, David. So here, we're looking at the Alkaid-2 pad. And 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 miles on the east side of the Dalton Highway north of our location. So 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 development. The state is our partner. We work with them every day through multiple agencies, and we have a great relationship with them. And of course, we have Pat Calvin 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 float. However, it is an open access pipeline so we cannot be denied access. But we are -- we are planning on 18 months and $20 million, which is way more than its cost. And 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 and of course, we'll reinject our water as well. So 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 sales 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 forecast, and we'll get the complete report from the output of that dynamic model. That will include gas and water injection well analysis. And as David has said and I have said in the past, we're currently planning on one injection well for every 3 production wells. On to you, David?

Yes. Sure. And 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. But 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 [ GMR ] can we manage 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. The -- we've talked about previously access to the Trans Alaska pipeline. And 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 Maldives and there would be consequences of that in terms of nondiscriminatory tariff, but we might have to wait until we fill the full Aframax tanker to be able to take it out of LDs and that would delay revenue and make revenue much chunkier. We might be able to combine lifting with other marketers accrued. 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 -- or would need to be a better deal than doing it ourselves. And 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. And then any improvement from that is going to be on the basis of mutually win-win deals with the third parties, and 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 cubic feet of gas, mostly being reinjected into the Prudhoe Bay reservoir. But in addition, there's around 10 trillion cubic feet 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 dead horse. And the most recent public statements from the Alaska Gas Line Development Corporation has been -- they're looking for their FID in 2025 to go ahead, and they have been talking with potential partners, who are going to 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. And also there is a benefit to us in terms of reducing the cost 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 -- not a big bar, but a bar about halfway down, which is financing for the ARPU and development. And the pillars of our intended financing are to talk to vendors, to talk to off-takers and to talk to banks and other lending institutions. And I think J. has been leading on some of the vendor financing discussions. And so maybe, J.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 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 3 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, and we partner to -- are you read the RNS that was out this morning on how that benefits both parties. Both parties can come out ahead on that. And 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. So we have -- we are undertaking those, and we expect that we will hopefully have something to report in the new year. So it's a pretty exciting time for us in that regard.

In terms of offtake financing, there are different time frames for different potential off-takers. 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. There is not cheap financing in terms of the coupon or the APR, if you like, on that financing. But it is a very cheap financing, when compared to potential dilution at lower valuations of the equity, and we'll come back to the equity, whether that's through the asset or through the corporation in a moment. But 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 contracts there as well. And so 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. And then 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 2 wells falling over and undermining the basis of the credit. We have planned that, that comes at around 6% to 8%, even potentially 9 production wells. And 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. And so -- but 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. And 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 -- as J. said, with the scale of contracts we're talking about, we're anticipating spending with this 3 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 more than $100 million during the course of the first year. And so 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 3 digits, not 2, in terms of the amount of financing we may be able to raise against the offtake. And so 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 and our timing as J. 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. J., do you want to talk any more about the scheduling here on this?

Yes. I think it's instructive. We are planning the Ahpun and full FID in late-2025. With being on production is you can build it up from [ David Grass ] in 2026. And the FID on Kodiak in 2028, the 3 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 1 rig to 2 rigs to 3 rigs and on. And as David mentioned, we would ultimately do batch drilling and the batch drilling would be -- we would have a spud rig that would drill down to surface casing, move over and drill down the service casing on the next well. And your directional drilling rig would come in behind the spud rig. So you have a spud rig, a directional drilling rig, 2 directional drilling rigs, 1 spud rig 3 and 1 et cetera, and then you come in with your frac equipment behind that. So a completely -- ultimately a batch. As David mentioned, it's Permian Basin North. And so 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. And in that context, J., 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 them starting from 0. It's actually being able to have the beaten and hit the Tundra in the -- at the very start of 2026, and that's the basis on which we're showing the production buildup during 2026.

There is a lot of work to getting sand to you dealers, horsepower, both of the fracking horsepower that we want because we want the ultimate frac units to be all electric and then the pumping horsepower just for our own internal use going into the Trans Alaska pipeline, the reinjection. So there's a lot of horsepower necessary for all of that.

Thanks. So that really takes us through, I think, pretty much to the end is just a restatement of where we -- where our strategy is. And I think with that, Mark, if I can hand it back to you, while we move into Q&A.

[Operator Instructions] 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 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, Matt. The first question, actually speak straight back to the financing. Why do you not have an equity partner as one of your main 3 pillars of financing? That's very simple in that there are, of course, 4 pillars the 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. And there's another question, which is are we worried that we haven't attracted a potential pharma 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 asset set 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 to just say, well, how we'll divest 50% to cover our capital and then 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 reenter Alkaid-1, [ Alcore, Mirag ] 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 [ Alcore and Mirag ]. I'm not even sure how they were plugged and abandoned, so we have to review that. But all things are possible. Michael and I were talking earlier this week and the 11th commandment of oil and gas people is never plug a well until you have to. So we'll keep the wellbores available until we decide we cannot use them.

So again, back in 2019, Michael Duncan talked about trucking production to 1 -- station 1. Jay, you reiterated it at various times. But we've decided to go for a hot tap. Why is that?

Well, we did truck 10,000 barrels of earlier this year and some last year. And the cost was just prohibitive. And so 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.

So it's -- basically that there is more value lost in terms of access charges than the cost of delay.

Yes, absolutely.

Yes. And without naming names, how many different entities are we talking to about vendor financing? And I think that sort of cuts into a more general topic of -- 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 extent? And I know that it's at least 6 in relation to people, who are talking about funding with us, but...

Yes, that's about the right number -- less than 10%, but growing.

Yes. So someone said, if they send you an old ARCO hat from the Dad's collection, would you wear it in one of the videos when we start drilling for good luck?

Yes, gladly. I will wear. Fond memories of my 30 years at ARCO.

Yes. And 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. The -- 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 got to be on terms that are reasonable for our investors. And it's got to be something that adds value over and above what we're capable of doing ourselves. But Jay, do you want to comment on that?

Yes. So -- and I had this discussion with one of the people that's in the data room. And I just said, if you're thinking you can come in based on our current market cap or even some uplift from that, we're not interested. And I was assured that they would -- they are looking at a project level and anything that they would do would be at a project level. And 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.

Yes. The -- and I think that's the key point. They're investing, people coming into the data room and doing deep analysis. They're investing several hundred thousand dollars of their time and effort and cost. And we just don't think it would be ethical to allow them to spend that money in the expectation that they were going to be able to trade on the basis of market caps so we have had those conversations. And 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 a recombination sample calculated GORs will give us a clearer idea.

Jay, -- and Netherland Sewell have already stated that, that will be a big part of their valuations going forward.

But on Ahpun, in fact, that someone's asked why has the original guidance on the Netherland Sewell will report on Ahpun slipped from the end of 2023 to the middle of 2024. And part of the reason for that, and 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, and we certainly didn't want to pay premium prices to have Netherland Sewell be pushing through the busiest time of the year for year-end reserve reporting for U.S. publicly listed companies. And so we were prepared to let that push back in terms of getting something in a time frame that was appropriate for our development planning without spending money unnecessarily on that. The -- there's a question about the number of injection wells. We don't think, Jay, in terms of the 1 injection well for 3, even with the lower gas oil ratio, we're not planning.

Yes. We ultimately think that there will be fewer than that required simply because that's based on a pretty low permeability and porosity regime. So -- and then, of course, as you mentioned, the gas pipeline will solve a lot of those problems going forward.

Certainly removed 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 presentation. 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, and we've showed them at a level that I remember before joining Pantheon. And I was able to scale off average porosities and permeabilities. But particularly what you've seen is in the chart we showed earlier, in fact, if I can just flip back to it for a second...

Well, and we showed that in more detail in the last webinar, too, David.

Exactly. I was going to say...

Our total was built up, in fact, with the statistical analysis.

Yes. So the averages and the depth 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? And I know from the modeling we've done on the basis of the minimum type curve of 1 million barrels starting at 1,500 barrels a day, you would get down to around a 20% rate of return post tax at around $65 for ANS. If you use our most -- our best estimate case, then the number goes down into the 40s. And if you don't need to drill as many injection wells because there's a gas offtake, then that number could even start with the 3. But 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, with stress testing at the technical level rather than planning for what's the minimum oil price. The -- Jay, we've actually -- we've got Bob with 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 test at Hickory this winter?

Well, that's a good question. They -- I think we're very focused on the their slope section. What we're hoping -- the first thing we're hoping to see is what kind of fluids they get out of it. And the -- obviously, what the kind of frac job they use to test. I'm hoping they focus on their -- the slope and the shelf margin delta, 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. And so we're waiting to -- wait and see. I think the position that they're in terms of where they're testing the well. We're but all our acreage is up dip and from where they're testing. So I'll just leave it like that.

Well, and that will be important information for Netherlands too as well...

Totally. It will certainly contribute to our Ahpun analysis. Yes. Sure. And on a similar vein, 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.

I'd just like to make one point about that is that we have had a good working relationship with them through their drilling of the Hickory well and their analysis. So it's been a very mutually supportive.

Yes, yes. And there's a question a 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 and that's part of what we're working through. But either way, requires the implementation of control processes and that sort of thing and governance to become Sarbanes-Oxley compliant. There was a question about a 50-year development or 20 wells a year. I just shrink my head. I'm speechless how you segregating acreage for initial farming 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 wells do you reckon each rig could probably drill per year?

Well, I think we could get between 15 at a minimum, David...

Yes, my and guess...

Yes. I guess hopefully getting a manufacturing process maybe 20 or...

Yes. And with 5 rigs, that's 100 wells a year. We're talking about a program of drilling out over 10 to 20 years, depending on how many wells we actually require. And right now, it looks like for the combination of a Ahpun and Kodiak, you could require a couple of thousand wells. But obviously, as we move to better reservoir more connectivity, the number of wells you may require as you move further west is reduced. So we're thinking in terms of a 10- to 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 could be done safely. Does politics play a role? Has it ever been denied? If so, why anything else you'd like to add, Pat?

Well, the process is really 2 parts. The first part is on the regulatory side, it's fairly straightforward. It's not that difficult from technical side, we have to get the current pipeline owner, the Alaska pipeline company to really drive the process. And 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. And so we have to go through their process, which can unfortunately be even more bureaucratic than going through a government agency. But 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. So we're confident we can get it. The time line is going to be a matter of working with Alaska.

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 and were there any surprises?

Can I -- I'll let Jay answer that part. I'd like to answer the first part is -- which is from a geologic standpoint, we absolutely prove that the shelf margin they'll take is light oil bearings, right? That -- there's always a question about that. Before hand we got a little oil out of it, when we tested it at [indiscernible] but we had an issue with the wellbore and when the season ended. So we've definitely shown the shelf market they'll take is light oil base is light oil. And then secondly, the GOR is significantly lower than it would -- you would anticipate from what we saw at Alkaid and the Alkaid-2 test of the Alkaid zone, which was going to have a significant impact on our resource assessment and how we develop the field. So I'd leave it like that and pass it over to Jay.

Okay. And what we learned, of course, is that the limited entry frac, the redesign that we placed on it with fewer perforations, lower concentrations, finer sand, definitely improved the frac. And we estimate 50% of theoretical efficiency. And as we've mentioned many times, we've only estimated that we would double our efficiency from 20% to 40%. I feel confident that we are going to achieve 50% or better efficiency over time because we will learn as we go. And just like the industry has learned in all the other basins, where the horizontal wells and the multi-stage fracs are going on.

Great. 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 that the majority of my investable funds are in US 401(k) retirement plan. And 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 it to happen straight off. So I asked IPGL whether they had allow me to participate that way and they were happy to facilitate that it is purely just an administrative process to allow things to move fast. But on director participation, I think this is probably the last time I'm going to 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. But 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 it's almost $3 million.

So no shortage of investment there. And Bob, I know that you put substantial money in both through your involvement in Great Bear and subsequently in fundings that we've done. And it's typically been the case. The directors have participated in funding because their general preference would be to contribute to the company's success by making sure the money is 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. The -- so 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 1 million shares after becoming Chairman, it was purely that I just thought I wasn't prepared to wait until funding in order to participate in the share price than was -- so maybe Green was my cent there. Another question. Can you operate year round, according -- what I'm not going to name names, according to an analyst, the permafrost melts every year and the winter operating window is getting shorter and shorter. 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 analysts concern 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 misspeaking -- God bless you, but it's not where we're at. But 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, high line power running from a central power generation facility that allows us to recompress the exhaust to be a 0 emissions development, which incidentally is going to 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. And 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. And another question is, do you think that all the controversy on social media and bulletin board has an impact on the attraction of Pantheon for institutional investors, what did you talk about with oil and Jim, who reported a positive discussion with David Hobbs and Justin Hondris? Well, firstly, we're not going to talk about specific conversation, 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 are a supporter or nae sayer or over the hostile of 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 going to 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 farming partners. No one's ever mentioned it. But those conversations for obvious reasons, are always going to be similar to these webinars based on what information is already in the public domain. And if it involves helping to explain something that's in the public domain because it was being misunderstood. We're happy to help understand. And 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 trying 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.

And 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. And we've been told by others that we supply more information than any company around.

And the risk, of course, is someone somewhere is going to find that we've got a number wrong somewhere. I guarantee you we'll have some numbers wrong somewhere in our planning. But by planning on the most conservative possible basis, it should mean that we've always got headroom. There's a question, have any counterparties being given exclusivity ahead of other parties. Jay, do you want to talk about that?

Yes. No, we have not given any one exclusivity ahead of other parties. Everyone has been on a first come, first serve basis...

And 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. And that's been important, I think, for some of the people you've spoken with Jay.

Absolutely, yes.

Yes. Bob, maybe or Jay, when do you think the Alkaid reentry PVT data will be available?

Bob, have you spoken to [ Mark ] lately?

I have not. So obviously in the next few weeks.

Yes. The last quarter, it was -- yes, it was a few weeks away.

Yes. It's not going to reach very many people over the last few days. So I'm hoping the next couple of weeks.

Yes. So during the last webinar, apparently, I said I wasn't concerned about shorter 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. And so we're trying to focus -- we've got a very clear idea of what our strategic objective is. We ask ourselves every day, when we're faced with the decision, does taking this decision in the way we intend, move us closer to faster towards our strategic objective. And if the answer is no, then we don't do it. And 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. The -- our share price, I think, Jay, you talked earlier about 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. And so we're not focused particularly on what our share price is along the way. But 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. So 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. But 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. And our job in terms of bringing nonequity financing forward is to challenge that belief. And if we demonstrate to the equity market that we can fund a significant or in a perfect case, all of the development cost 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 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. But Jay, do you want to...

Yes. Well, obviously, they are potentially recoverable. It's -- 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 a lot of assumptions. That's why they're 2C and not reserves.

Yes. So there's a question about will we provide NPV tables for Ahpun Kodiak at $70 and $80 oil using base investment case and the best estimate models, the market needs assistance, understanding the upside potential that such calculations come up with? And 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 add 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, that was the basis on which the $5 to $10 per barrel target was set. But if you take just under 500 million barrels of recoverable marketable liquids, in Ahpun $70 a barrel and a 10% discount rate -- sorry, $70 barrel and 12% discount rate, you get about $2.5 billion of present value. And if you take $80 a barrel and a 10% discount rate, you get around about $5 billion, hence the $5 to $10 per barrel as a slaughter range, our guess is that you could apply much the same to Kodiak. But that is something we'll look at in the future is whether we can just show a mechanical run using the assumptions that we previously shared, and so that then you can see how that tracks forward along the way. There's a question around production buildup. If we're at 15,000 barrels a day 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 6 directional rig and that sort of thing. But what I can say is that our planning basis for the hot tap is to be looking at 200-plus thousand barrels a day of total capacity. And our objective is to be at peak production within a decade of starting the development. And 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. vehicle 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. But it's too soon to say that it 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. The -- let's have a look. What does offtake look like for Kodiak? Is that a pipeline to tax? Jay, do you want to talk about that?

Yes. When we originally looked at Kodiak, we've estimated 80,000 to 120,000 barrels a day. This was some modeling we did a year or 1.5 years ago. It would come through the same tap, since we're going to apply for up to 200,000 barrels a day. We would pipe it over to our facilities along the Dalton Highway and up the corridor to the hot tap 1.5 miles 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.

And 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 will subsequently backfill in due course, but 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.

Yes. In fact, some of those further west wells, you might have a very, very wide road you just drill them along that road, since we'll be drilling more conventional wells there. Yes. There are many ways to do it.

Yes. So it's probably too early to say. There's a question, how should we think of the price per share in 2024, '25, 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. But our job is to progress, 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. And typically, companies will trade nearer their asset value when you remove risk then before you remove risk. So perception will change over time, and we're anticipating that sometime before 2028, when people see progress on financing progress on condensed 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 supplier 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, but we think there are several avenues to sourcing sand in Alaska, Fairbanks and on the North Slope. But -- and that's one of the long lead time items. Pat, do you want to 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, you turned off too quickly. Do you have any preliminary views about what the cost per kilometer of pipeline to the hot tap is going to cost? And I suppose that speaks to just generally metrics for per kilometer pipeline because moving from one pad to another, that's going to 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 is not going to 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. And as I mentioned earlier, the hot tap itself is something that will be designed by Alaska as part of our application process to them.

And a few years back, we had some sort of conceptual engineering done for water hot tap or to cost, and that came out at seem to remember 5-ish to the nearest 5...

Yeah. Something. There's fairly modest.

That would imply that cost per kilometer is sort of 1 million maximum, $2 million a kilometer, and that's why the overall development isn't terribly sensitive to what the actual cost is because you're talking about each incremental pad is only adding 2 or 3 kilometers of pipeline. And from the initial entry point, we're talking about a couple of miles away.

Correct.

How can shareholders work out how to value the incredible amount of information we had 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 -- we run that through, I think that's probably a fair request that can we help them understand 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 2 investors, IPGL and other investor that we just placed shares, who are both supportive long-term shareholders. Someone said, why didn't we describe the second one is supportive. The answer is because it was in the sentence before and the investor concern 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 I can remember nor do they have any intention of doing so. The -- 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.

There -- 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 the cost on the backside. So 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. The -- 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 going to go up and you want to make sure that you've bought them before they go up. And if you think they're going to 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 news. It's our obligation to report anything price sensitive that would otherwise, if not disclose, 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. But we can't tell people what they should or shouldn't take a view on and everyone's personal circumstances are different. The -- so I personally think the share price is going up because I wouldn't have just put $0.25 million into it. And if I thought that I could have waited until December or January to get shares cheaper. Maybe I would have done, but 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 do we -- are we getting close to...

Yes, I think that's a very good answer, yes. Obviously, if there -- if we sign something, that's price sensitive, we'll announce it immediately.

So Mark, maybe we can hand it over to you to direct to closing.

Thank you to you all. I mean, thank you for such a thorough Q&A as well. But also thank you to all the investors for your questions submitted this afternoon, and 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 wanted before doing so, Jay, just one final time, if I may ask you for a few closing comments.

Yes. So I just want to thank everyone for spending the time. We've been on for almost 1.5 hours. 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 promised to give you regular updates, and we're doing that. We will continue to do that. And we're all pretty excited about what we have. We got the Netherland Sewell report on Kodiak. We expect the Netherland Sewell report on Ahpun in 2024, the 880 well results the PVT analysis. So we have lots of things that are happening. And of course, we're working on all those long lead time items that we'll need to have FID and production in 2026. So I just want to 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. Could I please ask the investors not to close this session as we're now automatically redirected for the opportunity to provide your feedback. [Operator Instructions] On behalf of the management team of Pantheon Resources, PLC, I would like to thank you for attending today's presentation, and good afternoon to you all.

Thank you.