Pantheon Resources Plc (PANR) Earnings Call Transcript & Summary

Good afternoon, ladies and gentlemen, and welcome to the Pantheon Resources plc post AGM investor presentation. [Operator Instructions] The company may not be in a position to answer every question received in today's meeting. However, the company can review your questions and we'll publish those responses whereas appropriate to do so. I'd now like to hand over to Executive Chairman, David Hobbs. Good afternoon.

Thanks very much, indeed, Mark, and thank you, everyone, for joining us here on the webinar today. We've just completed the formal business in which -- of the AGM in which all the resolutions were approved. And we also, a few minutes ago, released an RNS confirming that those resolutions have been approved and sharing with you some information that we'll be presenting in the webinar. So I would invite you to review that at your leisure afterwards, and we'll be posting the presentation to our website. In fact, may have already done so. Someone's nodding at me, so it means it has already been put on our website. Joining me today in person, Justin Hondris and virtually, Jay Cheatham and Bob Rosenthal. And we'll be running through a number of things to give you an update on where we're at in terms of moving forward to achieving our stated strategic goal of achieving a recognition of $5 to $10 per barrel of recoverable oil. I would invite you please to review the disclaimer. Again, do feel able to read it in the posted version in due course. And what I can see is that when Bob was practicing how to use arrows there, we get -- they remained on screen. This is obviously just a reminder of what we've got and what we're going to be talking about. And to the west, you can see the thin outline of the new acreage that we acquired in December, which is the up-dip extension of Kodiak. And to the east, you can see the blue line, which again is used to the extension of Ahpun, and we'll be talking in more depth about that. But I want to use this as the backdrop to give you a quick review of what we achieved in the last, well, effectively 18 months. So the year that we've reported and just had the AGM for and the subsequent events. And of course, the biggest event in that period was the long-term test of the Alkaid-2 well. And what we have come to realize, as we've done the analysis and subsequent work is that, that will turn out to be a typical moment for the company in the sense that it provided the data that satisfied us that we have economically developable resources that we should be moving forward into development. And that was the reason for the pivot of the strategy that we announced in the middle of last year, just before our financial year-end that we were going to be moving forward with all speed towards bringing our resources online that we would cost what it would take to get there and we would develop a funding strategy that sought to bring us into production and then to financial self-sufficiency at minimum dilution to shareholders. And the commitment to that, I've said it before, I'll say it again. There are 2 ways I personally could have played this. I could have waited until we were trying to issue a lot of equity and bought in whatever price that would be having not sought to protect shareholders. Or I could buy shares and make sure that I was aligned with you effectively like the Greeks on the shores of Troy burn the boats, it will stiffen this in you somewhat and make sure that when we talk the talk, we're also rather incentivized to walk the walk. And that's absolutely what we're intending to do, and we will in due course be sharing news with you about that. Subsequent to the results of that well, where we don't need to retrade history. Needless to say, it was not viewed favorably by the market at the time. A lot has gone on since then in terms of retooling company and rebuilding the governance that would allow us to have the underpinnings in order to achieve the financing that we require. Today, we're in a lot better shape, and that's in part because of our subsequent recompletion of the Alkaid-2 well to test what are the top sets. So you've heard lots of different words to describe the different formations. If we're going to leave you with one message today, it is there are 2 large fields. One is called Ahpun, and it's got some formations in it. And the other one is called Kodiak, and it's got some formations in it. And Bob and his technical team are much better at understanding and describing and explaining those technical things, then there is any chance of anyone around this table or anyone else in this room, being able to better understand. There are multiple formations laid down in multiple events. But at the end of the day, what we've got is a set of what are called top sets. You'll -- Bob will talk a little bit more than that about that, which is the predominant resource in the Ahpun field. And you've got a basin floor fan, which is the predominant resource in the Kodiak field. But at the end of the day, we're developing these as 2 fields that will be engaging with the State of Alaska, are engaging with the State of Alaska about 2 areas, 1 called Ahpun, 1 called Kodiak. All the other names that you've heard, well names, unit names, formation names, whatever, we will try to avoid confusing you with lots of different things to try and reconstruct some kind of mental model because at the end of the day, what you need to know is that Netherlands have evaluated Kodiak prior to the new acreage, and we are hoping for, by the end of the first quarter, an updated report that incorporates that new acreage. But their evaluation was just shy of 1 billion barrels of recoverable market of the liquids. And they are working on a similar report. So Ahpun, the company's estimate, you'll recall for that set of formations is 481 million an orderly specific number, the 481 million barrels of recoverable liquids. We will hope to have an updated report on that by the middle of the year, which will be based on the full development plan that we've been working with SLB and then with Netherland, Sewell. So that's -- those are the key things to remember. But the critical thing for us was that subsequent recompletion of the Alkaid well, which allowed us to test the formation that is the predominant resource within Ahpun. And what we found, and we'll share with you in a bit has led to our ability to now reforecast what the development looks like. And Jay will be sharing that with you in shortly when we get that far. So let's just move into what really matters. I'd say the review of the year, you can read the annual report and it would be more informative than me trying to renarrate it for you. We recompleted the Alkaid-2 while I mentioned we acquired the new acreage, and that now genuinely completes our acreage acquisition. We have always thought that the updip most westerly portions of Kodiak would be where the best reservoir was, you can understand why, for obvious reasons, we couldn't go and apply for the furthest West [indiscernible] between that we didn't go for. So we had to play a sophisticated game over the course of the last few years of gradually expanding in order to avoid a situation in which people were competing with us. And from our point of view, we've managed to complete that before the seismic that it was all founded upon becomes public. Next year will be the first release of the proprietary 3D seismic, which would be the point at which we would no longer have that competitive advantage. And that's the reason that we moved as we did in order to tie up the entirety of the resource. Similarly, as Bob is going to talk to you as the Eastern extension of Ahpun also has better reservoir qualities by our analysis, and he'll explain more about that. We have strengthened the Board of Directors, and I'll talk through that in more depth. And also look at some of the key elements of governance in order to make sure that we are ticking the right boxes that we're not, in any way, excluding those who might invest in the company on the basis of what may appear arbitrary requirements that they would have. We announced during the second half of last year that we were examining the benefits of the U.S. listing. We completed that work. We have now a base plan, which is that we will be listing on one of the major U.S. exchanges, either the NYSE or the NASDAQ, most likely the NASDAQ because that's from a regulatory perspective, the easiest to do. We intend in an interim period to retain a U.K. listing likely not to be an aimless thing but a whole main board listing and that's in order not to disadvantage U.K. shareholders who are holding shares in tax-efficient wrappers. We don't want to force you to take your shares out of those wrappers. The -- so there will be a period. But in the long run, we will probably be solely listed on a U.S. exchange, and we have I'll come back to talk a little bit more about that. And then, finally, we're going to share with you that to Jay. We're going to share with you our progress towards the planning funding and permitting of the Ahpun development. So with that, let me hand it over to Jay just to talk through some of the specifics and the new data gathered from the Alkaid-2 recompletion. Jay, over to you.

Yes. Well, thanks, David, and hello to everyone, whether it's in the afternoon in the U.K., in the morning in the U.S. or in the evening in Asia. We did, as David said, we recompleted the Alkaid-2 well in the vertical portion in that upper topset. We previously called out the shelf margin deltaic. And this is the market update that we promised everyone after we had done our pressure bomb analysis that we put in after the frac and the test and the work done by GeoMark on the recombination. There are 2 key takeaways. The recompletion we originally said that we have 30 to 100 barrels per day of oil. But when we get the GeoMark data and add in the C5 plus, it's 20 to 40 barrels a day higher. So our actual marketable liquids were between 50 and 140 barrels per day. More importantly, though, our top set horizon's permeability, and permeability is strictly a measure of the ability of reservoir fluids to move through the rock. It's at least 2 orders of magnitude, which means it's more than 100x better than our Alkaid zone of interest. And permeability is directly related to production rates. And we also had a lot of technical data our pressure volume temperature data PBT. It's 35-degree API oil. That's very important because it's not nice light sweet oil. And the gas is even richer than the gas that we found in the lower zone. 162 barrels per mmcf of C5 plus versus 98. We'd also promised that the evaluation of our revised frac, and we see that we were about 50% of frac efficiency versus about 20% in the Alkaid zone of interest. We think we can probably drive that even higher. Our initial reservoir pressure, just under 3,500 psig and a bubble point at 3,500. So we're right at the bubble point, and that's the pressure where the liquid start coming out of the gas solution. And the bonus result, as we like to call it, is that we had negative skin. Now if you have a positive skin, it means that you're restricting the flow into the wellbore. We had significant negative skin. So it's a very, very much improved permeability in the wellbore. So as we said, we -- this well is in the extreme northeast portion of these top sets. And Bob is going to talk and show you about that. And I'm going to turn it over to Bob next or to talk about the new acreage.

Thanks, Jay. So Hello, everyone. I hope you can hear me. So what you're looking at here is a AVO display going through our -- the pipeline state well through one of the targeted locations called Megrez. This is a permitted location, that's west of the haul road. And into our new acreage of this Eastern extension of Ahpun. And I'm going to focus on just the topset here. So here, we have -- that's the Ahpun topset anomaly that was called the SMD in the past. And we've talked about this in great detail in the past. The depth here is at about 7,200 feet. And the Dmax is about -- and we've talked about which Dmaxs in the past, which is maximum depth of burial, which is the -- there's been about 3,000 feet of uplift over here. When we go over to Ahpun East into the topset, and you can see the white circle is showing you the, where we see these reservoirs present and probably hydrocarbon bearing. We are at a Dmax of 8,600 feet and about a drilling depth of about 6,000 feet of subsurface. Now when we're doing this, when we look at this, and we've looked at all the well data, and wells that we've drilled and other people have drilled in the area. The porosities that we expect in this portion of the reservoir is between 15% and 25% porosity and 5 to 20 millidarcies. This is an excellent, excellent reservoir. As Jay said, one of the things that was highlighted here was we've tested the topset play at Alkaid-2. So we've actually tested it Alkaid-2 light oil. This was at the very, very, very feather edge of the Ahpun topset play. As a matter of fact, when we originally drilled the well, we were predicting very, very thin reservoir there, and that's what we saw. But we were able to test it and we got a really good result. So what's the takeaway across the board for the Ahpun new acreage that we picked up to the East. One, we have excellent porosities and permeabilities. We know this is a large structural stratigraphic trap. It is the structural component gives us an excellent focus for migration of oil. We're sitting on peak oil generation for the source rock. The topsets display here on this acreage, we have multiple stacked targets. Not just in space, but on top of each other in this play in this area. We can develop this from the Dalton highway. It's known light oil. Alkaid-2 had a -- we had a flow test and we have the results from GeoMark. We have not changed our resource estimate. It's still about 18 -- 1.8 billion barrels of -- sorry, liquid hydrocarbons in place. So that's our total resource there. We have multiple additional targets in the slope and Basin Floor Fans and they are under evaluation for their resources as well. So before I turn it over to David, again, I just want to point out that on the Kodiak. So here's the new acreage that we picked up for the Kodiak anomaly. At this time, we're now showing you the total extent of the field that we have at Kodiak. Everything in this acreage to the East -- sorry, to the West of Theta West is updip and we're expecting significantly better reservoir than what we've seen at Theta West, and that's being evaluated right now with Netherlands, Sewell. With that, I'll turn it over to David.

I don't know if Mark had just muted me. I wanted to ask you to reflect back to you. The work that we've been doing over the last month and the key part of the update is, therefore, as it relates to the Eastern acreage. It's not volumetric. It is in terms of our assessment of the quality of the reservoir that we would anticipate in that -- in those topsets in the Eastern extension of our project. Is that right?

That is absolutely correct.

And the reason that that's important is clearly in terms of likely recovery factor and likely flow rates of successful wells into those topsets. That is taking it an order of magnitude or to even above what we found from the topset test in the Alkaid-2 well, where we moved -- if you remember in the Alkaid zone of interest, we were talking about nanodarcies. So that's less than millidarcies, less than microdarcies to a point where we're talking about 1/10 of a millidarcy in the topsets in the Alkaid-2. And here, we're talking about another 1, maybe 2 orders of magnitude higher still in terms of that Eastern exemption.

That's actually correct.

All right. And David, did you know -- and we'll show this later, that relates to the new type curves that we have in our development plan. And I guess that's where you're headed. [indiscernible] 4,000 barrels a day IP30 and 2 million barrels of recoverable.

Yes. But that's on the basis of what we saw in the Alkaid-2 topset test. It doesn't even get close to assessing what you might see as the results from in the Eastern extension. So our new planning basis is not yet invoking anything from the Eastern extensions or the updip Western in terms of type curve. We're simply basing it on what we've seen in the Alkaid-2 well that we're able to analyze it. So thank you, Bob.

That's absolutely correct.

I mean of course, SLB is incorporating that into their new modeling.

Yes, yes, yes. So I said to you just earlier, we want you to come away recognizing there are 3 areas that matter here. We've got the entirety of the Kodiak field, which is all a Lower Basin Floor Fan. It's all 1 continuous accumulation. It will be developed as a single unit area. So right now, you'll recall in the past, we've had the Alkaid unit, the Talitha unit, and we've had non-unitized leases. We will be seeking in due course to incorporate into the Kodiak unit, and we'll get rid of the confusing terminology about is Talitha a well? Is it a unit? Is Alkaid a well, a unit, a formation, et cetera? So we want to simplify so it's easy to understand. So you've got a tank, which is Kodiak. And we will be seeking to unitize that into a single development. In addition to that, we've got the current definition of Ahpun, the majority of which is, in terms of the resources, is here in the -- and you can see the red along the bottom. And that is the main body of the oil that we tested in the topset up by the Alkaid. So it Horseshoes round and it gets better as we move further South. So what we're telling you is having evaluated the well performance in these topsets, we will be focusing our initial development into the main body of the topsets in Ahpun, which is why we're envisaging higher initial flow rates and the revised production projections and cash flow projections that we're going to be showing you at the end of this, and then, finally, the Eastern addition, that next cycle of topsets across the majority of which sits within our acreage accessible from West of the Dalton Highway. So all part of the same development. And the initial well, you can see that green dot Megrez, that's where we would probably drill the initial well that would allow us to demonstrate the producibility of those topsets. So this area and the other area we're putting together will be unitized into the Ahpun development. And then as I said, the Kodiak will be the other area. And we will seek to have all our licenses unitized into those developments, and we'll be moving forward with approvals on the initially Ahpun with a view to a final investment decision end of 2025 and then Kodiak following some further appraisal with an FID in late 2028. Okay. I talked about new Board members. We've announced both Allegra and Linda in previous stock exchange announcements. So you're familiar with that background. What I can tell you is that now that we have 3 independent nonexecutive directors. Obviously, Jeremy Breast came on to the Board as a designee of Farallon and the Great Bear shareholders that's now dissolved. So that effectively, Jeremy is in his own right as a fully functioning independent member of the Board. Allegra and Linda means that we have more oversight than we've had in the past, where we've only ever had a Chairman and 1 other Non-Executive Director over the last several years. And that allows us to hopefully build confidence among investors that every decision is being taken with a view to achieving and driving our long-term fresh. We have -- as a result of having a fuller complement on the Board, the Board committees which historically were effectively almost saying people on the Board, different people sharing those committees now have the opportunity to begin to take on personalities of their own and to focus in hard on the issues that matter to them. Linda comes from a long and storied background as CFO of both public and large private companies and has taken over as the Chair of the Finance Audit and Risk Committee. And she will be really focused on the program that drives us towards having the kind of controls that we need in order to be Sarbanes-Oxley compliant and to be able to operate seamlessly and efficiently as a U.S.-listed company. It will also should be able to bring expertise in how to close the books quicker. American companies typically close their books quicker than U.K. companies. There are a number of steps that, that requires. Sometimes it's just a shift in terms of how one thinks about it, how much, work is done before you get to the year-end in order to be further along. And so she'll be working with Justin on making sure that we have a process that will shorten the time frame this year we were earlier than last year. And next year will be earlier than this year along the way. We have asked Tony Larkin to join the team to lead the U.S. listing transition Tony is sitting quietly at the back of the room, and I'm sure we'll be happy to talk to anyone afterwards, but Tony will be project managing and leading that whole process because it's multidisciplinary, it requires all of us to have our butts kicked to make sure that we're staying on track on what is now a 14 and a quarter month process because we're aiming by the end of the first quarter of 2025 to be in a position where we can be listing on a U.S. exchange. Jeremy Brest has taken on chairmanship of the Remuneration Committee. You saw some early results from that, one of which was the termination of a historical incentive plan, which was designed for a different time and a different company. We are in the process of replacing the old remuneration plans with a single omnibus plan that is consistent with market practice. And as we move to a U.S. listed company, we'll be moving to be compliant and in line with market practice there. The other thing, just as a technical point, is the move to a U.S. listing won't crystallize anything in terms of the termination of 1 plan and start a new. It will be a [Technical Difficulty] rollover along the way. We will be, in due course, announcing grants for this year. And what you'll see is that the main focus of the Remuneration Committee has been in making sure that rewards are aligned to shareholders' requirements so that the vesting conditions for options will be related to value-creating events and the value of awards will be related to share price performance so that the team, both the Board and management are aligned with shareholders that it shouldn't be possible for rewards to management that aren't consistent with [indiscernible] shareholders. I will continue to share the Nominations Committee and our -- now that we have a Board of 7 people, that is we don't need to expand the Board anymore. We don't intend to. Our focus will be on as we transition to a U.S. listed company, the general makeup of the Board in terms of how many members of the executive are members of the Board will change and we may need to reconfigure the Board in the listing process. But the most important job from my point of view, is succession planning for all key roles. There should be nobody involved in the company who is not extendable because we will have a good plan for everybody because that is a key risk factor to the success of the company is making sure that we've got not only a plan A for every role with a plan B. And in due course, the need from the company will change over time as we move from an exploration and appraisal company to a development company and then to a production company, the skill sets required and the numbers of people in different areas will change. So having a proper succession plan and a proper resourcing plan is critical for that. And one of the things that is mentioned just at the top of this slide, Josh McIntyre, who has historically been our controller in Alaska is going to be stepping up to become group financial controller which will free Justin to be much more focused on the funding and other parts of the Finance Director role. So we'll be strengthening that finance organization and building the controls around it. The -- Allegra has taken on the Conflicts Committee, and that is really no different than it has always been, which is to ensure that we maintain the highest ethical standards and ensure there are no unknown conflicts of interest and where there are potential conflicts of interest that we deal with them in an entirely transparent fashion. An example of that, that I'll share where if not addressed transparently, you could have a potential proceed conflict. When we selected the location for our Eastern office, we looked at a number of different locations. In the end, expanding the office of Proton Green, which is another company that I'm Chairman of, provided the lowest cost solution because we didn't need to have a whole bunch of common areas of meeting rooms or sorry, of nonoffice areas, those meeting rooms and kitchens and that sort of thing. By being double up in share, we were able to save money. But in order to ensure that we handled it right, we went through all the governance process of a related party transaction in order to confirm it was in the best interest, not only at Pantheon, but obviously, I had do the same thing from the other side for Proton Green so that it was handled transparently. In terms of the forward incentive programs, the remuneration committee is really focused on looking at the overall package because we're going to have to recruit a number of people as we build the organization to be running multiple rigs in parallel to be running simultaneous development and production operations. And so we needed to make sure we had a plan that allowed us to recruit and retain good people for the long term. And so we will have a combination of cash and restricted stock units for management that vest over periods of time so people have always got unvesting rewards in the future that retain them and a continuing rolling process. And we will ensure that the plan limits are consistent with U.K. market practice today and then when listed in the U.S. with U.S. listed peers, that's a commitment that we are giving you on that.

David, when you say there's relatively [indiscernible]. What does that mean?

So a part of -- typical for U.S. companies with restricted stock units, you have units that vest a 1/3, 1/3, 1/3 over a 3-year period. So that in any year, people have always got at least another 2 years work before the rewards have fully vested. And typically, it's smaller numbers of stock units than the number of options that you have granted if you are granting options. But what it means is that they their owners and growing owners over time from there on.

Restrictions [indiscernible] staff, restrictions of sales?

So once they've vested and in your hands there, you're not restricted in any way other than your belief that the share price is going to go up in there, so you hold on for the long term. I know from my own experience, I've previously been involved in teams like that, and the suckers were the ones we sold early in terms of the reward. The -- I mentioned the U.S. listing strategy. So our immediate priority is bringing on board and retaining the investment bank that's going to be taking us through the process. We have already engaged the accounting advisers who are going to be implementing the systems and documenting them to achieve Sarbanes-Oxley compliant. And obviously, the legal firm who will be working with the investment bank and Tony, as I mentioned, we'll be working that program and spending a lot more time in the U.S. during that overall program. With that, let me hand it back to Jay to talk through the Ahpun development planning and where we're at on key items.

Thank you, David. And so here, we're going to talk about how we plan to become West Texas North. And so one of the biggest items that we have in our well is the cost of the frac sand. We paid about $0.65 a pound for the sand that we used in the Alkaid-2 well. I won't go over all the cost differentials we had. We brought it out of Canada and that was a very, very expensive process. We're now -- our operations team has now looked at that supply chain. That supply chain includes mining, sorting, transport and storage. And for each well, we're going to use about 25 million pounds, and our target is $0.20 a pound. So significant savings over our previous cost. And -- but it's still a very, very big number. That's $5 million per well. And when you think that you may want to have storage for 10 or more wells, that requires a lot of trucks, a very large storage area, a significant sorting and mining to do that in the time period you want to do that. But our operations team is well underway and have talked to all of lots of various vendors on the North Slope and other, and we are confident that we will hit that $0.20 a pound. In Tubulars, we've been talking with current pipe vendors and using standard grades. We see no issues there. However, under full development, we may go to custom pipe if that proves to be a less expensive way to go. Rotating equipment. Sometimes these are very long lead-type items. But with the increased activity on the North Slope. You see increased pressure pumping capability on the North Slope and with the vendors of course, we're talking to many of those vendors and the rig companies about long-term contracts. We don't see any current bottlenecks for gas compression, power gen, gas turbines, et cetera. So we are confident that we are on our way to making this West Texas North and more like a manufacturing process. Now we talked a lot earlier about the recompletion of the Alkaid-2 well and what that meant for us in our development, and based on those porosities and permeabilities that we did, we saw in that well and the data we have from previous wells, including the old pipeline state well, we have new type curves. And as we talked earlier, these type curves are based on that reservoir data and generate 4,000 barrel a day IP30s and about 2 million barrels a day of EURs. And this is our development plan starting in Q1 of 2026 with a single well. We add our second rig in Q3, and we hit about 10,000 barrels a day at that time. In Q1 of '27, we're up to 20,000 barrels per day. We had a third rig on a third pad. We get to 25,000 barrels a day. We are easily self-sufficient when we get to those kinds of numbers. In the first year, we drilled 10 wells. We've estimated that's 7 producing wells and 3 injection wells. And this is what we are showing are the vendors that we are talking to about financing. Also, this will be important for reserve-backed lending for nonequity financing. And I'm going to turn it over to David to talk through that in more detail.

Thank you, Jay. So what you'll see, and if you've got a good enough memory, you'll recall when we presented numbers on the basis of what we've seen in the original Alkaid-2 long-term test, we were showing a ramp-up to around about 20,000 barrels a day by the end of 2027. So our approach to planning has been never to assume anything better than we have already encountered. And that's what the big change here is that we've now encountered this quality reservoir. We've got the pressure build up data that allows us to do the type curve matching and to be confident in the ability to develop wells, which, on average, don't forget there'll be some wells that will perform better, some wells that will perform worse. We're talking about, on average, build this up to a point at which by the end of 2027, we can expect to be hitting 40,000 barrels per day. Now what does that mean in terms of the financing requirements. We originally, if you remember this. Again, this is a revised version of the chart we showed you back in November. And with the new well type curve. But what it's telling you is that almost as soon as we get into production, the cumulative net cash outflow flattens off to 0 further cumulative cash outflow. So the original chart showed that number going to about $300 million negative cumulative cash flow. And with this type curve, we think that the total requirement is going to be somewhere just over $150 million using that conservative planning assumption of $20 million per well for the first 3 wells, $20 million for the production facilities, $20 million for the pipeline tie-in and $20 million for general overheads and engineering cost to get to that point. That was the $120 million up to the point of first production. And as soon as you see first production, that chart begins to flatten off. So the scale of what we're trying to raise is not as large as we originally anticipated because we've now been able to demonstrate in a physical test an improved reservoir quality and liquids quality. And so just focusing on what do we think the borrowing base that we can support from this would be -- once we get up to the end of 2026. At that point, we would anticipate having 7 production wells. Is that enough or too few to be able to be in borrowing on a reserve base lending? It really depends what percentage of the remaining present value of those wells you're looking to borrow. If you're looking to borrow a high proportion, 70%, 80% of the NPV, you require a larger number of wells because your risk of any individual well impacting the borrowing base is higher. If you're looking to borrow 50% or 60% of that number, the number of wells required to be smaller. The key point that I want to get across with this chart is that by the end of 2027, we'll be at a point where 60% of some '24, '25 producing wells is going to be around $350 million. The -- that's what I'm telling you is that our liquidity and ability to dramatically expand from 2, 3 rigs to 4, 5 rigs and to accelerate the development as we move into the point at which we're also starting to think about the Kodiak development, we're not going to have a shortage of liquidity. Now why is that important? Well, there are some people who have been trying to do the maths in their head and saying, "Well, if a rig can drill 10 wells per year. And 5 rigs is going to produce -- is going to deliver you 50 wells per year, and if you've got to drill 2,000 wells, that's 40 years' worth of drilling." That is very simple and very elegant and very incorrect math. Because 2 things. The first is that the initial number of wells per year, it may be that it's a month per well as we start up. But if we see the kind of efficiency gains that we'd expect to see in West Texas, then we'll be drilling considerably more wells per rig per year. Second, as you move into the manufacturing process of drilling rather than the running business of drilling, what you see is you use a specialist rig for studying the wells to get to that surface casing and then you follow up with the directional rig with a customized program. And so infact the number of rigs, in terms of the number of drilling rigs you've got per well or a number of wells per drilling rig, it starts to move geometrically because you are batch conducting different parts of the operation. And that's how the real efficiencies are being driven in the Permian Basin is from moving from that one well as time sequential process to best-in-class equipment for each of the different tasks and batching it like a manufacturing process moving forward. So we're anticipating a situation in which, yes, there's going to be drilling activity on this for the next 20 years in just the same way there was drilling activity on [indiscernible] for 20 years and there's drilling activity on the part for 20 years. But it's not that this is going to take forever to drill out the field. Our initial estimate is that we're aiming for between 200,000 and 250,000 barrels a day of capacity on the current plan by about 2033. So within essentially 7 years of start-up. And then the decision will be on whether 1 accelerates by expanding capacity or continues just keeping the system fall that, that will be an economic optimization at the time. You've got enormous optionality in terms of how many wells you drill in what timeframe, depending on what the macro environment looks like. So what it's telling you is that as we move through first production, we've got a number of steps that are taking us to the point in which we've got a final investment decision on Ahpun and we start the development and that takes us within about a 12-month period of the start of development to be positive net operating cash flow. And indeed, on this type curve, self-sufficiency happening sooner than the end of 2027, which is when we were originally forecasting it. And that is going to allow us to move more quickly towards full production capacity down the line between 200,000 and 250,000 barrels per day. So what are we going to be doing in the short term? What are the things to look out for? There will be 2 main reports, 1 on the updated Kodiak, which will incorporate now all of Kodiak, all of the acreage and a full evaluation of that. And Bob and his team are working with Netherland, Sewell to get us to that point aiming at the end of the first quarter. Right now, SLB are working on the detailed development plan, so individual well placements, individual pads, what are the facilities that we need to have in place, how much horsepower do we need for reinjection, how many wells do we need for gas reinjection, et cetera. That detailed plan is being developed, and that will then be handed on to Netherland, Sewell to produce a report on the resources of the Ahpun development based on that underlying development plan. We will be looking at planning the appraisal of all of those areas that require further appraisal for the FID on Kodiak. I can assure you that the state of Alaska is not going to approve a multibillion barrel development on the strength of 3 well penetrations. So there will definitely be another 2 or 3 appraisal wells. The precise timing of that will be a function of funding. And the -- we will look to drill a well into the Eastern expansion in order to demonstrate the producibility and the flow rates achievable from that area, and that will help us to optimize the order of development in the same way as we move from starting out in the North to starting out in the South in those topsets, how much of the Eastern extension we have incorporated into the initial development will be determined by drilling over the course of the next 2 years. Again, precise timing depending on how the overall plan comes together. I know a lot of people were hoping for more commentary on funding. I'm going to just leave you by saying we told you that we would anticipate having the first substantial announcement around the nonequity-based funding during the first quarter, we're still on track for that. We told you that we anticipate by the middle of the year having the full suite of funding laid out for you, and we're still on track for that. We're at a stage in discussions where I'm not sure it's going to help us in terms of our counterparties to start talking about anything else. So you should expect that we're going to be quieter or noisier on that over the course of the next couple of months getting to that point where, by the end of the first quarter, we're able to share with you more substantive news. But what I can tell you is that our strategy is going to be the rule 1, you never go bust because you had too much cash. And rule 2, you can always get cash when you don't need it, and it's hard to get it when you do need it. So we're going to be using those 2 rules as a watchword. We will fund this conservatively. We will make sure that we are always going forward, over capitalize against foreseeable needs for capital, and that will be our guiding principle. So with that, I think that's the end of the formal presentation. And I think we can, Mark, I hand it back to you...

Yes, that's great, David. And David, I do apologize, I am muting you momentarily just so we don't get the noise playing back through for the audience online. But thank you very much, indeed, once again, for your presentation, David and the to the team. [Operator Instructions] While the team can take a few moments to review your questions submitted already, I'd just like to remind you 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, I know you've got attendees in the room with you. If I could ask you, please, if there are any questions from the room just to summarize them or repeat them for the benefit of those online. And can I also ask you, please, to open up the Q&A tab on the right-hand side of the screen. You should see a number of questions that were submitted ahead of today's meeting, along with the number that was submitted during your presentation. If I could ask you just to read out those questions, and then I'll pick up from you at the end, David.

Great. Okay. Certainly. The first question I've got here is can we advise the approximate date we expect drilling to recommence? And does the company have sufficient funds at present to undertake further on-site work? I'm assuming further on-site work means drilling activity in terms of that. So the answer is under the development plan, we're not anticipating drilling until the first quarter of 2026. As to whether or not there won't be any drilling prior to that, that will be a function of the funding strategy, and I'm not in a position to share with you specifics of that because, as I said to you, we'll be sharing more of that both at the end of the first quarter and during the second quarter. We do not have sufficient funds, nor have we plan to have sufficient funds to go drilling without having completed the funding strategy that we've described with you. The second question, in estimating value of North Slope Holdings, what assumption does the company make regarding extraction costs, short-term, medium-term and long-term prices? So the answer is we have -- when we've shared that target of $5 to $10 per barrel, very specifically, the $5 number is arrived at using $70 per barrel for Alaska North Slope Crude and planning for a 10% discount from that for the marketable liquid stream that we produce; applying the tariffs, et cetera, that you would expect to see; and applying operating costs, which are too detailed to describe, but it contains a fixed component cost per well, which is around about $150,000; and then a variable cost associated with how much water and therefore, how much disposal, et cetera, et cetera. But there's -- the end result is that at $70 a barrel and a 12% discount rate, we get about $5 per barrel. And at $80 per barrel and a 10% account rate, we get about $10 per barrel for the range of resources that we're talking about. So that's the basis on which we've done it. We looked at down to what oil price do you still get a 20% rate of return on the development, and that ends up being around $45 per barrel. So we think it's pretty resilient to what we do. When looking at the Kodiak field and its reservoir system, is it being viewed as strictly conventional? Or is there potentially an unconventional component being analyzed? Before I hand that off to Bob, the majority of the area that we previously had on the lease, we've talked about it being unconventional in the sense that it will require completion with long laterals and multistage fracs. So regardless of where you draw the line and where does it cross over from conventional to unconventional and vice versa, that would be focusing on the wrong thing because what really matters is what's the strategy we're going to use to produce it. But Bob, do you want to talk a little bit more about the reservoir quality as we move towards the Northwest and West?

Yes. Yes. Thanks, David. As we move to the -- as we move to the West, and we've also -- we've already shown this and we've published it. We're looking at substantial reservoir with better than 0.1 millidarcy. So it's usually the cutoff for people use between what they call conventional and unconventional. And remember, we're looking at a system that's up to 1,000 feet thick. And when we're looking at that, we're seeing, in some cases, up to 50% of that reservoir is better than 0.1 millidarcies. So the answer is yes. To the west of Theta West, a lot of the reservoir is conventional. As we move to the East of Theta West, it would be -- we'd be looking at it in that terminology is unconventional. But as David said, all of it is going to be developed using long laterals and multi-stage fracs.

And the precise anatomy of the completion will be an economic optimization. How much do you spend to get how much more flow ratio and ultimate recovery and you optimize it to make sure that every dollar you invest earns the highest possible return. So the completions in the far Northwest may look quantitatively a little bit different than in the Southeast. But qualitatively, they'll look very similar. Could we give a timeline for next steps and company goals for 2024 and if possible, '25? I think we've covered that. The only other thing to add that we know are going to happen in a relatively short time period in addition to the Netherland, Sewell report on Kodiak, the Netherland, Sewell report on the Ahpun development plan and our funding announcements that 88 Energy will be flow testing the Hickory well that will come in February, March of this year. From our perspective, if it flows successfully, that's great news if it doesn't flow successfully. It doesn't influence the areas that we've already flowed successfully from. So in a sense, it's a free hit for us one way or the other. In terms of hearing about financing, I've addressed that. We're still on the same track that we outlined previously. Would management entertain a buyout of just the Ahpun field in the next 12 to 24 months or prefer Ahpun-Kodiak combined deal? The answer is neither. Our preference is to maximize the value of the resources for shareholders' benefit. We would only contemplate a transaction in which we disposed of assets if it represents a better outcome than the alternative our singular focus is on achieving financial self-sufficiency so that we become price makers, not price takers. And we are not planning, we're not secretly bluffing that we're trying to sell the company while pretending not to. We're actually seeking to maximize the value of the resources reflected to shareholders. Next question, having invested around 3 or 4 years ago in Pantheon, I watched and listen closely to presentations where it was stated there were around 22 billion barrels of oil in the Alaska held acreage up for grabs. What happened to the 22 billion barrels? Or is there -- is it still there? Is it just the case that publicly, you've load your actual declared volumes because experts told you were incorrect? Why is this being glossed over? What I can assure you that it's not being glossed over. And I'm thinking that from the question, maybe there's a misunderstanding about the difference between in-place and recoverable volumes. Our assessment is substantially more than 22 billion barrels of in-place resources, and we have always stated conservatively that we saw between 8% and 10% recovery factors in primary recovery. So the numbers have actually gone up over time, not down over time. If anyone was the person who asked that question, I would invite you, by all means, if a further more detailed explanation would be helpful to e-mail contact at pantheonresources.com, and we'll be happy to clear up any misunderstanding on that front. Would you kindly outline the process required before you're able to book reserves and once this has been achieved, is it at that stage, the industry will recognize value in the ground between $5 and $10 per barrel of oil. Jay, can I hand it to you to talk about what's required for reserves to be booked, and then I'll come back to the second part of the question.

Yes. So we have to prove producibility and producibility at an economic rate. And in addition and there's a lot that goes into that. And then, of course, you have to have funding available to bring it into production. And those are the 2 critical elements because, as David just reiterated, we know that we have huge volumes in place. We know that we have huge volumes recoverable. The big thing is for us to prove our producibility at an economic rate and to have the funding available to bring it on stream.

Demonstrating a path to market. So the distance in the pipeline and our ability to have access to it, clearly important and the regulatory permits along the way. We've got a question in the room.

So in terms of the NSAI report, can we anticipate that there are going to be fewer conditions in the NSAI to report on the afternoon relative to the number of additions that was shown in [indiscernible].

I wouldn't want -- so the question was, will there be fewer contingencies in the Ahpun report than in the Kodiak report, I wouldn't want to prejudge the contingencies. What I can say for sure is that by the middle of the year, we will still have a contingency around pipeline access because we won't yet have the FERC approval for the hot cap, we won't have FID. So in terms of the specifics, I wouldn't like to guess, but it is an independent report, and that's the nature of independent reports. Yes, go ahead.

The first one, please, can I take you back to recovery [ devices ], so you just stated that we modeled our assumptions conservatively 8% to 10% [indiscernible] factors. Periodically, we read that places like crude are very particularly using [indiscernible] demonstrated up to 60% recovery. Mind you, there's quite a gap between the core and the tertiary in terms of [indiscernible] what sort of -- is it possible to extend our expectations for secondary and tertiary recovery factors?

So rather than repeating it, let me just check, Jay, was that -- could you hear that clearly?

No, I couldn't, David, could you repeat it?

That's fine. In that case, I will repeat it then. I just thought I'd test. So the question was, given secondary and tertiary recovery factors in Prudhoe Bay as high as 60% and our planning on primary recovery basis only of 8% to 10%, what visibility might there be to higher recovery factors from our assets. So the first thing is I very much doubt, in fact, I would eat my hat, where -- if we have a sort of recovery factors north of 50% in our assets.

David, can I just interject a little bit since I did have a prolonged knowledge about Prudhoe Bay. So Prudhoe Bay had a gas cap, an oil leg and a tarmat at the bottom of that oil leg. It was a perfect reservoir for a combination of secondary, which is water injection because the water couldn't go below that tarmat at the bottom of the oil zone and the gas cycling in the gas cap. So yes, the original recoveries were estimated at 30%, but I assure you the reservoir engineers at ARCO and BP and Exxon, we're always looking at recoveries that could go up from there. We don't have anything like that. However, in the up dip portions where we have better porosities and permeabilities we certainly should see primary recoveries above the 10% level. But we haven't assumed any of that.

Okay. And so our planning basis is that until we see any successful indication of secondary recovery being viable, we're not going to plan on it. That's in much the same way as many Lower 48 fields in the United States have they do move to waterfloods or CO2 floods or whatever over time. But typically, as a pilot program to see whether it works and it doesn't work in all reservoirs and so anything at this stage, given that we have no experience of pressure support, communication over long distances of [indiscernible], that sort of thing, it would be just pure speculation to bet on anything else. So sorry, not to be able to give you more comfort on that. Just want to pick up a couple of questions from online because there are a heck of a lot here, and then we'll come back to the room. Can we go into the detail on the rationale behind the planned U.S. listing? What's the cost benefit analysis? Which professionals other than bankers, brokers, lawyers and other advisers who are conflicted and will receive fees from the transaction, and then I'm going to editorialize and say, and therefore, can't be trusted are saying that this is a good idea? Current major U.S. and international investors hold U.K.-listed companies. Hence, the answer is yes. How much has it cost so far? How much is expected to have cost at completion? Will the Chairman personally underwrite the substantial cost of the transaction if the U.S. listing is not successful or does not achieve the results we expect. Please explain why this is not a huge waste of the Board's time and precious shareholder cash. Well, that's a compound question that I'm going to break down into its various parts. The first is that we don't rely purely on interested professionals to advise us what's a good idea. We also take independent views and talk to potential investors in the United States across multiple different class of investors, whether it's family offices, whether it's major public equity funds, hedge funds and others. And our view as to the investability of the company is conditioned by that as well as the input from the professionals who are listed. Notwithstanding that the many of the professionals who don't have an interest in whether we actually do list or not, they only have an interest in giving us the best possible advice have argued with us the pros and cons of that. There are certainly investors who are unable to invest in an AIM-listed stock. Some of those investors are able to invest in a main board listed stock and some of them are able to invest in a dual listed stock more easily than just a London-based stock because we're not talking purely about public market funds. The -- to date, I think it cost us what, [ $25,000 ] or maybe a fraction more. Yes. So but a few tens of thousands of dollars in order to properly flesh out how much we expect it to cost at completion, the majority would be backloaded and fees would be through the commissions on any funding raised at the same time as a U.S. listing. So the likely cost range depending on what it looks like. I fear that you'll be disappointed if you're expecting the Chairman to underwrite any specific corporate costs. There is a general situation in which we view that the management of the company is -- management of the company and the company is the legal personality that people expect to take the risk and as to why it's not a huge waste of the Board's time and money, I can reassure you that we have not just looked at it from a point of view of is it a good idea from an equity market perspective. We've also looked at it from the perspective of, is it a good idea for the company corporately. We are going to be undertaking extensive engagement with the state of Alaska with the federal government, with local communities and with policy generally in America. And in addition to views as to what the likely impact is on the stock price of the company, there is also a view on how it helps us to manage the risks and ability to get the approvals we need of having a U.S. personality being based in the U.S., and that feeds into our decision to be moving forward with this program.

[indiscernible] sectors in the U.S.

It turns out it is for the time being. Although, obviously, Alaska and the U.S., are they really the same thing. The answer is that we want to be both Alaskan and American in terms of how we act. There's a simple question here is, what is C5+. So hydrocarbons, you have methane, 1 carbon atom, 4 hydrogen atoms, ethane, propane, butane. You get to pentane. That is 5 carbon atoms, that is the point at which typically without the need to chill or to hold pressure hydrocarbons will be liquid. So when we get to C5+, it's typically what we're referring to is all of those hydrocarbons, which would be naturally liquid without the requirement for temperatural pressure control and that's why that's a typical cutoff when describing a liquid card. In terms of what will be marketable liquids, there will be the opportunity to include the butane and propane going into the Trans Alaska pipeline, although there may be slightly higher value in marketing propane as propane because that's used in a variety of different settings across Alaska and shipping it around and ethane will almost certainly be consumed as fuel in our operations. And the -- why are major oil companies seemingly not interested in Pantheon. I'm assuming that, that question is based on because a major oil company hasn't made an approach to acquire Pantheon. [ Argo ], they're not interested. And I think there are 2 ways you can look at this. One is to do the thought experiment that it will be very difficult, given the liquidity in Pantheon shares for anyone to acquire a position unnoticed of more than 2% or 3%. And investors, if they suddenly saw a major oil company having gone through the threshold and bought 3% of the company, my guess is that the share price wouldn't be what it is today and for a major oil company, they don't typically like to start a transaction that they don't know they're going to finish. So the question then becomes there's probably not a path to a hostile takeover at any kind of a price that reflects where we are today. The question then becomes does someone think about making an approach to Pantheon's Board at prices similar to today are liable to receive a recommendation and shareholder approval. And I don't think we could have been clearer about the fact that, that wouldn't be the case. If someone came offering $500 million for Pantheon today, I can reassure you, we would not be recommending that to investors nor do I believe that the majority of investors would be interested in taking that. So the answer is that until there is less of a mismatch between what a potential acquirer would perceive to be an acceptable offer and the current market price is highly unlikely that you'd see activity of that nature. Does that mean that there are no companies interested. The answer is no, I wouldn't think that is a fair reflection of the situation. Mark, you've just removed a question that maybe I can get it back, that I was about to get to.

Sorry, David, which question was that relating to?

Yes, sorry. I didn't take the next question in line because I was feeling there is something more. So if when a listing on a major U.S. exchange is obtained, will our shares on the ACC be transferable to that exchange, maintaining the long short status of all share purchases? I believe that, yes, because what would happen is that existing positions will be rolled over. I don't know enough about I imagine that naked shorts would probably not be covered in that situation, but actual short positions would be rolled over in that situation. When -- sorry, does the Ahpun East Topset qualify as a conventional reservoir? I'd refer you back to Bob's earlier answer. It may well, in fact, it definitely would on the basis of the numbers he shared earlier, be recognized as conventional but would that mean that it wasn't being developed with the completions that delivered the highest return on capital invested, which would likely involve long laterals and multistage fracking. The answer is that it would qualitatively look like the same kind of completion as we're finding across the entirety of the portfolio. Is Megrez a historical well or the name of Pantheon's next Ahpun well. Bob, you're probably the best historian here. Bob, do you want to address?

It's the name of one of the wells where or one of the locations where we have gotten permits to drill. That's all it is. And it's at that location, we can actually test and also develop the Ahpun East from west of the road, so on the west side of the river.

So we have a permit for the pad location at Megrez and the permit in [indiscernible] to drill from it, but obviously, the specific well permit. So the particular well plan would need to be approved by NSAI.

Correct.

What will be current shareholder dilution when the U.S. IPO is completed? I have no idea. Exactly, entirely so. So it depends what the share price is at the point that we do the IPO. It depends how much money we raise in the IPO. It depends how much other money we raised in the interim period as divided between equity and nonequity funding. When can we expect an update on the chimney. So the chimney, I'm going to ban use of the word chimney going forward. Because obviously, with the additional acreage to the east, it doesn't look like a chimney anymore -- sorry, to the West. It doesn't look like a chimney anymore. The resource is attributable to the 2021 lease sale -- sorry, 2022 lease sale rather, were incorporated into [indiscernible] initial evaluation, the revised valuation will incorporate all of the acreage that we now have and we're expecting an update on that around the end of the first quarter. Sorry, okay, we're moving to some different questions. So go ahead in the room.

So in terms of timing of your main market -- move to the main market. Would you be planning to do that before or at the same time as the U.S.? A lot of other companies have done that some time before, which case out for you on the target sometimes you see the main market.

Yes, that's a process we're working through. We don't see an firm answer on that yet. So we'll update the market when we know.

But I think it's -- the one thing we can say for sure is it's not going to be later than end of the year.

Yes. Yes.

Yes, of course, sorry. Just in case you missed that. The question was, would we be listing on the main market in London before the U.S. IPO or at the same time. But and the answer was certainly not later, but we don't have a specific answer.

You mentioned that you are in for a peak reduction of between 200,000 and 250,000 within 7 years. What would be technically and commercially feasible peak production for a major that is less financially constrained than you? Any comment?

Well, I think it depends ultimately on the pace of drilling in terms of -- and how much you expand the facilities into the pipeline. So the peak throughput of the tax pipeline was 2 million barrels a day, but it would be very hard to get back up to 2 million barrels a day. There's a lot of oil coming in from other sources. And so there are costs associated with step-ups. What would be a likely peak production rate if you think about, Jay, you'll remember, Kuparuk River was 390,000 barrels a day peak. Was it?

Something around that, David, and yes, we actually got over $2 million, but that required to use a friction reduction agent. And I doubt that anyone would want to revisit that.

In the room, there are people who are imagining what friction reduction agents look like available from all the pharmacies and the -- but the point about it is that I think the original plan for Kuparuk River was somewhat less than 380,000, 390,000 barrels a day. But the economics of expanding the facilities and expanding the throughput justified it. I could quite foresee a situation in which it became apparent once we've got enough production history to know that the length of time that we were going to exceed that 250-odd-thousand barrels a day would justify the additional investment, and therefore, we would expand it. If you simply run the math and have a continuous drilling program, you could end up at 0.5 million barrels per day. But would that be the optimum economic position, the answer is there are many factors and a lot more analysis before you do it. But the planning for our initial access into the Trans-Alaska Pipeline is going to be in that 200,000 to 250,000 barrels a day range and that's the size of access that we want.

So if someone wants to do that later [indiscernible]

We need a further approval for an expansion of that facility. Yes, another question.

Second question, can I take you back to the Ahpun development. Specifically the testing is outpaced and even more specifically today the RNS [indiscernible] process. When we presented in November, we had a nice plan with clients and all that kind of stuff, it's been materially offered today, what you've shown it looks a lot more favorable. How come we're in the situation 3 months later, whereby we are meeting a much more opportunistic production. Is it purely on the basis of what we have [indiscernible]?

And the pressure buildup. So the pressure [ transient ] analysis to understand...

David, could you repeat please? Question it was kind of unclear for me. I don't know about others.

Forgive me, I should have repeated it. So the question was we've announced a material update and upgrade of the forward projection compared to just 2.5 months ago when we showed the start-up ramp-up on the basis of the then type curve for -- based on the Alkaid test. And the question was what had led to that? And the answer is it's the combination of the GeoMark analysis of the fluids and the fresh trend in analysis using the data retrieved from the pressure gauges. So just to put it in context, the amount of flowing to a well is a function really of 3 things. One is the area, which is a function of 2 things: the area of the sand face that's accessing the reservoir, and that is, therefore, the width and the height. Now if you didn't have a frac the only thing that would really matter would be the height and the permeability. In a fracked well, it's the area of the frac and the permeability flowing into that because it's now linear flow into that. So the 2 factors that have significantly improved our view is the frac efficiency. So we now know we can get a highly effective large area in a frac. And the second is the permeability where we now know that the permeability is 2 orders of magnitude better than we had assumed in our original type curve. And so when you multiply those 2 things together, you get a significant increase in expected well performance.

And [indiscernible] effectively telling you that's about permeability.

So the pressure gauge so. It's the shape of the curve building up. If it builds up quickly, this is a massive oversimplification, but if it builds up quickly it is generally high permeability and if it builds up very slowly over a long period of time, it's generally low permeability. The precise shape of that, depending on how quickly you draw it down and how much you produce, how long you shut it in for leads to the ability to analyze what the in-situ permeability of the rock is.

Sorry, can I make a...

Yes, Bob. Please go ahead.

There've been a number of questions that are kind of bouncing around here. And one is when we tested Alkaid, we had the Alkaid anomaly, the first part of the test we had the results, and we took those results and we built our models. We had not yet tested the Alkaid to shelf upper zone. So we hadn't tested the topset, and we have a set of models. Those models were built by Schlumberger, and it said we have an economic development that we can move forward with. The Alkaid 2 taps quite simply, again, at the feather edge of the reservoir, we're saying we had a significant improvement in permeability, like 100x better permeability than what we saw in the Alkaid to the primary test. That leads you to saying, hey, this -- we can develop the topsets and this is what it's going to look like. I can tell you, as we move over to pipeline state, where we're in the heart of the topset that we had under release, we even have better reservoir performance. Now that hasn't been included yet into our analysis. It will be included. And then thirdly, as we move over to Ahpun East, we even have another order of magnitude improvement in the permeability. The point is we will be adjusting and moving forward, as we are proving these models up, there will be changes and it will be changes to the positive side. So what you're seeing today is our best estimate given on the test results that are verifiable as of this moment in time.

So our planning basis is restricted to what we have actually encountered rather than what we expect to be better as we move to the better areas.

That's correct.

Does better going sell to pipeline, is there better going East to the new?

And the pipeline, we -- at pipeline, we have whole core data through that reservoir. So the point is expect -- we can expect that there will be further changes. But right now, what we have is a fantastic project that is economic at today's prices, it's as David has said, we have a good project even at $45 oil.

There's another question in the room here. Go ahead.

Just a follow-on, David. With regards -- I mean, hearing that the direction of [indiscernible] better and you modeled from initial production test at 50% was -- moving forward into sort of a more conventional acreage. Can we assume that there's less flow and therefore, better [indiscernible] more oil.

Let me address -- repose the question for people online. As we move to better quality reservoir, will we see a lower water cut than we've assumed or have seen to date? The answer is quite possibly so. But again, it's not something we're planning on. And it's not something we're going to speculate on. We're trying to restrict ourselves in terms of statements of data is what have we actually seen. We have expectations, and we've shared some views as to how things might improve qualitatively. But to be honest with you, the amount of water is not a major driver of development cost or recovery, it's -- we're going to have to handle water no matter what and in large quantities, and we have a plan.

It might make a difference in terms of frac and therefore it is a huge difference in...

Sorry, in terms of number of frac, it's unlikely. The amount -- the water cut is unlikely to be a factor in terms of the number of frac stages. The number of frac stages is going to be to place the -- to grain the maximum area of reservoir that can be drained. So how close the frac stages are to each other is a function of the permeability and therefore, the pressure communication, i.e., robbing Peter to pay Paul with 1 frac stage to another, but the amount of water in there is not a major factor in determining that. Yes. I mean we can have a more detailed discussion, but no, that's not a major issue. There's another question there?

More financial question moving away from hydrology. Going forward, consistent with the development plan, is there a plan to engage with investors, institutional investors? And what are the key inflection points that make us more [indiscernible] along that process? And is that going to be expected by the migration to U.S.-listed investment?

Okay. So the question was engagement with investors during the course of the plan leading ultimately at the end to when we're up and producing. And so the answer is predominantly but the mix of investors who will have an interest will change as we get nearer to production. It will change as we appear to have less need of money. It will change as we become U.S.-listed versus not U.S. listed. That doesn't mean that there isn't a valid path to funding that doesn't involve the U.S. listing. As we mentioned, there are multiple dimensions to why being a U.S.-listed company and a U.S. legal company holding a U.S. asset and dealing with regulatory authorities also has an advantage. So this isn't a pure corporate finance game as to where do we think investors will pay the most because there are many investors who, as the earlier questioner correctly identified, they're not governed by where you're holding -- where the exchange is. Certainly, it's true that there are a lot of people who can't invest in an AIM-listed stock. And so whatever happens, that's probably not a long-term sustainable place for us to be listed. But we will be, during the course of the next 14 and a bit months, we will be engaging with a range of investors, not just North America, but generally in order to make sure that we're structuring ourselves and making ourselves known to the people who will increasingly be able to invest in us. I want to pick up some more from online before we come back to the room, if that's okay. How long is the U.K. listing expected to last after the planned U.S. listing by the end of Q1 2025? That will depend to an extent on a cost-benefit analysis if we had the main advantage of holding the U.S. -- the U.K. listing is probably for U.K. investors who have invested in an [ ISA ] or alternative tax-efficient wrapper and so we will take a view if the majority of capital gain, which is the main thing that people are looking to protect has occurred and the continued cost of having a U.K. listing is not attractive versus the benefits to investors then we wouldn't. And if there is an argument for keeping it, there is certainly no presumption about the timing of when we would or wouldn't lose a U.K. listing. We've heard all this before. I was looking forward to an update where do we stand on the Kodiak field? Do you have a time scale. So I think we've half answered that which is that we will be reporting on the full Kodiak resource with a better explained basis by -- we're aiming for the end of the first quarter. And we're also aiming in terms of the funding that we're aiming to meet the timetable was originally shared, which is by the end of the first quarter, we should have preliminary news on non-equity-based funding. And by the end of the first half, we should have the full funding program for our activity tied up. It's interesting that Justin has found another position, would you keep us updated on the new listing? I don't think Justin has found another position. We already -- he hasn't owned up to it, to us yet. What we're saying is that the current role as the needs of the company expand I know because I get e-mails from Justin later at night and earlier in the morning that is sensible for anyone who's hoping to stay healthy. What that means is that making sure that we allocate roles to allow people to focus on the areas that they can add most value. And in Justin's case that's being the Finance Director. So having someone else running the overall program of coordinating the different pieces for the U.S. listing program. It doesn't mean that Justin is not going to be involved in it. It just means that there's someone else who's keeping tabs on top of that. Similarly, it's not uncommon for the accounting and the finance to have some degree of separation or having a financial controller. Justin has been in fact as the financial controller for the last more than 17 years. So as the organization matures and the needs mature, so sorry to disappoint Justin, you don't have a new position. Alkaid 2 was landed in a highly structured part of the Alkaid reservoir, how much of the poll completion efficiency was due to having the wellbore out of the primary zone. That's probably a more technical question that requires more pictures to describe but the answer is undoubtedly some part of the well performance was to do with how the well was landed because it certainly came out of a zone at some point. And with hindsight, we probably would have landed it lower. But the majority of the well performance was a function of the frac design implementation and efficiency. Sorry not to give a more detailed answer on that. When is the Kodiak, Netherlands [ sell ] report coming in, we mentioned we've dealt with that. What can shareholders expect now in return for their investment? Or would it be logical to come back in 6 months to buy in? The answer is, if you think that it's a better idea to sell now and buy back in 6 months, you should definitely do that. And if you don't, then you shouldn't. And that is about the extent of any investment advice that I'm going to give to anyone. When do we anticipate U.K. listing to become defunct? We've answered that. We've answered the question of when would we move from the AIM to the U.K. main Board. What is our current value per barrel? Well, the market says that we're worth about $0.10 a barrel, we think we're worth considerably more. That's what we're working to demonstrate to everybody and we'll do it by doing lots of small and boring things that will lead, as I said before, to a point at which people begin to recognize that achieving the targets we've set has become inevitable. That's when I would expect to see a value of more than $0.10 a barrel attributable to our resources. Can we give a targeted breakeven per barrel. We've talked about when we run the state of Alaska, Alaska not slope cash flow model, at $70 a barrel and a 12% cost of capital, we end up at about $5 a barrel. When you take that down, and that incentive is about an 80% rate of return development from memory. I don't have it in front of me, so please don't hold me to that specific number. But when you take it down to what price gives you a 20% rate of return, which would be a typical threshold for moving forward with the development. That's around $45 per barrel.

That's your cost or...

That's the [ A&S ] price at which the development gives you about a 20% rate of return, which -- so that's sort of an equivalent breakeven. Appreciate drilling can't, I think rather than can begin until finance is addressed. Surely, the company will be actively drilling once finance is secured. Is it safe to presume the technical team is planning to drill Ahpun East topset so they can fire the gun immediately after financing is secured? The answer is the team is -- it's safe to assume the team is doing all the planning necessary for all the activities that the Board considers to add most value to shareholders. And that we are certainly not going to wait until we have completed funding before we start thinking about the next thing. We are going to be planning for the range of different things we would do given different timings and availability of financing. But the whole program is built around optimizing value to shareholders. Can we request our brokers not to lend out shares to short sellers? And if they have, can we ask them to restock? Can the company vote for a not-short selling Pantheon shares. I don't know that, that's something within our ability. I do know that typically, if you tell your trustee or nominee, that you don't wish your stock to be loaned then they can't. But I don't know. There are many different brokers and so many different paper work to go through. Sorry, I don't think we've got an answer to that. Have we provided estimates on the slope plan system within our acreage, if not, are we planning to do so? We have -- historically, we provided an in-place assessment. I think that was a couple of years ago. We haven't done any updated work on that since Bob, do you know?

I think we're going to be handling that as part of looking at the full field kind of development like Ahpun. We know we have the slope systems there and we're just kind of working on them. So there's -- I have no specific target for getting the full sort of resource on [indiscernible].

Okay. The question asked earlier wasn't from this person, but they think what the person meant was we previously said 22.8 billion barrels oil in place with 10% recovery. So therefore, 2.28 billion barrels recover all. People want to know where this has gone and the latest estimate. The answer is it's gone nowhere other than the how many thousand barrels we sold in the long-term test. And but we're anticipating -- when you add the new acreage and the revised estimates that, that will lead to an upgrade from the 22.5 billion barrels in place. We'll be sharing that over the course of the next 2 quarters in the 2 major accumulations, Kodiak and Ahpun. And what won't be included in Kodiak and Ahpun will be the additional zones that we have to incorporate such as the term and other things.

David, I was just going to jump in just to say that for every 1 question you answer, you're getting another 2 or 3. So just to remind you that there's always the opportunity should they get up and let me know of [indiscernible].

Okay. What progress has been made on the time to tap who's responsible for driving that process? At the same time, I'm going to say Pat Galvin, who is our Chief Counsel and Chief Commercial Officer, is driving that process in Alaska as we speak and we are -- we're taking a stepwise process necessary to get to that point. I'm not going to get into the details of it today. There's a question for, can we help people to map all of the individual's own names to the Ahpun and Kodiak field. I'm sure we probably can, at some point, what I'm going to tell you is the Kodiak field is the lower basin floor fan for all intents and purposes. Anything else that you may think is part of the Kodiak field, it is not part of the resources that are estimated for the Kodiak field. Will there be other zones that may, in due course, be incorporated in the Kodiak field? Yes, if we appraise them and find them to be economically developable. Similarly for Ahpun, the only zones that are included are the topsets and the Alkaid zone of interest, which is an oddity that just happens to have had a couple of wells drilled in it, and therefore, we've incorporated to do it. Anything else is not part of that. So all you need to know is that the Ahpun field is predominantly the topsets, what used to be called the shelf margin, they'll take various iterations of that, but it is now all of the topset and the Kodiak field is the lower basin floor fan. Any progress to relay about the proposed Alaskan gas pipeline, that would be a matter for the AGDC, the Alaska Gas Line Development Corporation to share. We understand that there are discussions ongoing with potential sponsors of that, and we would anticipate being a part of the conversation, given that we have high-quality gas along the line of the pipeline that requires less processing than gas from the North slope. Last webinar, Jay said 5 or 6 usual suspects. He did indeed. That's quite correct. We did say at the last webinar, we were not going to be providing continuing commentary on who was and wasn't in the data or more signing NDAs, what they were wearing or what conversations they've had with us at any point. Kodiak is fundamentally why many investors are here, Ahpun is stepping stone, but I feel we are -- I'm not sure what that word is on the Kodiak field. Do you think that's delaying or something, I'm not sure.

Lacking, I think.

Lacking. But I feel we're lacking on the Kodiak field. Okay. So there are -- the earlier state that we could begin production from the Kodiak field is in line with the program. Even if we had unlimited money today, we would still be talking about an FID in late 2028. So there is absolutely no lack of focus. In fact, you'll see that the early work on the volumes because it's so important to planning the overall scope of the development of the 2 giant fields. We have done a lot of work on Kodiak and that will be the next major report out, which is then on the entirety of Kodiak. Ahpun is indeed a key stepping stone in terms of providing the funding and providing the infrastructure that allows us to move into the development in Kodiak as quickly as possible. So if there's anyone who thinks that Kodiak isn't important to us, the answer is you couldn't be more wrong. Kodiak is absolutely where the largest volume is and where the long-term production will be supported from. What is Ahpun? If we forget about Kodiak, I'll assume that's not in the most physical sense. Ahpun is a giant field, in round numbers, 500 million barrels a day, I think official number 481 million right now. But when we've done the further work, we will be able to share a number for that. if someone offered you that for Christmas instead of Kodiak, it would be a pretty ungrateful grandchild who said to their grandmother that they wanted a Kodiak and not an Ahpun for Christmas. Ahpun is a giant and valuable field in its own right and more valuable in the sense that its proximity to the infrastructure allows us to build cash flow incredibly quickly to accelerate the development of the overall program. So it has its own value that would show up in the $5 to $10 a barrel range, but it also has a multiplier effect on the value that we can bring to Kodiak. The upgraded IP 30 figure 4,000 and 2,000 is an average number over the first 12 months, a massive upgrade. I have in mind the previous guidance was 1,500 to 2,000 for IP 30. Is that correct? This is very noteworthy, isn't it? Yes. How is the company going to ensure the stock market appreciates this revised guidance by telling them about it and by answering any questions people have as to how we arrived at it, by any definition, these are highly commercial numbers, correct. They were pretty highly commercially attractive on the original basis, we absolutely believe that more oil for the same money is more attractive. So no disagreement there. Is there a theory on why the GOR has improved so much in that topset test? Yes is the answer. But part of that is because of better sampling and better production practices that meant we got a more representative sample. Part of it is because the GOR in the Alkaid zone of interest test is probably an overstatement of the GOR because of the way in which that well was produced that resulted in more gas production than otherwise would have been the case. We still think there's a lot of gas and a lot of reservoir energy, but we think we've got a much tighter handle on it now. What is the current total number of barrels recoverable being used by management. We have announced a number in the past, which was the 1.7 billion barrels -- 1.78 billion barrels. And then add the 481 million, that's where you get the 2.2-odd-billion barrels. We will be providing updated numbers in due course. What is the current cash available and current monthly burn rate. Justin, do you want to talk a little bit about that?

Yes. We announced -- at our year-end, we announced that we had about $8 million -- just under $8 million in cash. And if you recall, there was a placement in equity placement with deferred terms. That money is presently in the process of being collected by the company, and that's about another $4 million, which is a little bit over $4 million. So that's where we're at. In terms of cash burn, our G&A was around -- was running around $7 million. That will naturally increase as we move towards the U.S. listing with additional costs, but that's a fairly representative number.

Okay. Thanks for the update regarding Justin. It sounds like there's a shareholder who is as relieved as we all are on that. The entire webinar seems to have avoided Kodiak, could Bob discuss further? I don't think we have avoided it. Bob, is there anything more you'd like to say about Kodiak?

Well, I want to -- just want to say the presentation on the Eastern acreage was just to say this is the work -- the new work that we've seen since the last webinar, which was highlighting the quality of the reservoir we expect to see in Ahpun East. We are working on Kodiak now and within 2 months, we expect to have like a major, major update on Kodiak. But I'll remind you, on the last webinar, we are showing a significant improvement in the reservoir quality as we move to the west. What that all means, we're hopefully have that answer for everybody by the end of the first quarter.

[indiscernible] is having currently drilled and completed wells, all being plugged or abandoned or similar plan as producers, I'm going to add in or injectors similarly, will the forthcoming appraisal wells on Kodiak sub-facility be planned as producing wells. It is -- not all the wells have been abandoned, but ultimately are likely to be. We are hoping to use the Alkaid 2 well as an injector but as things currently stand, that we don't -- we're not planning on appraisal wells, which are likely to be drilled from -- on ice pads to be completed as producers, but you never say never. If it turned out that one was drilled from a location that was ultimately going to be a gravel pad, I can envisage it would be, but that's not a basis for planning. Are there any more questions in the room?

There was one question in the last [indiscernible] that drew attention to hear you.

Somebody brought that up.

You know what there was -- so I think there's [indiscernible] that was a podcast. And I'm sorry, there was some editing of that which created around misleading because earlier at the south of the webinar, he asked me what I'm doing, and I talked about -- mostly about Pantheon and a little bit about Proton Green, which is a helium production company. At the end, he -- as he's starting to wrap up because he had originally intended that we were going to talk about both companies. As we started wrapping up I typically put a face holder for him. Don't forget we were going to talk about helium and carbon dioxide, which is what Proton Green produces. So apologies if that all got mixed up because I think the Proton Green reference at the start got cut in the edit. I mean I can absolutely assure you, Proton Green is 100% focused on producing helium and carbon dioxide. Pantheon is 100% focused on appraising and developing oil and so it actually -- anyone who assumed that statement was to do with Pantheon, I know I saw Paul corrected that online for a few people. I think the people have got there a bit garbled on that.

I'm going to ask a really tough question. That is, if the world goes to [indiscernible] '24 as it seems to be aiming that way. And we are not able to get financing. When we look at this project as is we go to say you'd have to put it into auction, we cannot get financing. What would you say the value of the asset as it is. What do you think we can get for?

If you could -- if you were to try and sell it today just as is where is?

[indiscernible].

I wouldn't want to speculate on what that might be. It would certainly be less than we would get if we were to development. If we -- I would have to take advice if we were to put the company up for sale today and people knew that the company was truly up for sale, what price would we get compared to people making speculative offers? I don't know is the answer.

What is the price of oil in the ground?

Today? There's no individual price that you could apply -- sorry, there's a general price you could apply for oil in the ground. The market has been pretty clear that it thinks it's about $0.10 a barrel in our hands right now. I'm pretty confident that if we were to sell the company tomorrow, it would sell for more than the current market capitalization. I think the thing that would stop it from achieving that would be if people didn't believe that you were serious about completing a deal. But I don't have a good answer to it. It's a great question. For anyone who didn't hear the question, the question was if you put the company up for auction today, what would it sell for and I don't have a good answer for that. I'll hold my hand up and be honest.

There was in the ground oil deal in Alaska not that many years ago, all on strong.

Yes.

I think the valuation was about $3 a barrel.

It depends on what you think the volume was because the seller might have said that there were X number of barrels to buy, I might have said there were this number of barrels. So the number could be between $1 and $3.10.

That deal did go through?

That deal did go through. And so the question is, where is the marginal buyer today? Was that a stroke of luck? Was that the result of strong competition. There are quite a lot of unknowns that would make it unsafe to definitely read across as to what the precise number would be, I just don't think I've got a good answer for you that I would feel comfortable was credible in terms of its foundation. And I always said to you -- I'll tell you the truth when I know it. When I don't know, I'll tell you, I don't know, and this is one of those I don't know. Any other questions before we wrap up? Okay. Last question.

Could the recent share price performance of another U.K. company with U.S. assets. This is, I think, in November of last year, share price going [indiscernible] happening business. Does that make Pantheon a tougher sell or are you aiming for a different success that you potentially get investors on that?

I don't think we look like the company that's listed. I think every -- so the question was, is past experience of U.K. companies relisting in the U.S. relevant to whether or not we're likely to be successful. The answer is that we can only focus on what we have, how that interacts with potential investing market. And what I guarantee is that if we need money, then we're less likely to achieve success, then if we don't need money, the objective here must be to maximize the value. Someone speak in a question. Someone in Huddersfield says his wife is desperate to divorce him and wants the share price to rocket. Hoping we both get our wishes. So it wasn't really a question. It's a comment. With that, Mark, back to you. Thank you to wrap up.

That's great. David, Jay, Bob, thank you once again for updating investors, and thank you to everybody for your considerable engagement this afternoon. Can I please ask investors online, 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 of Pantheon Resources, we would like to thank you for attending today's Annual General Meeting, and good afternoon to you all.