Good afternoon, ladies and gentlemen, and welcome to the Pantheon Resources plc investor presentation. Throughout this recorded presentation, investors will be in listen-only mode. Questions are encouraged and can be submitted at any time using the Q&A tab situated on the right-hand corner of your screen. Simply type in your questions at any time and press Send. Given the significant attendance on today's call, the company will not be able to answer every question it receives during the meeting itself. However, the company can review all questions submitted today, and we'll publish those responses where it's appropriate to do so. Before we begin, we'd like to submit the following poll, and as usual, I'm sure the company will be most grateful for your participation. I'd now like to hand over to Executive Chairman David Hobbs. Good afternoon.
Thank you very much indeed, Mark, and good afternoon, good morning, and good whatever, depending on where you're joining from. Thank you for spending the time with us. Before we kick off, it's important that we share the disclaimer, give you an opportunity to read it, maybe later. The presentation has been posted to the website, so it's all there. On with business. Today we're gonna be sharing six things with you.
First, we're gonna tell you about the first of two independent expert reports covering the two horizons within the Ahpun field that have so far been flow tested successfully are going to be delivered, one imminently from Lee Keeling & Associates on the Alkaid zone, and the second from Cawley, Gillespie & Associates on the Topsets, the western Topsets in the Ahpun field. Again, expected shortly, but we know that the Lee Keeling one is imminent. These estimates will not be contingent on economics because we've asked them to include an economic analysis in their work.
We will address the contingency on marketability so far as we have a legitimate path to gain access to the Trans-Alaska Pipeline System and in due course, the in-state phase of the Alaska LNG project pipeline to Nikiski, should that project proceed. Alternatively, we've investigated the injectability of the gas back into the Topset reservoirs for storage and found that that is feasible. The second thing we're gonna share is the most recent resource estimates from Netherland, Sewell & Associates updating their report on Kodiak to include the new up-dip acreage acquired in the recent bidding round. This is gonna confirm a best estimate of 1.2 billion barrels of marketable liquids and around 5.5 TCF of natural gas.
Third, we're gonna share the results of SLB's dynamic modeling of the Ahpun Topsets at the Pipeline State-1 location, which is calibrated to the whole core gathered in that well by ARCO and reflects the results of the recompletion and flow tests of the Topsets in the Alkaid #2 well. This is gonna demonstrate EURs per well, Expected Ultimate Recoveries per well of 3.7 million barrels of marketable liquids and 8 BCF of gas. That's consistent with Pantheon's own internal work on type curves for each of our main reservoirs. It gives us confidence that our methodology and analysis are robust and results in a planning basis for the Ahpun Topsets of 3.5 million barrels of marketable liquids per well.
Using the same methodology, we've estimated type curves for the Kodiak reservoir, both at the Theta West number one well location, where our planning basis is, for the time being, 3.65 million barrels of marketable liquids, and also at an up-dip planning, up-dip appraisal location, where, as you'll recall, there's a reduced depth of burial, and that has a planning basis of 4.56 million barrels per well Expected Ultimate Recovery. The analysis that we'll be sharing with you supports our belief that Kodiak's resources can be developed economically. The pre-tax economics on each of these wells, type curves, is has been run at between GBP 60-GBP 90 per barrel of ANS, and we'll be sharing with you, but the headline is that in all circumstances, they, individual wells on a marginal basis deliver more than 100% rates of return.
The fourth thing we're gonna share with you is the work we've done on the eastern Topsets of Ahpun. That's the next cycle of Topsets to cross, which we expect to exhibit conventional reservoir characteristics, even on a par with the Pikka-Horseshoe development, and with best estimates of prospective resources of more than 600 million barrels of marketable liquids. Bob will be going into more detail on that. The fifth thing we're gonna explain to you is the importance of the announcement that we and AGDC agreed two weeks ago about the proposed agreement on natural gas and how it ties into our funding strategy.
I'm gonna hold my hands up, figuratively rather than literally, and say we could have done a better job and been more explicit about the link between the two. We'll explain why the pipeline project does not rely upon the LNG export plan or the participation of other sellers of gas and how it will support potential non-equity funding of Pantheon's Ahpun and Kodiak developments. The final thing, and sixth, is we're gonna explain the basis on which we disclose the helium potential identified in the Kodiak field. It lies between two radioactive shales, the HRZ and the Hue. While there can be no guarantees that this helium will be present in sufficient quantities to make it commercially extractable, Pantheon is taking steps to ensure the opportunity to refine the concentrated helium stream that would constitute the gaseous residues from an LNG plant if one were built.
The reason we haven't disclosed it previously is that without any way of accessing helium and doing anything other than producing reinjecting natural gas meant that it had no commercial significance, but we're now obliged to mention it as part of what we're sharing with you. We're doing everything we can to accelerate vendor pro financing. We're still in discussions with one large contractor and we hope to be able to share information with you in due course and certainly to meet our commitment to lay out the full shape of our funding strategy by the end of the second quarter of this year. At the end, we're going to try and answer all the questions that we legitimately can either or have time for. Just a reminder of the two major fields.
Ahpun constitutes everything above the Hue Shale and below the Decker D. There are resources included for it and we are doing development planning on the topsets, the shelf margin, deltaic horizons as well as on the Alkaid zone. It does not include anything for the upper and lower slope fans. Secondly, Kodiak constitutes everything between the HRZ and the Hue. And that only includes the lower basin floor fan. It does not currently include resources for the upper basin floor fan and the Kuparuk River Formation discovery that was made in the Talitha well, again, not included in any resource estimate. Hopefully that clarifies for everyone what we're talking about. When we talk about Ahpun, we're talking about the topsets, the Alkaid zone, and we're talking about Kodiak, the lower basin floor fan. With that, I'm gonna hand over to Jay.
Okay, we have two independent expert reports that we've talked about. Cawley, Gillespie & Associates work is underway on the Ahpun field, as David said. Lee Keeling & Associates, who did an original independent expert report on the Alkaid zone back in January 2020, has reworked what they've done before with new data, and we imminently expect that to come. We have also, as David said, used the SLB modeling, their dynamic modeling and our own internal modeling to look at type well curves. We've done this on a single well basis for the Ahpun field top sets. We'll show you a layer cake model later in the presentation on that. We have used 3.5 million barrels EUR, where the SLB model was 3.7 million barrels expected.
The Kodiak Theta West has a little better KH in it, so it's a slightly better EUR of 3.65 million barrels. The Kodiak updip that we've talked extensively about, and we're expecting conventional type reservoirs there, and Bob will talk a lot more about that later. We have 4.56 million barrels of EURs. All of these wells have in excess of 100% internal rates of return. Now, here on the right-hand side, you can see the actual layer cake model that SLB did for the single well SMD zone type well. You can see the green, the yellow, and the red is layered in, and that is exactly emulates what the reservoir looks like.
We have some high permeability and porosity zones, some that are average and some that are poor, and they are stratified throughout the height of the reservoir. That is exactly what SLB modeled. We drilled it. They did it with a 10,000 foot lateral. You can see the frack height and lengths that we've assumed with a cluster efficiency of 80%. We have capped liquid rates, so that's both oil and water, at 5,000 stock tank barrels a day. We've capped the gas rate at 10,000 MCF per day. You can see they did a Monte Carlo analysis with the oil EURs having a range of 1.1-5.6, and the NGLs 0.5-1.3, with gas basically 5 BCF-14 BCF.
The best case yields 2.9 million stock tank barrels of oil and 800,000 stock tank barrels of gas. I mean, of condensates and liquids, and 8 BCF of gas. This is reasonably conservative because we use 95 barrels per MCF of condensate and NGLs, which was well below the actual liquid yield that we had seen for the SMD test. Now, here are the actual IRRs and NPVs for those wells based on the EURs and at an ANS price of GBP 60, GBP 70, GBP 80, and GBP 90. You can see the assumptions down below. We have GBP 7.50 in transportation. We've got one injection well for every three producing wells. We assume GBP 17 million for a production well and GBP 15 million for an injection well, and then GBP 50 million for a pad, including facilities.
We have state profits in. This is without federal income tax. You can see the NPVs and the IRRs obviously are greater than 100. The NPVs are incredible for these investments. When you add the well cost for the injectors and the cost per well per pad, you've got 1/1 to 6/1 in NPV to investment on the mid case 365. Something a little less than that for our Ahpun Topsets. You can see over on the right-hand side, the Kodiak up-dip, incredible return on those wells. These are hugely economic wells under any scenario, GBP 60 a barrel ANS, and we know that ANS trades for something close to Brent. The Ahpun field, the Eastern Topsets, I'm gonna turn it over to Bob to talk you through our best estimate of the Ahpun field Eastern Topsets' reservoirs.
Hello, everyone, and thanks for joining this presentation and the webinar. Yes, I'm gonna take you through our recent evaluation of the Eastern Topsets, and you can see now that our best estimates are circa 600 million barrels of marketable liquids recoverable. That's up from the 300+ million that we were looking at when we first discussed this with you in the past. Slide here, we're gonna look at the total Ahpun field. When we look at the total Ahpun field, which includes the Western Topsets around Pipeline State, the Ahpun anomaly, and the acreage that we just picked up in the lease sale, which is. Let me mark this up for you. Right here is what we picked up in the lease sale.
That's the Ahpun Topsets on the east. Our total sort of best estimate of contingent and prospective resource is over one billion barrels of marketable liquids. That number there is broken out in the west. We've published in the past about 400 million barrels. The Ahpun zone of interest, we have an IER of about 76 million barrels. The new resource estimate on the Ahpun Topsets in the east of 600 million. We mapped this recently. We got multiple targets. Our geologic chance of success, which I know we are continually asked, we hit this at about 70% chance of success.
When you look at the whole Ahpun field, what is important about this is, of course, that it's its location next to the pipeline. Let me mark that in here. That's the pipeline, right? Oops, sorry. That's the pipeline right there. And the haul road, which you're seeing right there. All of that means we're close to infrastructure, and we are, you know, it's easily developed. Do all that. So get rid of that. The important part of this is on the Ahpun Topset is that this is a conventional reservoir. It's younger, shallower than the Ahpun Topsets that we've intersected at Pipeline State-1. We have sidewall cores at Pipeline State-1 that indicate that the reservoir quality is gonna be something of between 20%-25% and 5-35 millidarcies.
This is a very good conventional reservoir in the range of what the Nanushuk looks like to the west of us. What does it look like? This is seismic line through it. The highlights on this line for all of you out there is, of course, that we've tested oil here in the Topsets at Talitha. We got some oil out of it. We know we have oil at Pipeline State. And over here is what we're going for in to the east. It is shallower. It's younger. There are sidewall cores in the Pipeline State that have ranges anywhere from 22% porosity. This is the information over here.
This is actual sidewall core data that anywhere from 22% porosity up to 34% porosity in the sidewall cores, and we have a sidewall core that has permeabilities of 35 millidarcies. This is a very much conventional reservoir. Remember, we always do what we call the seismic attribute analysis. This is the work done by Roger Young and his team at eSeis. Every single time when we've tested using this approach, we have found light oil. The multiple targets that you see in the Ahpun topset in the east there all those things light up and are telling us that we have light oil in those reservoirs. The other thing is our proposed test, which is the Megrez location, which is right there.
That well, we believe we can drill it from west of the Dalton Highway. We have a location that is already permitted where we can drill. We could spot it there and test across the Sagavanirktok River and go in and test these ends here. We're gonna try. We're gonna hit all the targets that we can map in with this one well. Of course, I wanna emphasize that this is just the Topsets resource number. We have identified other reservoirs and but we have not done the volumetrics on that. Here's the actual numbers and on the map, the different reservoirs labeled TS 1, 2, 3, those are.
Each of those zones have been mapped, and you can see the acreage outlines on that. The total estimate on this is 609 million barrels of recoverable liquids. Net to us, it would be about 527 million barrels. That's after taking out all the revenue for the state. Next. Now on to Netherland, Sewell. Netherland, Sewell, as we announced yesterday, came up with a new upgrade resource analysis on the Kodiak field, and that upgrade is to 1.2 billion barrels of marketable liquids. This is a contingent 2C number and includes all the leases that we've acquired in the last lease sale. Again, this is the NSAI disclaimer. You can, you know, read that at your convenience.
This is the actual table that they've put out. The numbers, I can only say they speak for themselves. It's, you know, 1.2 billion barrels. Their best case 2C estimate is 1.2 billion barrels of marketable liquids, oil, natural gas, and condensate and 5 TCF of gas. On the high side, which is important to look at, it's 2.8 billion barrels of marketable liquids and 11 TCF of gas. That's a 40% increase on what we had in our previous estimate. That is because
These numbers have moved because what we've been able to identify and what they've concurred is that as we move up dip, less Dmax, we're gonna encounter better reservoirs, and there's a portion of these reservoirs that are going to be conventional reservoirs. Conventional is just usually defined as having 0.1 millidarcies or better. Here's the map that shows the outline of where NSAI have mapped what they call Kodiak up dip, which is where the porosities are 12%, and more importantly, where the permeability, average porosities are 12% and average permeabilities are 0.1 millidarcies. Again, I wanna emphasize, those numbers are average. That means we can expect to see better than that in this portion of the field.
That up dip, which it starts sort of right here or at that marker right here and goes up dip in that direction over here, all of that's over 40,000 acres of reservoir that would be considered having an average of being considered a conventional reservoir. Why is that important? It's important because, as Jay showed, we're gonna get better EURs. We're also gonna get much higher recovery. As a matter of fact, in that area up dip there, we're almost double the recovery factors that we have around Theta West, which means that, you know, how we would develop this and what our EURs are significantly improved. This is the actual numbers that they used.
One of the things you'll see here is the reference to Tarn Meltwater, which was the analog that we thought, and they agreed, was the closest analog to what we have at Kodiak. They've modified some of the Tarn numbers because of slightly different Dmax. But in here, just to highlight, our best case recovery factor is about 15%. It was 7%. Here we can move this. We actually believe that this is the recovery factor that we see here in the high case is about 30%. What's important here is when you look at this, we have 1.2 billion barrels already. That's a massive discovery, you know, for just from the liquids point of view.
There's a potential to move that to the 2.8 billion by our appraisal program, the wells that we drill, and that we can show that we have the higher porosities and higher permeabilities that would be associated with moving up dip. In other words, the greater than 0.1 millidarcies. Understanding the distribution of porosities and permeabilities that are greater than that, we'll be able to move our numbers from the 1.2 to the 2.8. With that, I'm gonna turn that back over to Jay and to David.
Natural gas. Thanks a lot for whoever just remembered to unmute me. Natural gas. Thanks, Bob, for hanging on. We announced a few weeks ago that we were in discussion and Frank Richards, the President of AGDC, included a quote in our press release. We're gonna talk about the form of the proposed agreement and why we believe that that is the underpinning for substantial non-equity funding capacity. We're gonna explain to you why the pipeline doesn't require the LNG project to move ahead. There's an in-state phase first. Finally, we'll talk a little bit about the helium opportunity.
The proposal that we are discussing is to provide up to 500 MCF per day of methane at a price up to GBP 1 per million British thermal units at the exit of the Ahpun facility so that that would be no capital cost to us. It would simply be a choice between are we reinjecting that gas or is the exit from the compressors putting the gas into the pipeline. The GBP 1 is obviously a base price. It gets escalated with inflation or an appropriate package of escalators to take account of general price rises in the economy. The terms on which we were we're agreeing it create the opportunity for helium that may or may not end up being produced along with the gas.
Of course, there won't be any helium in the Ahpun gas. That is the first gas coming into the system. If there were helium, it would only be in Kodiak gas, which would be more aligned with the timeframe in which an LNG project might be added to the initial in-state phase. That in-state phase is for a 42 in pipeline. It's the pipeline that has already been permitted as we'll come through to talk about, and supported by federal loan guarantees. With an original estimated cost of just under GBP 11 billion, rather than the full cost of the project, which was estimated at GBP 45 billion-GBP 46 billion.
That if we had a take or pay contract for a minimum of 20 years, then if you take the present value of the post-tax cash flows from that and discount it, and take a 50% haircut for any lender's cover ratio, provides up to GBP 250 million worth of debt financing capacity. Obviously, that is debt that can be drawn for the development of the wells that will produce the gas, which is the same as the wells that will produce the oil, and will be drawable from FID on the project.
We're actually talking with the state about ways in which we can make the gas cheaper still to them, without damaging the ability to support the financing capacity, and looking for mutual benefit, on that. The key thing is that the gas commercialization, taking what would otherwise have been a liability for us in terms of incurring additional costs throughout the life of the assets for gas reinjection for storage. It's not actually terribly important to the recovery of oil and gas in the primary recovery stage, because that's the expansion of gas in the reservoir, forcing the oil out. If you don't allow that pressure to drop and for the gas to expand, then you don't get the primary recovery.
It's about gas storage for the long term and for preserving that resource for the benefit of the state in the long term. There can't be any guarantee as we said at the time that we'll conclude agreements, but I can say that we are in detailed negotiations. Over the coming weeks and couple of months, you'll be hearing more about that. This is a key underpinning of our ability to mobilize non-equity capital to support the development, which is the lion's share of the costs that we talked about as being required to get us through to cash flow breakeven and financial self-sufficiency. The gas pipeline, the 800 mi pipeline, has an LNG export permit.
It has its right of way and the major environmental permits already granted, and it benefits from a 60% federal loan guarantee in addition. The remaining cost of that pipeline, say in the order of GBP 5 billion, is supported by the take-or-pay obligations of the shippers of gas through that pipeline, which is supported by the ultimate purchasers of the gas. The state is very committed. You heard Governor Dunleavy at CERAWeek, and you've heard Frank Richards, and you've heard other key stakeholders in Alaska talking about their commitment to finding a way of moving forward for the initial in-state portion of the project. Of course, having the pipeline built enhances the attractiveness and economics of a subsequent LNG development.
That's where if we are lucky enough that the LNG development goes ahead, we find ourselves in a position where there's an opportunity to commercialize helium should that prove up in appraisal. AHS, you'll remember they're the people who have done all of the analytics on the cuttings from our wells. They take gas samples, and in the IsoTubes, found concentrations of helium. We don't know yet what those specifically mean, but we do know now that it's worth being very deliberate and having a specific protocol for gathering gases in the IsoTubes from the appraisal wells we talked about for the western extent of Kodiak. If that proves up, then indeed helium could be a very nice addition. It doesn't form any part of our current investment case.
It does, however, make sure that the state is very aligned with us in wanting the development to move forward because it's an option to extract more value from the state's natural resources. I mentioned in my introduction that in terms of vendor financing, we're down to a single large service company that we're negotiating with. We talked previously about being in negotiations with two. We've homed in on the one that we think is the best option. We will doubtless be in a position to announce something in the timeframe we originally talked about. As I said at the start, I hold my hands up. We should have been more specific when we told you about the gas negotiations.
That is a core part of our funding strategy. It always was. We talked about offtake of financing and vendor financing and some combination of the two. We talked about how if everything came off, it might exceed the GBP 120 million-GBP 150 million. That is still the case, even if the makeup of that is different than we might have imagined at the start of discussions. Of course, once we've moved forward and got further appraisal, there are no reasons to expect that we can't reopen discussions with people that we parked in the short term, because they had concerns or we had concerns about the acceptability of terms or the attractiveness of the opportunity. I want to summarize in the end, our strategy remains unchanged.
It is to achieve sustainable market recognition of GBP 5-GBP 10 per barrel by the end of 2028. That's the timeframe in which we expect to be getting to FID on Kodiak. Hopefully we'll have been able to get Ahpun up and producing sufficient to deliver cash flow for funding the continuing CapEx. To get to the point at which we're cash flow self-sustaining, still the same numbers as we shared with you at the end of last year. 24 wells required in the initial Topsets, we anticipate from two initial pads, and maybe 1/3 just being added as we get to that number, and delivering at least 20,000 barrels a day of liquids into the pipeline.
Just to remind you and to reiterate, we've had the Netherland, Sewell updated report. We've had SLB's single well modeling, and they're now working on the full field modeling to support our FID and regulatory applications. We're expecting the Ahpun Alkaid zone estimate imminently, and Cawley, Gillespie's estimate on the top sets to be released in the not-too-distant future, but shortly after that. With that, Mark, I'm gonna turn it back to you for Q&A.
That's very kind. David, Jay, Bob, Justin, thank you very much indeed for updating investors. Ladies and gentlemen, please do continue to submit your questions. Using the Q&A tab on the right-hand corner of your screen, just simply type in your question and press Send. Just while the guys take a few moments to review your questions submitted already, I just want to remind you that a recording of this presentation, along with the copy of the slides and the published Q&A, will be available via your Investor Meet Company dashboard. David, if I may just hand back to you. As you can see, you've had a number of questions submitted ahead of today's event and from the attendees today, which is very significant.
f I may just hand back to you just to moderate through that Q&A where possible, take those questions, and give response where it's appropriate to do so.
Certainly. Thanks. One of the questions was what helium on Kodiak. I think we addressed that in the subsequent presentation. There are indications that there may be helium that could be in commercial quantities, but absolutely no guarantee, no value taken for it, nor is it the basis for investment. As soon as we had a potential market for natural gas that would cause the helium to be producible, we considered that to be price sensitive non-public information, and therefore we're obliged to share it. Second question. What has the bondholder done with shares taken in payment on their amortizations? Justin, can I hand that one to you?
Yeah. Sure, David. Look, the bondholder ultimately sells some or all of that stock, but they do it in a very measured way. It's a great question, and there's a lot of misunderstanding. They're not the big bad wolf I think that many expect. They've been very supportive. In fact, what most shareholders don't know is that they've supported at an equity level all of our fundraisings since they've come in as an investor, including the original transaction where they came in and lent us money. Look, they lent GBP 50 million unsecured. They're not an equity holder, they're a lender, and they obviously need to manage their risk. That's their core competency. We've known that all along, and I've got to say to you, they've behaved incredibly well.
We couldn't be more pleased with the way they do it very professionally. They do hold a position at all times, is our understanding. Whenever we've asked the question, they've always been very forthcoming in showing us that information. Ultimately this bond, just so everybody understands, for the terms for Pantheon. You know, we borrowed GBP 50 million. We paid that back over five years quarterly, so it's GBP 2.5 million per quarter, plus the interest. The interest is accruing at 4% coupon rate. I mean, they're fantastic terms. We can make those payments in cash quarterly, or we can meet it through stock.
If we do it through stock, we do it at a 10% discount to essentially the VWAP of the stock price. It's not a huge margin. What I would say and what I really wanna stress is that for shareholders, the bondholder makes their money if the stock really performs. They want to see the stock perform. Today, for example, if we had to repay a bond payment, it would be. If we did it via stock, we would issue it at a 10% discount to the VWAP in the period building up to the payment date. For example, if the share price was 40p and the VWAP was 40p, we'd make that payment in stock at 36p.
Now, what I would say to you is there is a maximum conversion price, which is where the bondholder makes their money. If our stock price tripled overnight and we made a payment, well, then they would get all of the margin above that price, which is currently at about 91p. So $0.91 . So the sterling equivalent of that, a little bit above 70p. It's not until the stock reaches above 70p will they make their real margin. Of course, at that point, we've got many ways of dealing with the bond if we wanna minimize our cost of capital. We could go and raise equity at, you know, if the stock went to GBP 1, we could raise equity at GBP 1 and repay the bond.
There's many ways we can do it. Yeah. I hope that answers the question. They always manage their position. That's the business that they do in the same way as the bank has to manage its risk position. It's an unsecured position and they've been very professional in the way they do it. I hope that answered the question. David?
Thanks a lot, Justin. Yeah. There's a question: do we expect summer drilling? Sorry. Do we expect to be drilling in the summer season or the coming winter? Jay, we talked about four wells, one in the east and the others in the west. Do you wanna quickly talk about potential timing on that?
Sure. Thank you, David.
Turn, yeah. Hang on.
Yes. Can you just leave your microphone as it is, Jay, and we'll kick to David. Thank you.
Good question. Subject to funding, obviously. It's unlikely we could get ready to drill a well this summer. All the work that needs to go in advance of making sure we do that well as any well as effectively and as inexpensively as possible. Unlikely we could do that in the summer. A winter well, yes. We could be ready to drill a winter well subject to funding. There is a lot more activity on the North Slope now with both ConocoPhillips and the Santos groups going full bore on their operations and of course Hilcorp continuing to recomplete wells at Prudhoe Bay and at Kupik. Yes, we could be drilling in the winter.
We could do a second well then, after that in the spring or summer timeframe. If we had funding for two wells, one in the west at say Pipeline State and one, the Megrez's well that Bob outlined to you, it'd be great to be able to do them back to back, and we'd love to do that.
Sorry. I think you meant if we had one in Kodiak to the west. Sorry. Yeah. The answer is, as Jay says, we can drill the eastern well from Megrez-1 during the summer or winter. If it's cheaper to drill it in the summer, it would make sense to drill it in the summer. Whereas drilling out west on Kodiak, it requires an ice pad, so it's a winter drill. Obviously, development drilling in Ahpun and Kodiak out on the tundra will be on gravel pads. There was a question about, can we talk more about the Kodiak development with...
In terms of depths and stuff like that. You can refer to the slides. In terms of cost of the LNG project, there was a question asked about that. That's not relevant to our specific situation, but the economics of an in-state gas pipeline running down to South Central Alaska, providing 0.5 BCF a day, are attractive enough for all the stakeholders involved to be negotiating in good faith to move that forward and to ensure that there is no interruption in gas availability for South Central Alaska. Can we provide more information on the progress of our federal applications and stuff? The work is ongoing. There's no particular update. I can't provide specific commentary on day-to-day work.
We will update when there is anything significant to update. The data is being gathered, the studies are being done, and applications are being prepared. There was some questions about the vendor financing. I think I've talked about that. Just to be very clear, yes, we are currently in negotiations with only one company. We were discussing with two, now we're discussing with one. There's no hiding that is what we said. I hope the question about whether the update at the end of March on financing was substantive or not. I'm sure we can discuss what the word substantive means over a beer sometime.
We do believe that it was significant in being able to demonstrate that both from our side and from the other side of the discussion there was a meeting of minds on the outline of an agreement, and now we're working both with the commercial stakeholders and the political stakeholders to turn that into something that works. Jay-
Can I make one-
Yeah.
Can I make one comment?
Yeah.
From the subsurface point of view, the discussions with the state on the gas has moved gas from a liability to an asset, which was, you know, highlighted in the first slide. It has massive impact in terms of our valuations and things like that. You know, when you talk about Ahpun, we can start talking about, you know, two billion barrels oil equivalent, where in the past, you know, handling 5 TCF of gas, you know, with just injection. Which is what our models still do, which is what we're still doing. It just fundamentally changes the whole dynamic of our project.
Thanks, Bob. Jay, maybe you can talk about how we would complete wells, because while you may not have as massive a completion, maybe you can talk a little bit about that.
Yeah. The question was about, since we've talked about the Kodiak West up dip and the Ahpun East top set are conventional, how would we complete them? We likely would drill either highly deviated wells, maybe partially horizontal wells. The questioner said, would we need to put as large a frack on them? The answer to that is no. They are conventional reservoirs. I would say that even in the conventional reservoirs that the legacy producers are completing, they do small fracs on those to clean up around the wellbore. How large a frack we'd put on, we would decide once we had taken logs and sidewall cores and whole cores, exactly how big a completion we needed.
Thanks, Jay. Bob, maybe you can talk a little bit about the process that Netherland and Sewell conducted. The question was, did they make their own maps and do their own petrophysical analysis, et cetera, or did they QC work done by Pantheon? I know there's more of a story there, so go ahead.
The answer to that question is yes and yes. First they did QC the work that we've done, and then they, of course, went out and did their own analysis. Again, our numbers are different than their numbers, but because they've gone out and done their own analysis. One of the critical parts of the story was putting together the analog at Tarn and Meltwater, which was a lot of work with them and our team collecting all that data and going through, and then they do their own analysis on that data and how to use it. There's a lot of work that they do on their own to come up with the results.
Again, the engineers spent a huge amount of time working out the liquids composition of what we're gonna see at the surface, i.e., the oil versus the NGLs and condensate. Again, they did their own methodology for that. Some of the work, you know, is pretty straightforward, you know, making the map, the structure maps and things like that. A lot of that straightforward QC, you know, they would use it, you know, checking on the isopachs and doing some of their own work on the isopachs. Again, you know, some of that's straightforward. But a lot of the interpretive work they did on their own.
Is the upcoming Ahpun Topsets gonna include the Eastern Topsets? The answer is no. That's a separate piece. In any case, the resources in the Eastern Topsets are prospective resources, not contingent resources. As Bob mentioned, 70% geological chance of success, and there'll be no point in spending a great deal of time and effort on an independent expert's report until such time as we've got actual data in the reservoir. That's there. Any plans to tie up with 88 Energy after the Hickory-1 discovery? I think that's premature to be talking about that, and it would require both parties to think they wanted to tie up. Let's wait and see how they get on with testing the upper zone, and then doing their analysis.
I'm sure they'll share that with their shareholders. It's not our job to share 88 Energy's analysis. The upcoming IERs, we've asked both Lee Keeling & Associates and Cawley, Gillespie & Associates to include economics. Yes, it will include an assessment of the commerciality. Are we only aiming to get oil and gas production in 2028? No, we're aiming to get oil and gas production as quickly as possible. What I mentioned earlier was Kodiak certainly is not going to be getting its FID before 2028, and can't be coming into production before it gets its FID. We're working on plans to minimize the cost and minimize the timeframe to maximize the potential for the earliest possible production from our leases.
As that firms up, I'm sure we'll be updating people on the timetable as it begins to firm up. Could the part of the bargaining process with the State of Alaska mean access to TAPS more quickly? No, that's a federal permit. Department of Transportation. Actually, it's a division of the Department of Transportation called PHMSA, P-H-M-S-A, which is the pipeline management agency in that regard. Can we give an overview of the timelines for the gas pipeline? I can only tell you what we understand to be the case, which is that they're aiming for an FID during 2025. The time to build the pipeline is between two and three years.
Today they're trying to get into a position to fund the front-end engineering and design studies in order to be able to go out and to be able to get to their FID. It puts them in a similar timeline to our plans for having gas availability from our fields. How does Pantheon respond to people asking questions about gas being needed to be reinjected in the fields? Gas only needs to be reinjected in the fields in order to store it for preservation for the state. It's not a part of our production strategy. It's not required for that.
Obviously, gas used in gas lift is recycled, so it's not that you use up gas in gas lift. We will be using gas obviously for power generation, for running compression, and drilling and production operations. How much do you think the 2C estimate for Kodiak can improve with further drilling? Bob talked a bit about that. Just to be clear, we're not suggesting that we think that Netherland, Sewell & Associates' assessment is wrong and that we'll show them with further drilling. It is that the basis on which they've assessed the mid case is one form of extrapolation from the data we have. The high case allows for a different form of extrapolation.
Our own analysis suggests that the different form of extrapolation may end up being validated by appraisal, which is why Bob said earlier, our numbers are different from their numbers, because we've come to a different interpretation. It doesn't mean we're unhappy with the work they're doing. In fact, we're pleased to see that conservatism, and how commercial it looks even using that conservatism. Can we access the full extent of the Eastern Topsets from the Megrez location or from locations west of the river? The answer is that our assessment is based when we applied for the acreage, we looked to make sure that we only applied for what could be reached from the west side of the river.
There may well be additional commercial resource potential further to the west. Our view was that the costs of coming all the way down the other side of the Sagavanirktok River and trying to access it meant that there was little likelihood of that being a short-term target, and that we'd have plenty of time to think about what we wanted to do in terms of adding additional acreage. In terms of the probability that the gas deal with the state becomes a reality, Bob was very bullish, and this is important to us. Well, Bob is very bullish. It's important to us that Bob is bullish. I suspect what you meant was that the gas deal might be important to us.
The gas deal would certainly help us, but it's not the only basis on which we're able to move forward and develop these assets. My experience is that when you've got two parties who are motivated to do a deal because it's in their mutual interest to do so, and the backstop for one of those parties is either coal, diesel or expensive LNG imports, it would surprise me if we didn't succeed in doing a deal. Our interest is in making sure that we deliver the maximum value to the state in terms of access to gas at affordable terms. We are certainly open to the proposals that have been made to us, and vice versa. I'm optimistic on that.
Would I move all the way from optimistic up to bullish? No, I'll leave bullish to Bob. I'll retain my stance as merely optimistic at that, at this stage. Any updates on main board and U.S. listing? I think rather than getting into the U.S. listing today, we've always made clear that our process is aimed at a U.S. listing in around the end of the first quarter of 2025, so around a year from now. That the basis for moving forward is to ensure that we minimize any potential friction, particularly tax friction for investors from wherever they are.
It's highly unlikely that we would end up still listed on the AIM, as a dual listing is possible that would be listed on the London Stock Exchange, and as I think Justin has responded to various people, you know, many of us are shareholders with U.K. held shares. We're certainly not going to be precipitous in the move. I think over the next couple of months, we'll be able to do a webinar that gets into the process in more detail. We hope to shortly share with you who is gonna be our investment bank helping us through the process, and a more detailed outline on the process.
Isn't the basic plan we don't need the state and this is just upside? The answer is, of course we need the state and the state needs us, in so far as there are a number of appraisal approvals we require from the state, and we are regulated by the state. The economics of the oil development do not rely upon a gas project, which I think is really what that question was about. If this happens, yes, it's fabulous upside, but it's not, it doesn't yet form any part of our planning basis to assume that we do a deal. We include all the injection wells that we might otherwise have expected until such time as we don't.
Someone said, "Has the exposure of the Pantheon story in the U.S. prompted meetings?" The answer is we were meeting with U.S. investors before, and we will continue meeting with U.S. investors, but there's no doubt at all that this, the higher profile has meant that we're talking with more people than otherwise we might have done. Mark, you seem to have deleted some of the questions. I'll try and remember some of the ones that you deleted. How do we feel about progress? We feel good about progress.
We've said to you six and nine months ago, we said an awful lot of what we do over the course of the next two, three, four years is going to be the hard yards. It's the blocking and tackling, to use an American football analogy. It's not gonna be sexy and a lot of it isn't gonna be public, but it's all moving us forward to the point at which we've got a substantial development project and we're bringing it on production. We feel good that we are doing the work that needs to be done and that we're making forward progress. Someone asked earlier how we'd grade ourselves. I think we're hard graders on ourselves.
We'd give ourselves and could do better in every regard right up until we deliver the final result. The vendor financing discussions are specific to buying goods and services from people regardless of whether they're related to oil, gas or other development. Offtake of financing is related to production streams. How does the size of Pantheon's fields compare to global? Well, I think a lot of you are aware of the size of what we've said and can. I can't believe I'm about to recommend Wikipedia to you, but Wikipedia has a very good list of large oil fields around the world, and you can see how we compare.
Do we expect equity and debt financing to be needed? How does this relate to the U.S. listing? Well, we've said we would definitely be doing a raise with the U.S. listing because that's, there's a minimum level of raise that you need to do in order to have an immediate uplist. We are in terms of the overall costs of getting to cash flow self-sufficiency. We don't have any update on the numbers we've shared with you previously. What is provided by debt won't be provided by equity and vice versa. Our friend in Huddersfield says his divorce is getting closer, and our price is rising. He's not sure which he's most excited about.
We're excited for you if your relationship means that divorce is the right choice. The EURs and IRRs look spectacular. I couldn't tell you how the returns compare to other operators. That's for them to share their numbers with you. We think they look spectacular as well in the sense of they show that you've got very robust incremental drilling costs. If you wanted to come up with a post federal tax calculation, you could just knock off 21% from those values. They're still incredibly attractive. These wells are expected to pay back their costs in around 12 months or less.
That's the reason that the model just maxes out and says rate of return higher than 100%. Once you get above 100%, actually, the calculation becomes slightly meaningless because artifacts of the calculation can affect it. Are there other companies who could supply gas to the proposed pipeline? How close are they to the proposed route? The answer is that the proposed route runs from Deadhorse down to Nikiski. That means basically anyone with gas on the North Slope is in a position to supply gas.
In terms of at what timing and cost they could provide it, we are, as far as I'm aware, the only people who have easy access to infrastructure without the requirement for some kind of gas preconditioning to remove the carbon dioxide. Certainly we have a competitive advantage in terms of being further down the pipe. Why are the Upper Basin Floor Fan and the Kuparuk on the back burners? Well, the Kuparuk's on the back burner because it's relatively speaking a more expensive drill. It was slightly overpressured, which has implications. It may well long-term be an attractive reservoir, but there's certainly nothing to be lost.
It's not going anywhere, I think, would be the way I describe it. In terms of the Upper Basin Floor Fan, we expect to get more information as we drill. But again, it's not something that we need to appraise right now. If we drill development wells in Kodiak, and we encounter an area where the Upper Basin Floor Fan is well enough developed to complete it in its own right, we will. In that regard, there's nothing to be gained by spending money on further appraisal of the Upper Basin Floor Fan right now. Hang on. Let's just see. What, how much of the GBP 50 million? Oh, Justin, just to confirm, is it GBP 27 million is what's outstanding?
Yeah, a little bit below GBP 27 million, David. That's correct.
Once the IARs are received, we publish the full IER as received. I know people have said that they were hoping for a beefier document from Netherland, Sewell. We put on the website the letter with it, with its schedules as sent to us. We typically don't think it's worth spending a lot of money to have an independent report that regurgitates all of the nice colored charts and stuff that you gave to them back into it to bulk it out. We are, you know, the money's better spent elsewhere. We will publish everything that we receive from Lee Keeling and everything we receive from Cawley, Gillespie in whatever form.
Again, we have not asked them to do a big marketing document. We've asked them to do an analysis that is used for helping people understand the value of the assets, for partnership and potential funding. What would our potential share price be? That's not something we're in a position to answer. We've told you what our target is, which is to demonstrate the sustainability of a GBP 5-GBP 10 per barrel value of the established recovery or expected ultimate recovery. What that means for investors is for them to make a decision. Someone asked about helium.
I think yes, you did arrive late, and we talked about helium as being an option that we were obliged to disclose now that there was talk of the helium actually being potentially brought to market rather than reinjected. We don't know in what concentrations it's there. All we know is that it was detected during the Theta West well. We're progressing multiple strategies for funding, whoever asked that. I think that is it, Mark. With that, thank you all for participating, and I'll hand it over to Mark for final.
That's very kind of you, David. Thank you. Thank you once again to everybody for your engagement this afternoon. David, Bob, Jay, Justin, thank you also for your time. David, I'll shortly redirect everybody on the call to give you their feedback, their thoughts, their expectations. I just wondered, before doing so, just a couple of quick closing comments, and then, as I say, I'll send investors to give you some feedback.
In terms of where we've come from and where we're going to, I think you'll see that we've not made any transformational changes. We've simply refocused the strategy, tightened our focus on what it is that we're doing. We're moving it forward. We're sorry if we're not exciting enough for some people.
We think there's a lot going on over the coming months, with the delivery of the additional independent reports, with progress on financing with what we've talked about on the gas, with our neighbors test result, and beginning to plan, subject to funding for an exploration well on the eastern Topsets, in what would be potentially bringing up into a total of one billion barrels, recoverable, and appraising with a view to pushing the numbers up on Kodiak. We thank you for having joined us for the ride so far. We hope you'll stay with us. Certainly, we all remain absolutely committed and focused to delivering our strategy.
That's great. David, Jay, Bob, Justin, thank you once again for your time this afternoon. Could I please ask investors not to close this session, as we'll now automatically redirect you for the opportunity to provide your feedback in order that the company can better understand your views and expectations. This only 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 PLC, we'd like to thank you for attending today's presentation, and good afternoon to you all.