Pantheon Resources Plc (PANR) Earnings Call Transcript & Summary

Good afternoon, ladies and gentlemen, and welcome to the Pantheon Resources Plc investor presentation. [Operator Instructions] Given the significant attendance on today's call, the company will not be able to answer every question received during the meeting itself. However, the company can review your 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. And 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 and give you an opportunity to read it maybe later. The presentation has been posted to the website, so it's all there. So onward business. Today, we're going to be sharing 6 things with you. First, we're going to tell you about the first of 2 independent expert reports covering the 2 horizons within the Ahpun field that have so far been flow tested successfully, are going to, one, be delivered imminently from Lee Keeling & Associates on the Alkaid zone; and the second from Cawley Gillespie, on the top sets -- the western top sets 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 in -- 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 top set reservoirs for storage and found that, that is feasible. The second thing we're going to share is the most recent resource estimates from Netherland, Sewell & Associates updating their report on Kodiak to include the new updip acreage acquired in the recent bidding round. This is going to confirm a best estimate of 1.2 billion barrels of marketable liquids and around 5.5 trillion cubic feet of natural gas. Third, we're going to share the results of SLBs dynamic modeling of the Ahpun top sets 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 top sets in the Alkaid-2 well. This is going to demonstrate EURs per well, expected ultimate recoveries per well, of 3.7 million barrels of marketable liquids and 8 billion cubic feet of gas. And 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 top sets 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 #1 well location where our planning basis is, for the time, being 3.65 million barrels of marketable liquids. And also at an updip planning up 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. So the analysis that we'll be sharing with you supports our belief that Kodiak's resources can be developed economically. The pretax economics on each of these wells type curves has been run at between $60 and $90 per barrel of ANS, and we'll be sharing with you. But the headline is that in all circumstances, the individual wells, on a marginal basis, deliver more than 100% rates of return. The fourth thing we're going to share with you is the work we've done on the eastern top sets of Ahpun. That's the next cycle of top sets across, 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, but we'll be going into more detail on that. The fifth thing we're going to explain to you is the importance of the announcement that we, in AGDC, agreed 2 weeks ago about the proposed agreement on natural gas and how it ties into our funding strategy. I'm going to hold my hands up, figuratively rather than literally, and say we could have done a better job on being 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 nonequity funding at Pantheon's Ahpun and Kodiak developments. The final thing and sixth is we're going to explain the basis on which we disclosed the helium potential identified in the Kodiak field. It lies between 2 radioactive shales, the HRZ and the [ Hugh ]. And 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 are sharing with you. We're doing everything we can to accelerate vendor 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 2 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 top sets, the shelf margin deltaic horizons as was and on the Alkaid zone. It does not include anything for the upper and lower slope fans. Secondly, Kodiak constitutes everything between the HRC 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 discovery that was made in the Talitha well, again, not included in any resource estimate. So hopefully, that clarifies for everyone what we're talking about when we talk about Ahpun, we're talking about the top sets, the Alkaid zone, and we're talking about Kodiak, the lower basin floor fan. With that, I'm going to hand over to Jay.

Okay. So we have 2 independent expert reports that we've talked about, Cawley Gillespie & Associates work is underway on the Ahpun field, as David said. And Lee Keeling and Associates, who did an original independent expert report on the Alkaid zone back in January of 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. And we've done this on a single well basis for the Ahpun field top sets, and we'll show you a layer cake model later in the presentation on that. We have used 3.5 million barrels of 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. And 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. And 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 -- they did it with a 10,000-foot lateral. You can see the frac height and links that we've assumed with a cluster efficiency of 80%. And we have capped liquid rates, so that's both oil and water, at 5,000 stock tank barrels a day. And we've capped the gas rate at 10,000 Mcf per day. You can see they did Monte-Carlo analysis with the oil EURs having a range of [ 1.1 to 5.6 MMSTB ] and the NGLs [ 0.5 to 1.3 MMSTB ] with gas basically 5 Bcf to 14 Bcf. But the best case yields 2.9 million stock tank barrels of oil and 800,000 stock tank barrels of gas, I mean, condensates and liquids and 8 Bcf of gas. And 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 in an ANS price of $60, $70, $80 and $90, and you can see the assumptions down below. We have $7.50 in transportation. We've got one injection well for every 3 producing wells. We assumed $17 million for a production well and $15 million for an injection well. And then $50 million for a payout, including facilities. And we have state profits, and this is without federal income tax. But you can see the NPVs and the IRR is obviously greater than 100, but the NPVs are incredible for these investments. So when you add the well cost for the injectors and the cost per well per pad, you've got [ 1 to 1 to 6 to 1 ] of NPV to investment on the mid-case [ 3 6 5, ] something a little less than that for Ahpun top sets. And you can see over on the right-hand side, the Kodiak updip, incredible return on those wells. These are hugely economic wells under any scenario of $60 a barrel ANS, and we know that ANS trades for something close to Brent. The Ahpun field, the Eastern top sets, I'm going to turn it over to Bob to talk you through our best estimate of the Ahpun fields Eastern top set reservoirs.

Hello, everyone, and thanks for joining the -- this presentation and this webinar. So yes, first, I'm going to take you through our recent evaluation of the eastern top set. And you can see now that our best estimates are circa 600 million barrels of marketable liquids recoverable. That's up from the 300-plus million that we were looking at when we were -- when we first discussed this with you in the past. So slide here, we're going to look at the total Ahpun field. And when we look at the total Ahpun field, which includes the Western top sets 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. So right here is what we picked up in the lease sale. That's the Ahpun top set on the east. Our total sort of best estimate of contingent and prospective resources over 1 billion barrels of marketable liquids. That is a -- 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. And the new resource estimate on the Ahpun top set in the East of 600 million, we mapped this recently. We've got multiple targets. Our geologic chance of success, which I know we were continually asked, we have -- we hit this at about 70% chance of success. When you look at the whole Ahpun infrastructure or the Ahpun field, what is important about this is, of course, that its location next to the pipeline, which is -- we mark that in here, that's the pipeline, right. 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 -- it's easily developed. Do all that. So get rid of that. And the important part of this is on the Ahpun top set is that this is a conventional reservoir. It's younger, shallower than the Ahpun top sets that we've intersected at pipeline state. We have sidewall cores at pipeline state that indicate that the reservoir quality is going to be something between 20% to 25% in 5 to 35 millidarcies. This is a very good conventional reservoir in the range of what the Nanushuk looks like to the west of us. So what does it look like? This is a 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 top sets 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 the -- 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 sidewall cores, and we have a sidewall core that has permeabilities of 35 millidarcies. This is -- again, this is a very much a conventional reservoir. And remember, we always do the -- what we call the seismic attribute analysis. This is the work done by Roger Young and his team at [ ESI ]. And every single time when we've tested using this approach, we have found light oil. The multiple targets that you see in the Ahpun top set and the east there, all those things light up and are telling us that we have light oil in those reservoirs. The other thing is, 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 and where we can drill -- we could spin it there and test across the Sag River and go in and test these zones here. So we're going to hit, we're going to try -- we're going to hit all the targets that we can map in -- with this one well. Of course, I want to emphasize that this is just the top set 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, label TS1, 2, 3. Those are -- each of those zones have been mapped, and you can see the acreage outlines on that. And the total estimate on this is 609 million barrels of recoverable liquids. And net to us, it would be about 527 million barrels. So that's after taking out all the revenue for the state. So next. Now on to Netherland and Sewell. Netherland and 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 are -- that we've acquired in the last lease sale. Again, this is the NSAI disclaimer. You can read that at your convenience. And this is the actual table that they've put out. The numbers, I can only say they speak for themselves. It's 1.2 billion barrels. The best case C2 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. And that is because -- so these numbers have moved because what we've been able to identify and what they've concurred is that as we move updip, less Dmax, we're going to encounter better reservoirs and there's a portion of these reservoirs that are going to be conventional reservoirs. And 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 updip, which is where the porosities are 12% and more importantly, where the permeability, the average porosities are 12% and average permeabilities are 0.1 millidarcy. Again, I want to emphasize, those numbers are average. That means -- that means we can expect to see better than that in this portion of the field. That updip, which starts sort of right here, if that marker right here and goes updip in that direction over here. All of that, that's over 40,000 acres of reservoir that would be considered having average of being considered a conventional reservoir. Why is that important? It's important because, as Jay showed, we're going to get better EURs. We're also going to get much higher recoveries. As a matter of fact, we -- in that area, updip there, we are almost double the recovery factors that we have around Theta West, which means that how we would develop this and what our EURs are significantly improved. These are the actual numbers that they used. So one of the things you'll see here is the reference to Tarn and Meltwater, which was the analog that we thought and they agreed was the closest analog to what we have at Kodiak. They modified some of the Tarn numbers because of a 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 on -- is the recovery factor that we see here in the high case, is about 30%. So what's important here is when you look at this is we have 1.2 billion barrels already. That's a massive discovery of -- for -- just from the liquids point of view. But 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 updip. In other words, the greater than 0.1 millidarcies. And understanding the distribution of porosities and permeabilities that are greater than that, we'll be able to move our numbers from the 1.2 billion to the 2.8 billion. So with that, I'm going to turn that back over to Jay and to David.

Natural gas. Thanks a lot for whoever [indiscernible] to unmute me. So natural gas, thanks, Bob, for handing 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 going to talk about the form of the proposed agreement and why we believe that, that is the underpinning for substantial nonequity funding capacity, and we're going to explain to you why the pipeline doesn't require the LNG project to move ahead. There's an in-state phase first. And finally, we'll talk a little bit about the helium opportunity. The proposal that we are discussing is to provide up to 500 million cubic feet per day of methane at a price up to $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 $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. And the terms on which we were 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 time frame in which an LNG project might be added to the initial in-state phase. That in-state phase is for a 42-inch pipeline. It's the pipeline that has already been permitted as well come through to talk about and supported by federal loan guarantees with an estimated cost -- original estimated costs of just under $11 billion rather than the full cost of the project, which was estimated at $45 billion, $46 billion. That, if we had a take-or-pay contract for a minimum 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 the -- for any lender's cover ratio provides up to $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 will produce the oil, and will be durable 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. But 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 and it's 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. And if you don't allow that pressure to drop and for the gas to expand, then you don't get the primary recovery. So it's about gas storage for the long term and 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 will conclude agreements. But I can say that we are in detailed negotiations. And over the coming weeks and couple of months, you'll be hearing more about that, but this is a key underpinning of our ability to mobilize nonequity 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-mile 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. So the remaining cost of that pipeline, say, in the order of $5 billion is supported by the send or pay obligations of the shippers of gas through that pipeline, which is supported by the ultimate purchases of the gas. And the state is very committed. You heard Governor Dan Levy 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 -- for sure, for the initial in-state portion of the project. And of course, having the pipeline built enhances the attractiveness and economics of a subsequent LNG development, and 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 are 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. And 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 the -- we talked previously about being in negotiations with two. We've homed in on the one that we think is the best option. And we will, doubtless, be in a position to announce something in the time frame we originally talked about. But as I said at the start, I held 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 financing and vendor financing and some combination of the two. We talked about how, if everything came off, it might exceed the $120 million to $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. And 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. So I want to summarize. In the end, our strategy remains unchanged. It is to achieve sustainable market recognition of $5 to $10 per barrel by the end of 2028. And that's the time frame in which we expect to be getting to FID on Kodiak. Hopefully, we'll have being able to get Ahpun up and producing sufficient to deliver cash flow for funding the continuing CapEx. But 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 top sets. 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 Netherlands Sewell updated report. We've had SLBs single-well modeling, and they're now working on the full field modeling to support our FID and regulatory applications. And we're expecting the Ahpun Alkaid zone estimate imminently, and Cawley Gillespie's estimate on the top set to be released in the not-too-distant future, but shortly after that. So with that, Mark, I'm going to turn it back to you for Q&A.

[Operator Instructions] That's very kind. David, Jay, Bob, Justin, thank you very much indeed for updating investors, gentlemen. Please do continue to submit your questions. [Operator Instructions] But 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 meeting company dashboard. But 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 attendance today, which is very significant. If I may just hand back to you just to moderate through that Q&A where possible, take those questions and give a response where it's appropriate to do so.

Certainly. Thanks. So 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. But as soon as we had a potential market for natural gas that would cause the helium to be producible, we consider that to be price-sensitive nonpublic 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?

Yes. 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 fundraising since they've come in as an investor, including the original transaction where they came in and lent us money. Look, they lent $50 million unsecured. It wasn't -- they're not an equity holder. They're a lender. And they obviously need to manage their risk at their core competency. We've known that all along. And I've got to safety 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. And whenever we've asked the question, they've always been very forthcoming and showing us that information. So ultimately, this bond, just so everybody understands, for the terms of Pantheon, we issue -- we borrowed $50 million. We paid that back over 5 years quarterly. So it's $2.5 million per quarter plus the interest. The interest is accruing at 4% coupon rates. I mean it's the fantastic terms. We can pay that -- we can meet those payments in cash quarterly, or we can meet through stock. And if we do it through stock, we do it at a 10% discount. So essentially the VWAP of the stock price. So it's not a huge margin. What I would say -- and what I really want to stress is the shareholders is that the bondholder makes their money if the stock really performs, they want to see the stock perform. So today, for example, if we had to repay a bond payment, it would be -- and we did it via stock issued at a 10% discount to the VWAP in the period building up to the payment date. So for example, if the share price was 40p and the VWAP was 40p, we'd make that payment in stock at 36p. Now what it would take you is there was a maximum conversion price, which is where the bondholder makes their money. If our stock price tripled overnight and we made a payment, we'll then -- they would get all of the margin above that price, which is currently at about 91p -- sorry, USD 0.91, to the sterling equivalent of that, a little bit above 70p. So it's not until the stock which is above 70p where they make their real margin. And of course, at that point, we've got many ways of dealing with the bond if we want to minimize our cost of capital. We could go and raise equity if the stock went to GBP 1, which raised equity at GBP 1 and repay the stock. There's many ways we can do it. So yes, I hope that answers the question. So they always manage their position that's the business that they do in the same way 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. So I hope that answers the question, David.

Thanks a lot, Justin. Yes. There's a question, do we expect -- sorry. Do we expect to be drilling in the summer season or the coming winter? Jay, we talked about 4 wells, one in the east and the others in the west. Do you want to quickly talk about potential timing on that?

Sure. Thank you, David.

Yes. If you just leave your microphone is okay and we keep through, David.

Okay. Yes. So it was a 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, 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, Hillcorp continuing to recomplete wells at Prudhoe Bay and Kuparuk. But yes, we could be drilling in the winter. We could do a second well, then after that in the spring or summer time frame. And if we had funding for 2 wells, one in the West, let's say, pipeline state, and one the Megrez well that Bob outlines here, it would be great to be able to do them back to back, and we'd love to do.

I think you meant if we had one in Kodiak to the west, sorry, updip of -- to West. But the -- the answer is, as Jay says, we can drill the eastern well from Megrez 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 off 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 billion cubic feet 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 being prepared. The -- we talked about -- there were some questions about the vendor financing. I think I've talked about that. But just to be very clear, yes, we are currently in negotiations with only one company. The -- we were discussing with 2. Now we're discussing with 1. There's no hiding that, that is what we said. The -- 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. But 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 are working both with the commercial stakeholders and the political stakeholders to turn that into something that works.

Can I -- can I make one comment 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 highlighted in the first slide, and it has massive impact in terms of our valuations and things like that. When you talk about Ahpun, we can start talking about 2 billion barrels of oil equivalent, where in the past, handling 5 million -- 5 trillion cubic feet of gas with just injection, which is what our models still do, which is what we're still doing. But it just fundamentally changes the whole dynamic of our project.

Thanks, Bob. The -- Jay, maybe you can talk about how we would complete wells because while the -- you may not have as massive a completion, maybe you can talk a little bit about that.

So the question was about since we've talked that the Kodiak West updip and the Ahpun East top set are conventional, how would we complete them. And we likely would drill either highly deviated wells, maybe partially horizontal wells. But the questioner said, would we need to put as large a frac on them? And 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, do small fracs on those to clean up around the wellbore. How large a frac we 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 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? But I know there's more of a story there. So go ahead.

So the answer to that question is yes and yes. So first, they did QC the work that we've done. And then they, of course, went out and get their own analysis. And again, our numbers are different than their numbers, but because they've gone out and done their own analysis, they -- one of the critical parts of the story was putting together the analog at torn 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. So there's a lot of work that they do on their own to come up with the results. Again, they spent a huge amount of time. The engineers spent a huge amount of time working out the liquids composition of what we're going to see at the surface, i.e., the oil versus the NGLs and condensate. And again, they did their own methodology for that. So some of the work is pretty straightforward, making the map, the structure maps and things like that. A lot of that straightforward QC, they would use it. Checking on the isopachs and doing some of their own work on the SPAC. Again, some of that's straightforward. But a lot of the interpretive work, they did on their own.

The -- is the upcoming Ahpun top set is going to include the Eastern top sets? The answer is no. That's a separate piece. And in any case, the resources in the Eastern upsets are prospective resources, not contingent resources. As Bob mentioned, 70% geological chance of success, and there will be no point in spending a great deal of time and effort on an independent experts 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, and 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. So 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 maximize and minimize the time frame to maximize the potential for the earliest possible production from our leases. But as that firms up, I'm sure we'll be updating people on the timetable as it begins to firm up. The -- could the part of the bargaining process with State of Alaska mean access to taps more quickly? No, that's a federal permit Department of Transport -- Department of Transport. Actually, it's a division of the Department of Transport called PHMSA, P-H-M-S-A, which is the pipeline management agency in that regard. Can we give an overview of the time lines 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 2 and 3 years. And 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, but it puts them in a similar time line 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 field? 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 estimates 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 Netherlands Sewell's assessment is wrong and that we'll show them with further drilling. It is 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 top set from the Megrez location or from locations west of the river? The answer is that our assessment is based -- when we apply for the acreage, we look 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 cost of coming all the way down the other side of the Sag River and trying to access it meant that there was little likelihood of that being a short-term target and that we'll have plenty of time to think about what we wanted to do in terms of adding additional acreage. The -- in terms of the probability, 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. And so -- but how likely? 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 cold citizens 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 on affordable terms. And we are certainly open to the proposals that have been made to us and vice versa. So I'm optimistic on that. Would I move all the way from optimistic up to bullish? Now I'll leave bullish to Bob. I'll retain my stance as merely optimistic at this stage. Any updates on main board and U.S. listing? I think we run in getting into the U.S. listing today. We've always made clear that we -- 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. The -- but it's highly unlikely that we would end up still listed on the AIM as a dual listing. It's possible that would be listed on the London Stock Exchange. And as I think Justin has responded to various people, the -- many of us are shareholders with U.K. held shares. So we're certainly not going to be precipitous in the move. But 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 going to be our investment bank helping us through the process and a more detailed outline on the process. The -- 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 insofar as there are a number of approvals we require from the state, and we are regulated by the state. But the economics of the oil development do not rely upon a gas project, which I think is really what that question was about. And 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. And so we include all the injection wells that we might otherwise have expected until such time as we don't. The -- 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 the 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. The -- Mark, you seem to have deleted some of the questions. I'll try and remember some of the ones that you deleted. Has -- how do we feel about progress? We feel good about progress. But we've said to you 6 and 9 months ago, we said an awful lot of what we do over the course of the next 2, 3, 4 years is going to be the hard yards. It's the blocking and tackling, to use an American football analogy. It's not going to be sexy, and a lot of it isn't going to 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. And so 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 grade ourselves. I think we're hard graders on ourselves. I would 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 and gas or other development offtake of financing is related to production streams. The -- how do we -- how does the size of Pantheon's fields compared to global? Well, I think a lot of you are aware of the size of what we've said, and can I would -- 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 there's a minimum level of raise that you need to do in order to have an immediate uplift. The -- we are, in terms of the overall cost of getting to cash flow self-sufficiency, we don't have any update on the numbers we shared with you previously. And so what is provided by debt won't be provided by equity and vice versa. The -- 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. The -- I couldn't tell you how the returns compared to other operators. They -- that's for them to share their numbers with you. But 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. And that's the reason that the model just maxes out and says a 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. And so that means basically anyone with gas on the North Slope is in a position to supply gas. In terms of what at 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 combo outside. And certainly, we are -- we have a competitive advantage in terms of being further down the pipe. Why are the upper basin floor fan and the park on the back burners? Well, the parks on the back burner because, relatively speaking, a more expensive drill. It was slightly overpressured, which has implications. And 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. And so in that regard, there's nothing to be gained by spending money on further appraisal of the upper basin floor fan right now. The -- hang on, let's just see. What -- how much of the $50 million -- Justin, just to confirm, is it $27 million is what's outstanding?

Yes, a little bit below $27 million, David. That's correct.

Yes. Once the IERs are received, so we published 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 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 in to bulk it out. We are -- the money is spent elsewhere. We will publish everything that we receive from Lee Keeling and everything we received from Cawley Gillespie in whatever form. But 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. The -- 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 $5 to $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. But 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. And I think that is it, Mark. So with that, thank you all for participating, and I'll hand it over to Mark for final...

That's right, David, thank you, and 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 or expectations, but I just wondered before doing so, just a couple of quick closing comments. And then, as I say, as investors to give you some feedback.

So 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 have simply refocused the strategy, tightened our focus on what it is that we're doing, and 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 reports with progress on financing with what we've talked about on the gas with our neighbor's test result and beginning to plan subject to funding for an exploration well on the eastern top sets in what would be potentially bringing upon to a total of 1 billion barrels recoverable and appraising with a view to pushing the numbers up on Kodiak. So we thank you for having joined us for the ride so far. We hope you'll stay with us. Certainly, we will 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. Can we please ask investors not to close the session? 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 will only take a few moments to complete, but I'm sure it will be greatly valued by the company. On behalf of the management team of Pantheon Resources plc, I would like to thank you for attending today's presentation, and good afternoon to you all.