Good afternoon, ladies and gentlemen. Welcome to the Pantheon Resources plc post AGM investor presentation. Throughout this recorded meeting, attendees 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. Just simply type in your questions at any time and press send. The company may not be in a position to answer every question received during today's meeting. However, the company can review all questions, and we'll publish those responses where it's appropriate to do so. I'd now like to hand over to Executive Chairman David Hobbs. Good afternoon.
Thanks very much indeed, Mark, and thank you everyone for joining us here on the webinar today. We've just completed the formal business of the AGM, in which all the resolutions were approved. We also a few minutes ago released an RNS confirming that those resolutions had been approved and sharing with you some information that we'll be presenting in the webinar. I would invite you to review that at your leisure afterwards, and we'll be posting the presentation to our website. In fact, we may have already done so. Someone's nodding at me, so it means it has already been put on our website. Joining me today in person, Justin Hondris, and virtually Jay Cheatham and Bob Rosenthal.
We'll be running through a number of things to give you an update on where we're at in terms of moving forward to achieving our stated strategic goal of achieving a recognition of $5-$10 per barrel of recoverable oil. I would invite you, please, to review the disclaimer. Again, do feel able to read it in the posted version in due course. What I can see is that when Bob was practicing how to use arrows, there we go, they remained on screen. This is obviously just a reminder of what we've got and what we're gonna be talking about.
To the west, you can see the thin outline of the new acreage that we acquired in December, which is the up-dip extension of Kodiak. To the east, you can see the blue line, which again, is the easterly extension of our pool, and we'll be talking in more depth about that. I want to use this as the backdrop to give you a quick review of what we achieved in the last, well, effectively 18 months. The year that we've reported and just had the AGM for and the subsequent events. Of course, the biggest event in that period was the long-term test of the Alkaid-2 well.
What we have come to realize as we've done the analysis and subsequent work is that that will turn out to be a pivotal moment for the company in the sense that it provided the data that satisfied us that we have economically developable resources that we should be moving forward into development. That was the reason for the pivot of the strategy that we announced in the middle of last year just before our financial year end that we were going to be moving forward with all speed towards bringing our resources online. That we would cost what it would take to get there, and we would develop a funding strategy that sought to bring us into production and then to financial self-sufficiency at minimum dilution to shareholders.
The commitment to that, I've said it before, I'll say it again. There were two ways I personally could have played this. I could have waited till we were trying to issue a lot of equity and bought in whatever price that would be having not sought to protect shareholders. Or I could buy shares and make sure that I was aligned with you effectively, like the Greeks on the shores of Troy. Burn the boats, it'll stiffen the sinew somewhat and make sure that when we talk the talk, we're also rather incentivized to walk the walk. That's absolutely what we're intending to do. And we will in due course be sharing news with you about that.
Subsequent to the result of that well, where we don't need to retread history. Needless to say, it was not viewed favorably by the market at the time. A lot has gone on since then in terms of retooling the company and rebuilding the governance that would allow us to have the underpinnings in order to achieve the financing that we require. Today, we're in a lot better shape, and that's in part because of our subsequent recompletion of the Alkaid-2 well to test what are the topsets. You'll have heard lots of different words to describe the different formations. If we can leave you with one message today, it is there are two large fields.
One is called Ahpun, and it's got some formations in it, and the other one's called Kodiak, and it's got some formations in it. Bob and his technical team are much better at understanding and describing and explaining those technical things than there is any chance of anyone around this table or anyone else in this room being able to better understand. There are multiple formations laid down in multiple events. At the end of the day, what we've got is a set of what are called topsets. Bob will talk a little bit more about that, which is the predominant resource in the Ahpun field.
You've got a Basin-Floor Fan, which is the predominant resource in the Kodiak field. At the end of the day, we're developing these as two fields that will be engaging with the State of Alaska, are engaging with the State of Alaska about two areas, one called Ahpun, one called Kodiak. All the other names that you've heard, well names, unit names, formation names, whatever, we will try to avoid confusing you with lots of different things to try and reconstruct some kind of mental model. Because at the end of the day, what you need to know is that Netherland, Sewell have evaluated Kodiak prior to the new acreage, and we are hoping for by the end of the first quarter, an updated report that incorporates that new acreage.
Their evaluation was just shy of a billion barrels of recoverable marketable liquids, and they are working on a similar report for Ahpun. The company's estimate, you'll recall for that set of formations is 481. An oddly specific number, but 481 million barrels of recoverable liquids. We will hope to have an updated report on that by the middle of the year, which will be based on the full development plan that we've been working with SLB and then with Netherland Sewell. Those are the key things to remember. The critical thing for us was that subsequent recompletion of the Alkaid well, which allowed us to test the formation that is the predominant resource within Ahpun.
What we found, and we'll share with you in a bit, has led to our ability to now reforecast what the development looks like. Jay will be sharing that with you shortly when we get that far. Let's just move into what really matters. As I say, the review of the year, you can read the annual report, and it would be more informative than me trying to re-narrate it for you. We recompleted the Alkaid- 2 well I mentioned. We acquired the new acreage, and that now genuinely completes our acreage acquisition. We have always thought that the up-dip most westerly portions of Kodiak would be where the best reservoir was.
You can understand why, for obvious reasons, we couldn't go and apply for the furthest west bit and leave a crack in between that we didn't go for. We had to play a sophisticated game over the course of the last few years of gradually expanding, in order to avoid a situation in which people were competing with us. From our point of view, we've managed to complete that before the seismic that it was all founded upon becomes public. Next year will be the first release of the proprietary 3D seismic, which would be the point at which we would no longer have that competitive advantage. That's the reason that we moved as we did, in order to tie up the entirety of the resource.
Similarly, as Bob's gonna talk to you, the eastern extension of Ahpun also has better reservoir qualities by our analysis, and he'll explain more about that. We have strengthened the board of directors, and I'll talk through that in more depth. We also looked at some of the key elements of governance in order to make sure that we are ticking the right boxes, that we're not in any way excluding those who might invest in the company on the basis of what may appear arbitrary requirements that they would have. We announced during the second half of last year that we were examining the benefits of the U.S. listing. We completed that work.
We have now a base plan, which is that we will be listing on one of the major U.S. exchanges, either the NYSE or the Nasdaq. Most likely the Nasdaq, because that's from a regulatory perspective, the easiest to do. We intend in an interim period to retain a U.K. listing, likely not to be an AIM listing, but a full main board listing. And that's in order not to disadvantage U.K. shareholders who are holding shares in tax-efficient wrappers. We don't want to force you to take your shares out of those wrappers. There will be a period, but in the long run, we will probably be solely listed on a U.S. exchange. And we have, I'll come back to talk a little bit more about that.
Finally, we're gonna share with you our progress towards the planning, funding, and permitting of the Ahpun development. With that, let me hand it over to Jay just to talk through some of the specifics and the new data gathered from the Alkaid -2 recompletion. Jay, over to you.
Well, thanks, David, and hello to everyone, whether it's in the afternoon in the U.K., in the morning in the U.S. or in the evening in Asia. We did, as David said, we recompleted the Alkaid- 2 well in the vertical portion in that upper topset. We previously called that the Shelf Margin Deltaic. This is the market update that we promised everyone after we had done our pressure bomb analysis that we put in after the frack and the test and the work done by GeoMark on the recombination. There are two key takeaways. The recompletion, we originally said that we had 30-100 barrels per day of oil.
When we get the GeoMark data and add in the C5+. It's 20-40 barrels a day higher, so our actual marketable liquids were between 50 and 140 barrels per day. More importantly, though, our topsets permeability. Permeability is strictly a measure of the ability of reservoir fluids to move through the rock. It's at least two orders of magnitude, which means it's more than 100x better than our Alkaid zone of interest. Permeability is directly related to production rates. Now, we also have a lot of technical data. Our pressure volume temperature data, PVT, it's 35 degree API oil. That's very important 'cause it's not nice, light, sweet oil. The gas is even richer than the gas that we found in the lower zone.
162 barrels per MMCF of C5+ versus 98. We'd also promised the, you know, the evaluation of our revised frack, and we see that we were about 50% of frack efficiency versus about 20% in the Alkaid zone of interest. We think we can probably drive that even higher. Our initial reservoir pressure just under 3,500 PSIG, and a bubble point at 3,500. We're right at the bubble point, and that's the pressure where the liquids start coming out of the gas solution. A bonus result, as we like to call it, is that we had negative skin. Now, if you have positive skin, it means that you're restricting the flow into the wellbore. We had significant negative skin, so it's a very much improved permeability in the wellbore.
As we said, you know, this well is in the extreme northeast portion of these topsets, and Bob's gonna talk and show you about that. I'm gonna turn it over to Bob next, for to talk about the new acreage.
Thanks, Jay. Hello, everyone. I hope you can hear me. What you're looking at here is a AVO display, going through our pipeline state well, through one of the targeted locations called Megrez. This is a permitted location that's west of the Haul Road and into our new acreage, this eastern extension of our Ahpun. I'm gonna focus on just the top set here. Here we have. That's the Ahpun top set anomaly that was called the SMD in the past. We've talked about this in great detail in the past. The depth here is at about 7,200 ft, and the Dmax is about, and we've talked about what Dmax is in the past, which is maximum depth of burial, which is the.
There's been about 3,000 ft of uplift over here. When we go over to Ahpun East into the topsets, and you can see the white circle is showing you where we see these reservoirs present and probably hydrocarbon-bearing. We are at a Dmax of 8,600 ft and at about a drilling depth of about 6,000 ft subsurface. Now, when we're doing this, when we look at this, and we've looked at all the well data and wells that we've drilled and other people have drilled in the area, the porosities that we expect in this portion of the reservoir is between 15% and 25% porosity and 5 mD-20 mD. This is, you know, this is an excellent reservoir.
As Jay said, one of the things that was highlighted here was we've tested the topset play at Alkaid- 2, so we've actually tested at Alkaid- 2 light oil. This was at the very feather edge of the Ahpun topset play. As a matter of fact, when we originally drilled the well, we were predicting very thin reservoir there, and that's what we saw. We were able to test it and we got, you know, a really good result. What's the takeaway across the board for the Ahpun new acreage that we picked up to the east? One, we have excellent porosities and permeabilities. We know this is a large structural stratigraphic trap. It is the structural component gives us an excellent focus for migration of oil.
We're sitting on peak oil generation for the source rock. The topsets, this play here on this acreage, we have multiple stacked targets, not just in space, but on top of each other in this play, in this area. We can develop this from the Dalton Highway. It's known light oil. Alkaid- 2 had a flow test, and we have the results from GeoMark. We have not changed our resource estimate. It's still about 1.8 billion barrels of liquid hydrocarbons in place. So that's our total resource there. We have multiple additional targets in the slope and basin floor fans, and they are under evaluation for their resource as well.
Before I turn it over to David again, I just wanna point out that on the Kodiak, so here's the new acreage that we picked up for the Kodiak anomaly at this time. We're now showing you the total extent of the field that we have at Kodiak. Everything in this acreage to the west of Theta West is up dip, and we're expecting significantly better reservoir than what we've seen at Theta West, and that's being evaluated right now with Netherland Sewell. With that, I'll turn it over to David.
I don't know if Mark had just muted me. I wanted to ask you or to reflect back to you the work that we've been doing over the last month, and the key part of the update is therefore in as it relates to the eastern acreage, that it's not volumetric. It is in terms of our assessment of the quality of the reservoir that we would anticipate in that in those top sets in the eastern extension of our point. Is that right?
That is absolutely correct.
The reason that that's important is clearly in terms of likely recovery factor and likely flow rates of successful wells into those top sets. That is taking it an order of magnitude or two, even above what we found from the top set test in the Alkaid- 2 well. If you remember in the Alkaid zone of interest, we were talking about nanodarcy. So that's less than millidarcy, less than microdarcy, to a point where we're talking about about a 10th of a millidarcy in the top sets in the Alkaid- 2, and here we're talking about another one, maybe two orders of magnitude higher still in terms of that eastern extension.
That-
Um.
That's absolutely correct.
Well, David, you know, and we'll show this later, that relates to the new type curves that we have in our development plan. I guess that's where you're headed if-
Mm-hmm.
Four, we now-
Yeah, go on.
4,000 barrels a day, IP 30, and 2 million barrels that are recoverable.
Yes. That's on the basis of what we saw in the Alkaid -2 topsets test. It doesn't even get close to assessing what you might see as the results from the eastern extension. Our new planning basis is not yet invoking anything from the eastern extensions or indeed the uplift western in terms of type curve. We're simply basing it on what we've seen in the Alkaid -2 well that we were able to analyze.
That's-
Thank you, Mark. Go ahead.
That's absolutely correct.
Yeah.
Of course, SLB is incorporating that into their new modeling.
Yeah. I said to you just earlier, you know, we want you to come away recognizing there are three areas that matter here. We've got the entirety of the Kodiak field, which is all a lower Basin-Floor Fan. It's all one continuous accumulation. It will be developed as a single unit area. Right now you'll recall in the past we've had the Alkaid unit, the Talitha unit, and we've had non-unitized leases. We will be seeking in due course to incorporate into the Kodiak unit, and we'll get rid of the confusing terminology about is Talitha a well, is it a unit? Is Alkaid a well, a unit, a formation, et cetera? We want to simplify so it's easy to understand.
You've got a tank which is Kodiak, and we will be seeking to unitize that into a single development area. In addition to that, we've got the current definition of Ahpun, the majority of which, in terms of the resources, is here. You can see the red along the bottom. That is the main body of the oil that we tested in the topset up by the Alkaid. It sort of horseshoes round, and it gets better as we move further south.
What we're telling you is, having evaluated the well performance in these topsets, we will be focusing our initial development into the main body of the topsets in Ahpun, which is why we're envisaging higher initial flow rates and the revised production projections and cash flow projections that we're gonna be showing you at the end of this. Finally, the eastern addition, that next cycle of topsets across the majority of which sits within our acreage, accessible from west of the Dalton Highway, so all part of the same development. The initial well, you can see that green dot, Megrez. That's where we would probably drill the initial well that would allow us to demonstrate the producibility of those topsets.
This area and the other area of Ahpun together will be unitized into the Ahpun development. Then, as I said, the Kodiak will be the other area. We will seek to have all our licenses unitized into those developments. We'll be moving forward with approvals on initially Ahpun, with a view to final investment decision end of 2025. Then Kodiak following some further appraisal with a FID in late 2028. Okay. I talked about new board members. We've announced both Allegra and Linda in previous stock exchange announcements. You're familiar with their background.
What I can tell you is that now that we have three independent non-executive directors, obviously Jeremy Brest came onto the board as a designee of Farallon and the Great Bear shareholders, that's now dissolved. That effectively Jeremy is there in his own right as a fully functioning independent member of the board. Allegra and Linda means that we have more oversight than we've had in the past, where we've only ever had a chairman and one other non-executive director over the last several years. That allows us to hopefully build confidence among investors that every decision is being taken with a view to achieving and driving our long-term strategy.
We have, as a result of having a fuller complement on the board, the board committees, which historically were effectively all the same people on the board, different people chairing those committees, now have the opportunity to begin to take on personalities of their own, and to focus in hard on the issues that match them. Linda comes from a long and storied background as a CFO of both public and large private companies, and has taken over as the chair of the Finance, Audit and Risk Committee. She will be really focused on the program that drives us towards having the kind of controls that we need in order to be Sarbanes-Oxley compliant and to be able to operate seamlessly and efficiently as a U.S.-listed company.
It will also, she'll be able to bring expertise in how to close the books quicker. American companies typically close their books quicker than U.K. companies. There are a number of steps that requires. Sometimes it's just a shift in terms of how one thinks about it, how much work is done before you get to the year-end in order to be further along. She'll be working with Justin on making sure that we have a process that will shorten the timeframe. This year we were earlier than last year. Next year we'll be earlier than this year along the way. We have asked Tony Larkin to join the team to lead the U.S. listing transition.
Tony is sitting quietly at the back of the room, and I'm sure will be happy to talk to anyone afterwards. Tony will be project managing and leading that whole process 'cause it's multidisciplinary. It requires all of us to have our butts kicked to make sure that we're staying on track on what is now a 14.25-month process. Because we're aiming by the end of the first quarter of 2025 to be in a position where we can be listed on the U.S. exchange. Jeremy Brest has taken on chairmanship of the Remuneration Committee. You saw some early results from that, one of which was the termination of a historical incentive plan, which was designed for a different time and a different company.
We are in the process of replacing the old remuneration plans with a single omnibus plan that is consistent with market practice. As we move to a U.S.-listed company, we'll be moving to be compliant and in line with market practice there. The other thing, just as a technical point, is the move to a U.S. listing won't crystallize anything in terms of the termination of one plan and the start of a new. It will be a seamless rollover along the way. We will be in due course announcing grants for this year.
What you'll see is that the main focus of the Remuneration Committee has been in making sure that rewards are aligned to shareholders' requirements so that the vesting conditions for options will be related to value creating events and the value of awards will be related to share price performance so that the team, both the board and management are aligned with shareholders, that it shouldn't be possible for rewards to management that aren't consistent with rewards to shareholders. I will continue to chair the Nominations Committee. Now that we have a board of seven people, that is, we don't need to expand the board anymore. We don't intend to.
Our focus will be on, as we transition to a U.S. listed company, the general makeup of a board in terms of how many members of the executive are members of the board will change, and we may need to reconfigure the board in the listing process. The most important job from my point of view is succession planning for all the key roles. There should be nobody involved in the company who is not expendable, because we will have a good plan for everybody, because that is a key risk factor to the success of the company, is making sure that we've got not only a plan A for every role, but a plan B.
In due course, the needs of the company will change, over time as we move from an exploration and appraisal company to a development company and then to a production company. The skill sets required and the numbers of people in different areas will change. Having a proper succession plan and a proper resourcing plan is critical, for that. One of the things that is mentioned just at the top of this slide, Josh McIntyre, who has historically been our Controller in Alaska, is going to be stepping up to become Group Financial Controller, which will free Justin to be much more focused on the funding, and other parts of the Finance Director role. We'll be strengthening that finance organization, and building the controls around it.
Allegra has taken on the conflicts committee, and that is really no different than it has always been, which is to ensure that we maintain the highest ethical standards, and ensure there are no unknown conflicts of interest, and where there are potential conflicts of interest, that we deal with them in an entirely transparent fashion. An example of that that I'll share, where if not addressed transparently, you could have a potential perceived conflict. When we selected the location for our Houston office, we looked at a number of different locations.
In the end, expanding the office of Proton Green, which is another company that I'm chairman of, provided the lowest cost solution because we didn't need to have a whole bunch of common areas of meeting rooms or sort of non-office areas, so meeting rooms and kitchens and that sort of thing. By being able to double up and share, we were able to save money. In order to ensure that we handled it right, you know, we went through all the governance processes of a related party transaction in order to confirm that it was in the best interest, not only of Pantheon, but obviously I had to do the same thing from the other side for Proton Green, so that it was handled transparently.
In terms of the forward incentive programs, the Remuneration Committee is really focused on looking at the overall package, because we're gonna have to recruit a number of people as we build the organization to be running multiple rigs in parallel, to be running simultaneous development and production operations. We needed to make sure we had a plan that allowed us to recruit and retain good people for the long term. We will have a combination of cash and restricted stock units for management that vest over periods of time, so people have always got unvested rewards in the future that retain them, and a continuing rolling process.
We will ensure that the plan limits are consistent with U.K. market practice today, and then when listed in the U.S. with U.S. listed peers. That's a commitment that we're giving you on that.
Leland, you say they're with relatively spot grading. What does that mean?
A part of typical for U.S. companies with restricted stock units, you have units that vest a third over a three-year period, so that in any year, people have always got at least another two years worth before the rewards have fully vested. Typically it's smaller numbers of stock units than the number of options that you'd have granted if you were granting options. But what it means is that they are they're owners and growing owners over time from day one.
Restrictions on staff, restrictions on sales?
Once they're vested and in your hands, they're, you're not restricted in any way other than your belief that the share price is gonna go up, and therefore you hold on for the long term. I know from my own experience of previously being involved in schemes like that, the suckers were the ones who sold early, in terms of the reward. I mentioned the U.S. listing strategy. Our immediate priorities are bringing on board and retaining the investment bank that's going to be taking us through the process. We have already engaged the accounting advisors who are going to be implementing the systems and documenting them to achieve Sarbanes-Oxley, obviously, compliance. And obviously the legal firm who will be working with the investment bank.
Tony, as I mentioned, will be working on that program and spending a lot more time in the U.S. during that overall program. With that, let me hand it back to Jay to talk through the Ahpun development planning and where we're at on key items.
Thank you, David. Here we're gonna talk about how we plan to become West Texas North. One of the biggest items that we have in our well is the cost of the frac sand. We paid about $0.65 a pound for the sand that we used in the Alkaid -2 well. I won't go over all the cost differentials we had. You know, we brought it out of Canada and that was a very, very expensive process. Our operations team has now looked at that supply chain. That supply chain includes mining, sorting, transport, and storage. For each well, we're gonna use about GBP 25 million , and our target is $0.20 a pound. A significant savings over our previous cost.
It's still a very, very big number. That's $5 million per well. When you think that you may wanna have storage for 10 or more wells, that requires a lot of trucks, a very large storage area, a significant sorting and mining to do that, in the time period you wanna do that. Our operations team is well underway and have talked to all of lots of various vendors on the North Slope and other, and we are confident that we will hit that $0.20 a pound. In tubulars, we've been talking with current pipe vendors and using standard grades. We see no issues there. However, under full development, we may go to custom pipe if that proves to be a less expensive way to go. Rotating equipment.
Sometimes these are very long lead type items, but with the increased activity on the North Slope, we see increased pressure pumping capability on the North Slope. With the vendors, of course, we're talking to many of those vendors and the rig companies about long-term contracts. We don't see any current bottlenecks for gas compression, power gen, gas turbines, et cetera. We are confident that we are on our way to making this West Texas North and more like a manufacturing process. Now, we talked a lot earlier about the recompletion of the Alkaid- 2 well and what that meant for us in our development.
Based on those porosities and permeabilities that we saw in that well and the data we have from previous wells, including the old Pipeline State well, we have new type curves. As we talked earlier, these type curves are based on that reservoir data and generate 4,000 barrel a day IP30s and about 2 million barrels of EURs. This is our development plan starting in Q1 of 2026 with a single well. We add our second rig in Q3, and we hit about 10,000 barrels a day at that time. All in Q1 of 2027, we're up to 20,000 barrels per day. We add a third rig on a third pad, we get to 25,000 barrels a day. We're easily self-sufficient when we get to those kinds of numbers.
In the first year, we drill 10 wells. We've estimated that's seven producing wells and three injection wells. This is what we are showing the vendors that we are talking to about financing. Also, this will be important for reserve-based lending, for non-equity financing. I'm gonna turn it over to David to talk through that in more detail.
Thank you, Jay. What you'll see and if you've got a good enough memory, you'll recall when we presented numbers on the basis of what we'd seen in the original Alkaid- 2 long-term test, we were showing a ramp-up to around about 20,000 barrels a day by the end of 2027. Our approach to planning has been never to assume anything better than we have already encountered. That's what the big change here is, that we've now encountered this quality of reservoir. We've got the pressure buildup data that allows us to do the type curve matching and to be confident in the ability to develop wells, which on average, don't forget, there'll be some wells that will perform better, some wells that will perform worse.
We're talking about on average, build this up to a point at which by the end of 2027, we can expect to be hitting 40,000 barrels per day. Now, what does that mean in terms of the financing requirement? We originally, if you remember this, again, this is a revised version of the chart we showed you back in November, with the new well type curve. What it's telling you is that almost as soon as we get into production, the cumulative net cash outflow flattens off to zero so that there's zero further cumulative cash outflow. The original chart showed that number going to about $300 million negative cumulative cash flow.
With this type curve, we think that the total requirement is going to be somewhere just over $150 million, using that conservative planning assumption of $20 million per well for the first three wells, $20 million for the production facilities, $20 million for the pipeline tie-in, and $20 million for general overheads and engineering costs to get to that point. That was the $120 million up to the point of first production. As soon as you see first production, that chart begins to flatten off. The scale of what we're trying to raise is not as large as we originally anticipated, because we've now been able to demonstrate in a physical test an improved reservoir quality and liquids quality.
Just focusing on what do we think the borrowing base that we can support from this would be? Once we get up to the end of 2026, at that point, we would anticipate having seven production wells. Is that enough or too few to be able to begin borrowing on a reserve-based lending? It really depends what percentage of the remaining present value of those wells you're looking to borrow. If you're looking to borrow a high proportion, 70%, 80% of the NPV, you'd require a larger number of wells because your risk of any individual well impacting the borrowing base is higher. If you're looking to borrow 50% or 60% of that number, then the number of wells required would be smaller.
The key point that I want to get across with this chart is that by the end of 2027, we'll be at a point where 60% of some 24, 25 producing wells is going to be around $350 million. That's what that's telling you is that our liquidity and ability to dramatically expand from two, three rigs to four, five rigs and to accelerate the development as we move into the point at which we're also starting to think about the Kodiak development, we're not gonna have a shortage of liquidity. Now, why is that important? Well, there are some people who have been trying to do the math in their head and saying, "Well, if a rig can drill 10 wells per year and five rigs is gonna produce.
It's gonna deliver you 50 wells per year, and if you've got to drill 2,000 wells, that's 40 years worth of drilling." That is very simple and very elegant and very incorrect math. Because two things. The first is that the initial number of wells per year, it may be that it's a month per well as we start up, but if we see the kind of efficiency gains that we'd expect to see in West Texas, then we'll be drilling considerably more wells per rig per year. Second, as you move into the manufacturing process of drilling rather than the drilling business of drilling, what you see is you use a specialist rig for spudding the wells to get to that surface casing, and then you follow up with the directional rig with a customized program.
In fact, the number of rigs in terms of the number of drilling rigs you've got per well or number of wells per drilling rig, it starts to move geometrically because you are batch conducting different parts of the operation. That's how the real efficiencies are being driven in the Permian Basin is from moving from that one well at a time sequential process to best-in-class equipment for each of the different tasks and batching it like a manufacturing process and moving it forward. We're anticipating a situation in which, yes, there's going to be drilling activity on this for the next 20 years in just the same way as there was drilling activity on Prudhoe Bay for 20 years, and there was drilling activity on Kuparuk for 20 years.
It's not that this is going to take forever to drill out the field. Our initial estimate is that we're aiming for between 200,000 and 250,000 barrels a day of capacity on the current plan by about 2033. Within essentially years of startup. Then the decision will be on whether one accelerates by expanding capacity or continues just keeping the system full. That will be an economic optimization at the time. You've got enormous optionality in terms of how many wells you drill in what timeframe, depending on what the macro environment looks like.
What it's telling you is that as we move through first production, we've got a number of steps that are taking us to the point at which we've got a final investment decision on a permit when we start the development, and that takes us within about 12-month period of the start of development to being positive net operating cash flow. Indeed, on this type curve, self-sufficiency happening sooner than the end of 2027, which is when we were originally forecasting it. That is going to allow us to move more quickly towards full production capacity down the line between 200,000 and 250,000 barrels per day. What are we gonna be doing in the short term? What are the things to look out for?
There will be two main reports, one on the updated Kodiak, which will incorporate now all of Kodiak, all of the acreage, and a full evaluation of that. Bob and his team are working with Netherland, Sewell to get us to that point, aiming at the end of the first quarter. Right now, SLB are working on the detailed development plan, so individual well placements, individual pad, what are the facilities that we need to have in place? How much horsepower do we need for reinjection? How many wells do we need for gas reinjection, et cetera. That detailed plan is being developed, and that will then be handed on to Netherland, Sewell to produce a report on the resources of the Ahpun development based on that underlying development plan.
We will be looking at planning the appraisal of all of those areas that require further appraisal. For the FID on Kodiak, I can assure you that the State of Alaska is not going to approve a multi-billion barrel development on the strength of three well penetrations. There will definitely be another two or three appraisal wells. The precise timing of that will be a function of funding. We will look to drill a well into the Eastern extension in order to demonstrate the producibility and the fluid flow rates achievable from that area. That will help us to optimize the order of development in the same way as we move from starting out in the north to starting out in the south in those subsets.
How much of the eastern extension we have incorporated into the initial development will be determined by drilling over the course of the next two years. Again, precise timing depending on how the overall plan comes together. I know a lot of people were hoping for more commentary on funding. I'm gonna just leave you by saying, we told you that we would anticipate having the first substantive announcement around the non-equity based funding during the first quarter. We are still on track for that. We told you that we anticipate by the middle of the year having the full suite of funding laid out for you, and we're still on track for that.
We're at a stage in discussions where I'm not sure it's going to help us in terms of our counterparties to start talking about anything else. You should expect that we're going to be quieter rather than noisier on that, over the course of the next couple of months, getting to that point where by the end of the first quarter, we're able to share with you more substantive news. What I can tell you is that our strategy is going to be that, you know, rule one, you never go bust because you had too much cash. Rule two, you can always get cash when you don't need it, and it's hard to get it when you do need it. We're gonna be using those two rules as a watch word. We will fund this conservatively.
We will make sure that we are always going forward overcapitalized against foreseeable needs for capital. That will be our guiding principle along the way. With that, I think that's the end of the formal presentation.
That's-
I think we can, Mark, hand it back to you before we move into Q&A.
Yes, that's great, David. Thank you very much indeed. David, do apologize. I am muting you momentarily just so we don't get the noise playing back through for the audience online. Thank you very much indeed once again for your presentation, David and to the team. Ladies and gentlemen, please do continue to submit your questions using the Q&A tab situated on the right-hand corner of your screen. Just while the team take a few moments to review your questions submitted already, I'd just like to remind you the recording of this presentation, along with a copy of the slides and the published Q&A, can be accessed via your Investor Meet Company dashboard. David, I know you've got attendees in the room with you.
If I could ask you, please, if there are any questions from the room, just to summarize them or repeat them for the benefit of those online. Can I also ask you, please, to open up the Q&A tab on the right-hand side of the screen? You should see a number of questions that were submitted ahead of today's meeting, along with a number that were submitted during your presentation. If I could ask you just to read out those questions, and then I'll pick up from you at the end, David. Thank you.
Great. Okay, certainly. The first question I've got here is: Can we advise the approximate date we expect drilling to recommence? And does the company have sufficient funds at present to undertake further on-site work? I'm assuming further on-site work means drilling activity in terms of that. The answer is, under the development plan, we're not anticipating drilling until the first quarter of 2026. As to whether or not there will be any drilling prior to that will be a function of the funding strategy, and I'm not in a position to share with you specifics of that because, as I said to you, we'll be sharing more of that both at the end of the first quarter and during the second quarter.
We do not have sufficient funds, nor have we planned to have sufficient funds to go drilling without having completed the funding strategy that we've described with you. Second question: In estimating the value of its North Slope holdings, what assumption does the company make regarding extraction costs, short-term, medium-term, and long-term prices? The answer is when we've shared that target of $5-$10 per barrel, very specifically, the $5 number is arrived at using $70 per barrel for Alaska North Slope crude and planning for a 10% discount from that for the marketable liquid stream that we produce. Applying the tariffs, et cetera, that you would expect to see.
Applying operating costs, which are too detailed to describe, but it contains a fixed component cost per well, which is around about $150,000, and then a variable cost associated with how much water and therefore how much disposal, et cetera. The end result is that at $70 a barrel and a 12% discount rate, we get about $5 per barrel. At $80 a barrel and a 10% discount rate, we get about $10 per barrel, for the range of resources that we're talking about. That's the basis on which we've done it.
We've looked at down to what oil price do you still get a 20% rate of return on the development, and that ends up being around $45 per barrel. We think it's pretty resilient to what we're doing. When looking at the Kodiak field and its reservoir system, is it being viewed as strictly conventional or is there potentially an unconventional component being analyzed? Before I hand that off to Bob, the majority of the area that we previously had under lease, we've talked about it being unconventional in the sense that it will require completion with long laterals and multi-stage fracs.
Regardless of where you draw the line as to where does it cross over from conventional to unconventional and vice versa, that would be focusing on the wrong thing, because what really matters is what's the frac we're going to use to produce it. But Bob, do you wanna talk a little bit more about the reservoir quality as we move towards the northwest and west?
Yeah. Thanks, David. As we move to the west, we've already shown this, and we've published it. We're looking at substantial reservoir with better than 0.1 mD, which is usually the cutoff that people use between what they call conventional and an unconventional. Remember, we're looking at a system that's up to 1,000 ft thick. When we were looking at that, you know, we're seeing, you know, in some cases up to 50% of that reservoir is, you know, better than 0.1 mD. The answer is, yep, to the west of Theta West, a lot of the reservoir is conventional. As we move to the east of Theta West, it would be, you know, we'd be looking at it in the,
That terminology is unconventional. As David said, all of it is gonna be developed using long laterals and multi-stage fracs.
The precise, you know, anatomy of the completion will be an economic optimization. How much do you spend to get how much more flow rate and ultimate recovery? You optimize it to make sure that every dollar you invest earns the highest possible return. The completions in the far northwest may look quantitatively a little bit different than in the southeast, but qualitatively they'll look very similar. Could we give a timeline for next steps and company goals for 2024 and if possible 2025? I think we've covered that.
The only other thing to add that we know is going to happen in the relatively short time period, in addition to the Netherland, Sewell report on Kodiak, the Netherland, Sewell report on the Ahpun development plan, and our funding announcement, that 88 Energy will be flow testing the Hickory well, that will come in February, March of this year. From our perspective, if it flows successfully, that's great news. If it doesn't flow successfully, it doesn't influence the areas that we've already flowed successfully from. In a sense, it's a free hit for us one way or the other. In terms of hearing about financing, I've addressed that. We're still on the same track that we outlined previously.
Would management entertain a buyout of just the Ahpun field in the next 12-24 months or prefer Ahpun Kodiak combined deal? The answer is neither. Our preference is to maximize the value of the resources for shareholders' benefit. We would only contemplate a transaction in which we disposed of assets if it represented a better outcome than the alternative. Our singular focus is on achieving financial self-sufficiency so that we become price makers, not price takers. We're not secretly bluffing that we're trying to sell the company while pretending not to. We're actually seeking to maximize the value of the resources reflected to shareholders. Next question.
Having invested around three or four years ago in Pantheon, I watched and listened closely to presentations where it was stated there were around 22 billion barrels of oil in the Alaska held acreage up for grabs. What happened to the 22 billion barrels or is there? Is it still there? Is it just the case that publicly you've lowered your actual declared volumes because experts told you you were incorrect? Why is this being glossed over? Well, I can assure you that it's not being glossed over. I'm thinking that, from the question, maybe there's a misunderstanding about the difference between in-place and recoverable volumes. Our assessment is there's substantially more than 22 billion barrels of in-place resources. And we have always stated conservatively that we saw between 8% and 10% recovery factors in primary recovery.
The numbers have actually gone up over time, not down over time. If anyone was the person who asked that question, I would invite you, by all means, if a further more detailed explanation would be helpful, to email contact@pantheonresources.com and we'll be happy to clear up any misunderstanding on that front. Would you kindly outline the process required before you're able to book reserves? Once this has been achieved, is it at that stage the industry will recognize value in the ground between $5-$10 per barrel of oil? Jay, can I hand it to you to talk about what's required for reserves to be booked? I'll come back to the second part of the question.
Yes. We have to prove producibility at an economic rate. In addition, that you know there's a lot that goes into that. Then, of course, you have to have funding available to bring it into production. Those are the two critical elements because as David just reiterated, we know that we have huge volumes in place. We know that we have huge volumes recoverable. The big things for us to prove are the producibility at an economic rate and to have the funding available to bring it on stream.
Demonstrating a path to market. The existence of the pipeline and our ability to have access to it, clearly important and the regulatory permits along the way. We've got a question in the room.
In terms of the NSAI report, can we anticipate that there are going to be fewer conditions in the NSAI report on the afternoon, relative to the number of conditions that were shown in the Kodiak?
The question was, will there be fewer contingencies in the Ahpun report than in the Kodiak report? I wouldn't want to prejudge the contingencies. What I could say for sure is that by the middle of the year, we will still have a contingency around pipeline access because we won't yet have the FERC approval for the hot tap. We won't have FID. In terms of the specifics, I wouldn't like to guess. It's an independent report. That's the nature of independent reports. Yes, go ahead.
I'll ask two. My first one please. Can I take you back to recovery factors?
Yeah.
You just stated that we modeled our assumptions conservatively on 8%-10%.
Yeah.
Primary recovery factors. Periodically, we read that places like Prudhoe Bay, particularly using tertiary recovery, have demonstrated up to 60% recovery. Obviously there's quite a gap between the primary and tertiary, 10% and 60%.
Yeah.
Is it possible to extend our expectations for secondary and tertiary recovery on our tools?
Rather than repeating it, let me just check. Jay, was that? Could you hear that clearly?
No, I couldn't, David. Could you repeat it please?
Okay. That's fine. In that case, I will repeat it then. I just thought I'd test. The question was, given secondary and tertiary recovery factors in Prudhoe Bay as high as 60%, and our planning on primary recovery basis only of 8%-10%, what visibility might there be to higher recovery factors from our assets? The first thing is I very much doubt. In fact, I would eat my hat were I a hat wearer if we ever saw recovery factors north of 50% in our assets.
David, can I just interject a little bit.
Yeah, sure.
Knowledge about Prudhoe Bay.
Yeah.
Prudhoe Bay had a gas cap, an oil leg, and a tar mat at the bottom of that oil leg. It was a perfect reservoir for a combination of secondary, which is water injection, because the water couldn't go below that tar mat at the bottom of the oil zone, and the gas cycling in the gas cap. Yes, the original recoveries were estimated at 30%, but I assure you, the reservoir engineers at ARCO and BP and Exxon were always looking at recoveries that could go up from there. We don't have anything like that. However, in the up dip portions where we have better porosities and permeabilities, we certainly should see primary recoveries above the 10% level. We haven't assumed any of that.
Our planning basis is that until we see any successful indication of secondary recovery being viable, we're not gonna plan on it. That's in much the same way as many lower 48 fields in the United States have. They do move to water floods or CO2 floods or whatever over time, but typically as a pilot program to see whether it works and it doesn't work in all reservoirs. At this stage, given that we have no experience of pressure support, communication over long distances of injection flood fronts, that sort of thing, it would be just pure speculation to bet on anything else.
Sorry not to be able to give you more comfort on that. Just wanna pick up a couple of questions from online 'cause there are a heck of a lot here, and then we'll come back to the room. Can we go into the detail on the rationale behind the planned U.S. listing? What's the cost-benefit analysis? Which professionals other than bankers, brokers, lawyers, and other advisors who are conflicted and will receive fees from the transaction, and then I'm gonna editorialize and say, and therefore can't be trusted, are saying that this is a good idea. Can't major U.S. and international investors hold U.K.-listed companies? Hint, the answer is yes. How much has it cost so far? How much is expected to have cost at completion?
Will the chairman personally underwrite the substantial cost of the transaction if the U.S. listing is not successful or does not achieve the results he expects? Please explain why this is not a huge waste of the board's time and precious shareholder cash. Well, that's a compound question that I'm gonna break down into its various parts. The first is that we don't rely purely on interested professionals to advise us what's a good idea. We also take independent views and talk to potential investors in the United States across multiple different classes of investor. Whether it's family offices, whether it's major public equity funds, hedge funds, and others.
Our view as to the investability of the company is conditioned by that as well as the input from the professionals who are listed. Notwithstanding that, many of the professionals who don't have an interest in whether we actually do list or not, they only have an interest in giving us the best possible advice, have argued with us the pros and cons of that. There are certainly investors who are unable to invest in an AIM-listed stock. Some of those investors are able to invest in a main board-listed stock, and some of them are able to invest in a dual-listed stock more easily than just a London-based stock, because we're not talking purely about public market funds.
To date, I think it's cost us, what, GBP 25 thousand, or maybe a fraction more.
Tax advice.
A few tens of thousands of dollars in order to properly splash out how much we expect it to cost at completion. The majority would be back loaded and fees would be through the commissions on any funding raised at the same time as a U.S. listing. The likely costs are arranged depending on what it looks like. I fear that you'll be disappointed if you're expecting the Chairman to underwrite any specific corporate costs. There is a general situation in which we view that the management of the company is the management of the company, and the company is the legal personality that people expect to take the risk.
As to why it's not a huge waste of the board's time and money, I can reassure you that we have not just looked at it from a point of view of is it a good idea from an equity market perspective. We've also looked at it from the perspective of, is it a good idea for the company corporately? We are going to be undertaking extensive engagement with the State of Alaska, with the federal government, with local communities, and with policy generally in America. In addition to views as to what the likely impact is on the stock price of the company, there is also a view on how it helps us to manage the risks and ability to get the approvals we need of having a U.S. personality being based in the U.S.
That feeds into our decision to be moving forward with this program.
Made in the U.S. It is in the U.S.
It turns out it is for the time being. Although, obviously, Alaska, you know, and the U.S., are they really the same thing? The answer is that we want to be both Alaskan and American, in terms of how we act. There's a simple question here. What is C5+? So, hydrocarbons, you have methane, one carbon atom, four hydrogen atoms. Ethane, propane, butane. You get to pentane, that is five carbon atoms. That is the point at which typically without the need to chill or to hold pressure, hydrocarbons will be liquid. So when we get to C5+, it's typically what we're referring to is all of those hydrocarbons which would be naturally liquid without the requirement for temperature or pressure control.
That's why that's the typical cutoff when describing a liquid cut. In terms of what will be marketable liquids, there'll be the opportunity to include the butane and propane going into the Trans-Alaska pipeline. Although there may be slightly higher value in marketing propane as propane because that's used in a variety of different settings across Alaska and shipping it around. Ethane will almost certainly be consumed as fuel in our operations. Why are the major oil companies seemingly not interested in Pantheon? I'm assuming that question is based on because a major oil company hasn't made an approach to acquire Pantheon, ergo, they're not interested. I think that there are two ways you can look at this.
One is to do the thought experiment that it would be very difficult given the liquidity in Pantheon shares for anyone to acquire a position unnoticed of more than 2% or 3%. Investors, if they suddenly saw a major oil company having gone through the threshold and bought 3% of the company, my guess is that the share price wouldn't be what it is today. For a major oil company, they don't typically like to start a transaction that they don't know they're gonna finish. The question then becomes. There's probably not a path to a hostile takeover at any kind of a price that reflects where we are today.
The question then becomes, does someone think that making an approach to Pantheon's board at prices similar to today are liable to receive a recommendation and shareholder approval? I don't think we could have been clearer about the fact that that wouldn't be the case.
Wouldn't?
Wouldn't be the case. If someone came offering $500 million for Pantheon today, I can reassure you we would not be recommending that to investors, nor do I believe that the majority of investors would be interested in taking that. So the answer is that until there is less of a mismatch between what a potential acquirer would perceive to be an acceptable offer and the current market price, it's highly unlikely that you would see activity of that nature. Does that mean that there are no companies interested? The answer is no, I wouldn't think that is a fair reflection of the situation. Mark, you've just removed a question that, h ang on. Maybe I can get it back, that I was about to get to.
Sorry, David, which question was that relating to?
Yeah. Oh, yeah, sorry. I didn't take the next question in line because I was dealing with-
Oh, okay.
Something more specific. If when a listing on a major U.S. exchange is obtained, will our shares on the AIM be transferable to that exchange, maintaining the long short status of all share purchases? I believe that, yes, because what would happen is that existing positions would be rolled over. I don't know enough about. I imagine that naked shorts would probably not be covered in that situation, but actual short positions would be rolled over in that situation. Does the Ahpun East topsets qualify as a conventional reservoir? I'd refer you back to Bob's earlier answer. It may well, in fact, it definitely would, on the basis of the numbers he shared earlier, be recognized as conventional.
Would that mean that it wasn't being developed with the completions that delivered the highest return on capital invested, which would likely involve long laterals and multi-stage fracking? The answer is that it would qualitatively look like the same kind of completion as we're finding across the entirety of the portfolio. Is Megrez a historical well or the name of Pantheon's next Alkaid well? Bob, you're probably the best historian here.
It's-
Bob, do you want to address what the Megrez name is?
It's the name of one of the wells or one of the locations where we have gotten permits to drill. That's all it is. It's at that location, we can actually test and also develop the Ahpun East from west of the road, so on the west side of the river.
We have a permit for the pad location at Megrez and a permit in principle to drill from it, but obviously the specific well permit for the particular well plan would need to be approved by the state.
Correct.
What will the current shareholder dilution when the U.S. IPO is completed? I have no idea.
It's something.
Exactly. Entirely so. It depends what the share price is at the point that we do the IPO. It depends how much money we raise in the IPO. It depends how much other money we've raised in the interim period as divided between equity and non-equity funding. When can we expect an update on the chimney? The chimney, I'm going to ban use of the word chimney going forward because obviously with the additional acreage to the east, it doesn't look like a chimney anymore.
To the west.
Sorry, to the west. It doesn't look like a chimney anymore. The resources attributable to the 2021 lease sale, sorry, 2022 lease sale rather, were incorporated into Netherland, Sewell & Associates' initial evaluation. The revised evaluation will incorporate all of the acreage that we now have, and we're expecting an update on that around the end of the first quarter. We're moving to some different questions. Go ahead, in the room. Yeah.
Yes. In terms of timing. Move to the Main Market. Would you be planning to do that before or at the same time as the U.S. IPO?
I think.
I mean, a lot of other companies have done that some time before.
Yeah.
In which case I'll put you on a target date of some time this year for the main markets.
Yeah, that's a process we're working through. We don't have a firm answer on that yet. Yeah, we'll update the market when we know.
I think it's the one thing we can say for sure is it's not gonna be later than.
Yeah, yeah.
Yeah.
Can I ask the odd question?
Yeah, of course. Sorry. Just in case anyone missed that, the question was, would we be listing on the main market in London before the US IPO or at the same time? The answer was certainly not later, but we don't have a specific answer.
You mentioned that you are aiming for a peak production of between 200,000 and 250,000 .
Yes.
Within seven years. What would be technically and commercially feasible peak production for a major that is less financially constrained than you? Can you comment on the scope?
Well, I think it depends ultimately on the pace of drilling in terms of and how much you expand the facilities into the pipeline. The peak throughput of the TAPS pipeline was 2 million barrels a day, but it would be very hard to get back up to 2 million barrels a day. There's a lot of oil coming in from other sources, and there are costs associated with step-ups. What would be a likely peak production rate if you think about, Jay, you'll remember Kuparuk River was 390,000 barrels a day peak, was it?
Something around that, David. We actually got over 2 million, but that required the use of friction reduction agent. I doubt that anyone would wanna revisit that.
In the room, there are people who are imagining what friction reduction agents look like, available from all departments. The point about it is that I think the original plan for Kuparuk River was somewhat less than 380-390,000 barrels a day, but the economics of expanding the facilities and expanding the throughput justified it. I could quite foresee a situation in which it became apparent once we'd got enough production history to know that the length of time that we were going to exceed that 250,000-odd barrels a day would justify the additional investment, and therefore we would expand it.
If you simply run the math and have a continuous drilling program, you could end up at 500,000 barrels per day. Would that be the optimum economic decision? The answer is there are many factors and a lot more analysis before you do it. The planning for our initial access into the Trans-Alaska pipeline is going to be in that 200,000- 250,000 barrels a day range. That's the size of access that we want.
If someone wants to do that, basically we need to then get a further
You'd need a further approval for an expansion of that facility. Yes, another question here.
Yeah. Second question. Can I take you back to the Ahpun developments?
Yeah.
Specifically the testing at Alkaid.
Yeah.
Even more specifically, today's RNS, which obviously managed to have a little result that's not
Yeah.
When you presented in November, we had a nice financial plan and all that kind of stuff. It's been materially altered today by what you've shown us. It looks a lot more favorable. How come we're in a situation three months later whereby we are making a much more optimistic projection? Is it purely on the basis of what we have back from GeoMark?
The pressure buildup.
Absolutely. Sure.
The pressure transient analysis to understand the effect of permeability.
David, could you repeat that please?
Oh, sorry.
It was coming.
Sorry. Yes.
To me. I don't know about others.
Yeah. No, no. Forgive me. I should have repeated it. The question was: We've announced a material update and upgrade of the forward projection, compared to just two and half months ago, when we showed the startup ramp up, on the basis of the then type curve, based on the Alkaid test. The question was what had led to that. The answer is, it's the combination of the GeoMark analysis of the fluids and the pressure transient analysis, using the data retrieved from the pressure gauges. Just to put it in context, the amount of flow into a well is a function really of three things. One is the area, which is a function of two things.
The area of the sand face that's accessing the reservoir, and that is therefore the width and the height. Now, if you didn't have a frack, the only thing that would really matter would be the height and the permeability. In a fracked well, it's the area of the frack and the permeability flowing into that because it's now linear flow into that. The two factors that have significantly improved our view is the frack efficiency. We now know we can get a highly effective large area in a frack. The second is the permeability, where we now know that the permeability is two orders of magnitude better than we had assumed in our original type curve. When you multiply those two things together, you get a significant increase in expected well performance.
This is appreciable, effectively telling you that about the permeability?
It's the shape of the curve building up. If it builds up quickly, this is a massive oversimplification, but if it builds up quickly, it is generally high permeability. If it builds up very slowly over a long period of time, it's generally low permeability. The precise shape of that, depending on how quickly you drew it down, how much you produced, how long you shut it in for, leads to the ability to analyze what the in-situ permeability of the rock is.
Can I make-
Oh.
Sorry, can I make a.
Yes. Oh, please go ahead.
Yeah, there's a number of questions that are kinda bouncing around here. One is, you know, when we tested Alkaid, we had the Alkaid anomaly, the first part of the test. We had the results, and we took those results and, you know, we built our models. We had not yet tested the Alkaid shelf upper zone. We hadn't tested the top set, and we had a set of models. Those models were built by Schlumberger, you know, and it said we have an economic development that we can move forward with.
The Alkaid- 2, quite simply, you know, again, at the feather edge of the reservoir, was saying we had a significant improvement in permeability, like 100x better permeability than we saw in the Alkaid- 2, the primary test. That leads you to saying, "Hey, this, you know, we can develop the topsets and this is what it's gonna look like." I can tell you, as we move over to Pipeline State, where we're in the heart of the topset that we had under lease, we even have better reservoir performance. Now, that hasn't been included yet into our analysis. It will be included. Then thirdly, as we move over to Ahpun East, we even have another order of magnitude improvement in the permeability.
The point is, you know, we will be adjusting and, you know, moving forward. As we are proving these models up, there will be changes, and it will be changes to the positive side. What you're seeing today is our best, you know, our best estimate given on the test results that are verifiable as of this moment in time.
Our planning basis is restricted to what we have actually encountered rather than what we expect to be better as we move to the better areas. That's-
Correct.
Yeah. It gets better going south to Pipeline State. It gets better going east to the new-
Yeah. Yes.
Yeah.
Okay.
Pipeline, you know, we at Pipeline have whole core data through that reservoir. The point is, you know, we can expect that there will be further changes. But right now what we have is a fantastic project that is economic at, you know, today's prices. It's you know as David has said you know we have a good project even at $45 oil.
Okay, there's another question in the room here. Go ahead.
Just to follow on, David. With regards, I mean, hearing that the direction of travel is that it's getting distinctly better.
Yeah.
You've modeled some of the initial production tests at 50% water cut.
Yeah.
Moving forward into the sort of more conventional acreage, can we assume that there's less active flow and therefore a better water cut, so more oil in the?
Okay.
There's more separation.
Let me address repose the question for people online. As we move to better quality reservoir, will we see a lower water cut than we've assumed or have seen to date? The answer is quite possibly so. Again, it's not something we're planning on, and it's not something we're gonna speculate on. We're trying to restrict ourselves in terms of statements of data. It's what have we actually seen. We have expectations, and we've shared some views as to how things might improve qualitatively. To be honest with you, the amount of water is not a major driver of development cost or recovery. It's you know, we're gonna have to handle water no matter what, and in large quantities, and we have a plan for that.
It might make a difference in terms of amount, fractions, and therefore a huge difference in.
Sorry, in terms of number of frac stages?
The frac stages. Yeah.
No. It's unlikely. The water cut is unlikely to be a factor in terms of the number of frac stages. The number of frac stages is going to be to drain the maximum area of reservoir that can be drained. How close the frac stages are to each other is a function of the permeability and therefore the pressure communication. Are you robbing Peter to pay Paul with one frac stage to another? The amount of water in there is not a major factor in determining that. Yeah. I mean, we can have a more detailed discussion, but no, that's not a major issue. There's another question there.
It's more a finance question, moving away from the geologist. Going forward and consistent with the development plans, is there a plan to engage with, w hat are the key inflection points that make us more investable along that process? Is that going to be affected by the migration to the U.S. system for the investors?
Okay. The question was engagement with investors during the course of the plan, leading ultimately, you know, at the end to when we're up and producing. The answer is, predominantly, that the mix of investors who will have an interest will change as we get nearer to production. It will change as we appear to have less need of money. It will change as we become U.S. listed versus not U.S. listed. That doesn't mean that there isn't a valid path to funding that doesn't involve a U.S. listing. As we mentioned, there are multiple dimensions to why being a U.S. listed company and a U.S. legal company, holding a U.S. asset and dealing with regulatory authorities, also has an advantage.
This isn't a pure corporate finance game as to where we think investors will pay the most because there are many investors who as the earlier questioner correctly identified, they're not governed by where you're holding where the exchange is. Certainly it's true that there are a lot of people who can't invest in an AIM listed stock. Whatever happens, that's probably not a long-term sustainable place for us to be listed. We will be, during the course of the next 14 and a bit months, engaging with a range of investors, not just North American, but generally, in order to make sure that we're structuring ourselves and making ourselves known to the people who will increasingly be able to invest in our equity.
I want to pick up some more from online before we come back to the room, if that's okay. How long is the U.K. listing expected to last after the planned U.S. listing by the end of Q1 2025? That will depend to an extent on a cost-benefit analysis. The main advantage of holding the U.K. listing is probably for U.K. investors who have invested in an ISA or alternative tax efficient wrapper. We will take a view if the majority of capital gain, which is the main thing that people are looking to protect, has occurred and the continued cost of having a U.K. listing is not attractive versus the benefits to investors, then we wouldn't.
If there is an argument for keeping it, there is certainly no presumption about the timing of when we would or wouldn't lose the U.K. listing. We've heard all this before. I was looking forward to an update. Where do we stand on the Kodiak field? Do you have a timescale? I think we've half answered that, which is that we will be reporting on the full Kodiak resource with a better explained basis by we're aiming for the end of the first quarter. We're also aiming in terms of the funding to meet the timetable we've originally shared, which is by the end of the first quarter, we should have preliminary news on non-equity based funding.
By the end of the first half, we should have the full funding program for our activity tied up. It's interesting that Justin has found another position. Will you keep us updated on the new listing? I don't think Justin has found another position. Or at least he hasn't owned up to it to us yet. What we're saying is that the current role as the needs of the company expand, I know because I get emails from Justin later at night and earlier in the morning than is sensible for anyone who's hoping to stay healthy.
What that means is that making sure that we allocate roles to allow people to focus on the areas that they can add most value, and in Justin's case, that's being the finance director. Having someone else running the overall program of coordinating the different pieces for the U.S. listing program, it doesn't mean that Justin's not gonna be involved in it. It just means that there's someone else who's keeping tabs on top of that. Similarly, it's not uncommon for the accounting and the finance to have some degree of separation and having a financial controller. Justin has been de facto the financial controller for the last 17 years.
As the organization matures and the needs mature, sorry to disappoint Justin, you don't have a new position. Alkaid -2 was landed in a highly structured part of the Alkaid reservoir. How much of the poor completion efficiency was due to having the wellbore out of the primary zone? That's probably a more technical question that requires more pictures to describe. The answer is undoubtedly some part of the well performance was to do with how the well was landed because it certainly came out of zone at some point. With hindsight, we probably would have landed it lower. The majority of the well performance was a function of the frac design implementation and efficiency. Sorry, not to give a more detailed answer on that.
When's the Netherland Sewell report coming in? We've dealt with that. What can shareholders expect now in return for their investment? Or would it be logical to come back in six months to buy in? The answer is, if you think that it's a better idea to sell now and buy back in six months, you should definitely do that. If you don't, then you shouldn't. That is about the extent of any investment advice that I'm going to give to anyone. When do we anticipate U.K. listings become defunct? We've answered that. We've answered the question of when would we move from the AIM to the U.K. main board. What is our current value per barrel? Well, the market says that we're worth about $0.10 a barrel.
We think we're worth considerably more. That's what we're working to demonstrate to everybody. We'll do it by doing lots of small and boring things that will lead, as I said before, to a point at which people begin to recognize that achieving the targets we've set has become inevitable. That's when I would expect to see a value of more than $0.10 a barrel attributable to our resources. Can we give a targeted break-even per barrel? We've talked about when we run the State of Alaska Alaska North Slope cash flow model at $70 a barrel and a 12% cost of capital, we end up at about $5 a barrel. When you take that down to t hat instantly is about an 80% rate of return development from memory.
I don't have it in front of me, so please don't hold me to that specific number. When you take it down to what price gives you a 20% rate of return, which would be a typical threshold for moving forward with the development, that's around $45 per barrel.
That's your cost or your return?
That's the ANS price at which the development gives you about a 20% rate of return. That's sort of an equivalent break-even. I appreciate that drilling can't begin until finance is addressed. Surely the company will be actively drilling once finance is secured. Is it safe to presume the technical team is planning to drill an Alkaid East topset so they can fire the gun immediately after financing is secured? The answer is it's safe to assume the team is doing all the planning necessary for all the activity that the board considers to add most value to shareholders. That we are certainly not going to wait until we have completed funding before we start thinking about the next thing.
We are going to be planning for the range of different things we would do, given different timings and availability of financing. The whole program is built around optimizing value to shareholders. Can we request our brokers not to loan out shares to short sellers? And if they have, can we ask them restock? Can the company vote for not short selling Pantheon shares? I don't know that that's something within our ability. I do know that typically if you tell your trustee or nominee that you don't wish your stock to be loaned, then they can't. But I don't know. There are so many different brokers and so many different sets of paperwork to go through. I'm sorry, I don't think we've got an answer for that.
Have we provided estimates on the slope fan system within our acreage? If not, are we planning to do so? We have. Historically, we provided an in place assessment. I think that was a couple of years ago. We haven't done any updated work on that since. Bob, do you know?
I think we're gonna be handling that as part of looking at the full field kind of development, like at Ahpun. You know, we know we have the slope systems there, and we're just kind of working on them. Yeah, I have no specific target for getting the full sort of resource on the slope systems yet.
Yeah. Okay. The question asked earlier wasn't from this person, but they think what the person meant was, we've previously said 22.8 billion barrels of oil in place with 10% recovery, so therefore 2.28 billion barrels recoverable. People want to know where this has gone and the latest estimate. The answer is it's gone nowhere other than the however many thousand barrels we sold in the long-term test. That we're anticipating when you add the new acreage and the revised estimates, that will lead to an upgrade from the 22.5 billion barrels of oil in place. We'll be sharing that over the course of the next two quarters in the two major accumulations, Kodiak and Appomoo.
What won't be included in Kodiak and Appomoo will be the additional zones that we have to incorporate in such as the slope fan and other things.
David, I was just gonna jump in just to say that, for every one question you answer, you're getting another two or three. Just to remind you that there's always the opportunity should-
Okay. Let's
Let me know, and we s tep up the pace.
Okay. What progress has been made on the tie-in to TAPS? Who's responsible for driving that process? To save time, I'm gonna say Pat Galvin, who is our Chief Counsel and Chief Commercial Officer, is driving that process in Alaska as we speak. We're taking the stepwise process necessary to get to that point. I'm not gonna get into the details of it today. There's a question, can we help people to map all of the individual zone names to the Ahpun and Kodiak fields. I'm sure we probably can at some point. What I'm gonna tell you is that the Kodiak field is the lower Basin-Floor Fan, for all intents and purposes.
Anything else that you may think is part of the Kodiak field, it is not part of the resources that are estimated for the Kodiak field. Will there be other zones that may, in due course, be incorporated into the Kodiak field? Yes, if we appraise them and find them to be economically developable. Similarly, for Ahpun, the only zones that are included are the topsets and the Alkaid zone of interest, which is an oddity that just happens to have had a couple of wells drilled in it, and therefore we've incorporated it in. Anything else is not part of that. All you need to know is that the Ahpun field is predominantly the topsets, what used to be called the Shelf Margin Deltaic, various iterations of that, but it is now all of the topsets.
The Kodiak field is the lower Basin-Floor Fan. Any progress to relay about the proposed Alaskan gas pipeline? That would be a matter for the AGDC, the Alaska Gasline Development Corporation, to share. We understand that there are discussions ongoing with potential sponsors of that and we would anticipate being a part of the conversation given that we have high quality gas along the line of the pipeline that requires less processing than gas from the North Slope. Last webinar, Jay said five or six usual suspects. He did indeed. That's quite correct.
We did say at the last webinar, we were not going to be providing continuing commentary on who was and wasn't in the data room or signing NDAs, what they were wearing, or what conversations they'd had with us at any point. Kodiak is fundamentally why many investors are here. Ahpun is a stepping stone, but I feel we are. I'm not sure what that word is on the Kodiak field. Do you think that's delaying or something? I'm not sure.
Lacking, I think.
Uh.
Lacking.
I feel we're lacking on the Kodiak field. The earliest date that we could begin production from the Kodiak field is in line with the program. Even if we had unlimited money today, we would still be talking about an FID in late 2028. There is absolutely no lack of focus. In fact, you'll see that the early work on the volumes, because it is so important to planning the overall scope of the development of the two giant fields, we have done a lot of work on Kodiak, and that will be the next major report out, which is then on the entirety of Kodiak.
Ahpun is indeed a key stepping stone in terms of providing the funding and providing the infrastructure that allows us to move into the development of Kodiak as quickly as possible. If there's anyone who thinks that Kodiak isn't important to us, the answer is, you couldn't be more wrong. Kodiak is absolutely where the largest volume is and where the long-term production will be supported from. What is Ahpun if we forget about Kodiak? I'll assume that's not in the metaphysical sense. Ahpun is a giant field, in round numbers, 500 million barrels a day. I think official number 481 right now. When we've done the further work, we will be able to share a number for that.
If someone offered you that for Christmas, instead of Kodiak, it would be a pretty ungrateful grandchild who said to their grandmother that they wanted a Kodiak, not an Ahpun for Christmas. Ahpun is a giant and valuable field in its own right, and more valuable in the sense that its proximity to the infrastructure allows us to build cash flow incredibly quickly to accelerate the development of the overall program. It has its own value, that would show up in the $5-$10 per barrel range. It also has a multiplier effect on the value that we can bring to Kodiak. The upgraded IP30 figure, 4,000 and 2,000 as an average number over the first 12 months is a massive upgrade.
I have in mind the previous guidance was 1,500-2,000 for IP30. Is that correct? This is very noteworthy, isn't it? Yes. How is the company going to ensure the stock market appreciates this revised guidance? By telling them about it and by answering any questions people have as to how we arrived at it. By any definition, these are highly commercial numbers, correct. They were pretty highly commercially attractive on the original basis. We absolutely believe that more oil for the same money is more attractive. So no disagreement there. Is there a theory on why the GOR has improved so much in that topset test? Yes, is the answer. But part of that is because of better sampling and better production practices that meant we got a more representative sample.
Part of it is because the GOR in the Alkaid zone of interest test is probably an overstatement of the GOR, because of the way in which that well was produced, that resulted in more gas production than otherwise would have been the case. We still think there's a lot of gas and a lot of reservoir energy, but we think we've got a much tighter handle on it now. What is the current total number of barrels recoverable being used by management? We have announced a number in the past, which was the 1.7 billion barrels, 1.78 billion barrels. And then add the 481, that's where you get the 2.2-odd billion barrels. We will be providing updated numbers in due course.
What is the current cash available and current monthly burn rate? Justin, do you wanna talk a little bit about that?
We announced at our year-end that we had just under $8 million in cash. If you recall, there was a placement, an equity placement with deferred terms. That money's presently in the process of being collected by the company, and that's about another $4 million or just a little bit over $4 million. That's where we're at. In terms of cash burn, our G&A was running around $7 million. That will naturally increase as we move towards the U.S. listing with additional costs. You know, that's a fairly representative number.
Okay. Thanks for the update regarding Justin. Sounds like there's a shareholder who's as relieved as we all are on that. The entire webinar seems to have avoided Kodiak. Could Bob discuss further? I don't think we have avoided it.
I think-
Bob, is there anything more you'd like to say about Kodiak?
Well, I wanna say, you know, the presentation on the eastern acreage was just to say this is the work, the new work that we've seen since the last webinar. Which was, you know, highlighting the quality of the reservoir we expect to see in Ahpun East. We are working on Kodiak now. Within, you know, two months, we expect to have, like a major update on Kodiak. You know, I'll remind you on the last webinar, we are showing a significant improvement in the reservoir quality as we move to the west. What that all means, you know, we're hopefully have that answered for everybody by the end of the first quarter.
Line is, have the currently drilled and completed wells all been plugged and abandoned or are some of them planned as producers? I'm gonna add in or injectors. Similarly, will the forthcoming appraisal wells on Kodiak subsequently be planned as producing wells?
No.
It is not all the wells have been abandoned, but ultimately are likely to be. We are hoping to use the Alkaid- 2 well as an injector. As things currently stand, that's. We're not planning on appraisal wells which are likely to be drilled from on ice pads to be completed as producers, but you never say never. If it turned out that one was drilled from a location that was ultimately going to be a gravel pad, I can envisage it would be. That's not a basis for planning. Are there any more questions in the room? Irving, yes.
There was one quick question. In the last Canaccord note, they drew attention to helium.
Did they?
Somebody brought that up.
Oh. Do you know what? I think there's
The Canaccord.
On the institution. Yeah, that was the podcast.
Yeah.
The Chuck Yates Needs a Job podcast.
Yes. Yeah.
I'm sorry, there was some editing of that which created a rather misleading. 'Cause earlier, at the start of the webinar, he asked me what I'm doing, and I talked about mostly about Pantheon and a little bit about Proton Green, which is a helium production company. At the end, as he's starting to wrap up, 'cause he'd originally intended that we were gonna talk about both companies. As we started wrapping up, I simply put a placeholder for him. Don't forget we were gonna talk about helium and carbon dioxide, which is what Proton Green produces. Apologies if that all got mixed up, because I think the Proton Green reference at the start got cut in the edit. So.
I assumed it was all still there.
Oh, God. Yeah, no. I mean, I can absolutely assure you, Proton Green is 100% focused on producing helium and carbon dioxide.
Sure.
Pantheon is 100% focused on appraising and developing oil. Anyone who assumed that statement was to do with Pantheon, I know, I saw Paul corrected that online for a few people saying, "I think the people have got it a bit garbled on that.
Right.
Nabil, yes.
David, I'm gonna ask a very tough question.
Please.
That is, if the world goes to hell during 2024, as it seems to be aiming that way.
Mm-hmm.
We're not able to get financing. When we look at this project as is, and you're gonna say you'd have to put it into auction, we cannot get financing. What would you say the value of the asset as it is today? What do you think we can get for it?
If you were to try and sell it today just as is, where is?
The way it is right now.
I wouldn't want to speculate on what that might be. It would certainly be less than we would get if we were to,
That's for sure.
Get development. I would have to take advice. If we were to put the company up for sale today and people knew that the company was truly up for sale, what price would we get compared to people making speculative offers? I don't know is the answer. That's
What is the price of oil in the ground?
Today?
Yeah. In the ground.
There's no individual price that you could apply. There's no general price you could apply to oil in the ground. The market's been pretty clear that it thinks it's about $0.10 a barrel in our hands right now. I'm pretty confident that if we were to sell the company tomorrow, it would sell for more than the current market capitalization. I think the thing that would stop it from achieving that would be if people didn't believe that you were serious about completing a deal. I don't have a good answer for you. It's a great question. For anyone who didn't hear the question, the question was, if you put the company up for auction today, what would it sell for? I don't have a good answer for that.
I'll hold my hand up and be honest.
There was an in-the-ground oil deal in Alaska not that many years ago. Paul Armstrong, I think.
Yes. Yeah, but
I think the valuation was about $3.50 a barrel.
It depends on what you think the volume was, because the seller might have said that there were X number of barrels to buy. I might have said there were this number of barrels. So the number could be between $1 and $3.10.
That deal did go through.
That deal did go through. The question is, where is the marginal buyer today? Was that a stroke of luck? Was that the result of strong competition? There are quite a lot of unknowns that would make it unsafe to definitely read across. As to what the precise number would be, I just don't think I've got a good answer for you that I would feel comfortable was credible in terms of its foundation. I always said to you, "I'll tell you the truth when I know it, and when I don't know, I'll tell you I don't know," and this is one of those I don't know. Any other questions before we wrap up? Okay, last question.
Yeah. Could the recent share price performance of another U.K. company with U.S. assets, this is, I think November of last year, hasn't been good?
Mm-hmm.
Could that make Pantheon a tougher sell, or are you aiming for a different success with you potentially as investors by now?
The question was, is past experience of U.K. companies relisting in the U.S., relevant to whether or not we're likely to be successful? The answer is that we can only focus on what we have, how that interacts with potential investing markets. What I guarantee is that if we need money, then we're less likely to achieve success than if we don't need money. The objective here must be to, you know, maximize the value. Someone sneaked in a question. Someone in Huddersfield says his wife is desperate to divorce him and wants the share price to rocket. Hoping we both get our wishes.
It wasn't really a question, it was a comment. With that, Mark, back to you. Thank you. To wrap up.
That's great. David, Jay, Bob, thank you once again for updating investors, and thank you to everybody for your considerable engagement this afternoon. Can I please ask investors online not to close this session as we'll now automatically redirect you for the opportunity to provide your feedback in order that the company can better understand your views and expectations. This may take a few moments to complete, but I'm sure it'll be greatly valued by the company. On behalf of the management team of Pantheon Resources, we'd like to thank you for attending today's annual general meeting, and good afternoon to all.