Pantheon Resources (LSE:PANR) — AGM

0:00 Good afternoon, ladies and gentlemen, and 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 could be submitted at any time using the Q and The company may not be in a position to answer every question received during today's meeting. However, company can review your 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 in which of the AGM in which all the resolutions were approved. We also a few minutes ago released an RNS confirming that those resolutions have been approved and sharing with you some information that we'll be presenting in the webinar.

1:00 So, I would invite you to review that at your leisure afterwards, and we'll be posting the presentation to our website. In fact, may have already done so. Someone's nodding at me, so that means it has already been put on our website. Joining me today in person, Justin Hondros and virtually Jay Cheetham and Bob Rosenthal, and we'll be running through a number of things to give you an update on where we're at in terms of moving forward to achieving our stated strategic goal of achieving a recognition of $5 to $10 per barrel of recoverable oil. I would invite you please to review the disclaimer.

1:47 Again, do feel able to read it in the posted version in due course. And what I can see is that when Bob was practicing how to use arrows there we get they remained on the screen. This is obviously just a reminder of what we've got and what we're going to be talking about. And to the west, you can see the thin outline of the new acreage that we acquired in December, which is the up dip extension of Kodiak. And to the east, you can see the blue line, which again is the easterly extension of Hapun. And we'll be talking in more depth about that. But I want to use this as the backdrop to give you a quick review of what we achieved in the last well, effectively eighteen months. So the year that we've reported and just had the AGM for and the subsequent events.

2:50 And of course, the biggest event in that period was the long term test of the ALKARE-two well. And what we have come to realize as we've done the analysis and subsequent work is that that will turn out to be a 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. And that was the reason for the pivot of the strategy that we announced in the middle of last year just before our financial year end that we were going to be moving forward with all speed towards bringing our resources online that we would cost what it would take to get there. And we would develop a funding strategy that sought to bring us into production and then to financial self sufficiency at minimum dilution to shareholders. And the commitment to that, I've said it before, I'll say it again.

3:53 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 will stiffen the sinews somewhat and make sure that when we talk the talk, we're also rather incentivized to walk the walk. And that's absolutely what we're intending to do. And we will, in due course, be sharing news with you about that. Subsequent to the result of that well where we don't need to re trade history, Needless to say, it was not viewed favorably by the market at the time.

4:45 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 Alkade II well to test what are the top sets. So you'll have heard lots of different words to describe the different formations. If we're to leave you with one message today, it is there are two large fields. One is called Aupun, and it's got some formations in it and the other one is called Kodiak and it's got some formations in it. And Bob and his technical team are much better at understanding and describing and explaining those technical things than there is any chance of anyone around this table or anyone else in this room being able to better understand.

5:43 There are multiple formations laid down in multiple events, But at the end of the day, what we've got is a set of what are called top sets. Bob will talk a little bit more about that, which is the predominant resource in the Yapun field. And you've got a basin floor fan, which is the predominant resource in the Kodiak field. But at the end of the day, we're developing these as two fields that will be engaging with the state of Alaska are engaging with the state of Alaska about two areas, one called Lapun, 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 Netherlands will 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.

6:44 But their evaluation was just shy of 1,000,000 barrels of recoverable marketable liquids. And they are working on a similar report for Apun. The company's estimate, you'll recall for that set of formations is four eighty one million, an oddly specific number, but four eighty one 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 Lemansour. So that's those are the key things to remember. But the critical thing for us was that subsequent recompletion of the Alkade well, which allowed us to test the formation that is the predominant resource within Apun.

7:31 And what we found and we'll share with you in a bit has led to our ability to now reforecast what the development looks like. And Jay will be sharing that with you shortly when we get that far. So let's just move into what really matters. I'd say the review of the year, you can read the annual report and it would be more informative than me trying to re narrate it for you. We've recompleted the LK2, while I mentioned we acquired the new acreage and that now genuinely completes our acreage acquisition. We have always thought that the updip most westerly portions of Kodiak would be where the best reservoir was. You can understand why for obvious reasons we couldn't go and apply for the furthest west bit and leave a crack in between that we didn't go for. So we had to play a sophisticated game over the course of the last few years of gradually expanding in order to avoid a situation in which people were competing with us. And from our point of view, we've managed to complete that before the seismic that it was all founded upon becomes public.

8:48 Next year will be the first release of the proprietary three d seismic, which would be the point at which we would no longer have that competitive advantage. And that's the reason that we moved as we did in order to tie up the entirety of the resource. Similarly, as Bob is going to talk to you, the eastern extension of Apun also has better reservoir qualities by our analysis and he'll explain more about that. We have strengthened the Board of Directors and I'll talk through that in more depth and also 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.

9:39 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 U. K. Listing likely not to be an AIM listing, but a whole main board listing. And that's in order not to disadvantage U. K. Shareholders who are holding shares in tax efficient wrappers. We don't want to force you to take your shares out of those wrappers.

10:27 So there will be a period, but in the long run, we will probably be solely listed on a U. S. Exchange. And we have I'll come back to talk a little bit more about that. And then finally, we're going to share with you back to Jay, we're going to share with you our progress towards the planning, funding and permitting of the upcoming development. So with that, let me hand it over to Jay just to talk through some of the specifics and the new data gathered from the LK2 recompletion. Jay, over to you. Yes, well, thanks, David, and hello to everyone, whether it's in the afternoon in The U.

11:15 K, in the morning in The U. S, or in the evening in Asia. We we did, as David said, we recompleted the ALK-two well in the vertical portion in that upper top set. We previously called that the shelf margin deltaic. And this is the this is the market update that we promised everyone after we had done our pressure bomb analysis that we put in after the frac and the test, and and the work done by Geomark on the recombination. There are two key takeaways. The recompletion, we originally said that we had 30 to a 100 barrels per day of of oil, but when we get the GeoMark data and add in the c five plus, it's a 20 to 40 barrels a day higher, so our actual marketable liquids was between 50 and a 140 barrels per day.

12:17 More importantly, though, our top set horizon's permeability, and permeability is is strictly a 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 100 times better than our alkade zone of interest. And permeability is directly related to production rates. And we also had a lot of technical data. Our pressure volume temperature data, PVT, it's 35 degree API oil, that's very important because it's not nice, light, sweet oil, and the gas is even richer than the gas that we found in the lower zone.

13:11 162 barrels per MMcf of c five plus versus 98. We'd also promised the evaluation of our revised frac, and we see that we were about 50% of frac efficiency versus about 20% in the alkane zone of interest. We think we can probably drive that even higher. Our initial reservoir pressure, just under 3,500 PSIG, and a bubble point at 3,500, so we're right at the bubble point, and that's the pressure where liquid start coming out of the gas solution. And a bonus result, as we like to call it, is that we had negative skin.

14:01 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, very much improved, permeability in the wellbore. So, as we've said, this well is in the extreme northeast portion of these top sets, and Bob's going to talk and show you about that. And I'm going to turn it over to Bob next for to talk about the new acreage. Thanks, Jay. So Hello, everyone. I hope you can hear me. So what you're looking at here is a AVO display going through our the pipeline state well through one of the targeted locations called Meggres.

15:07 This is a permitted location that's West of the Hall Road and into our new acreage, this eastern extension of Ahpoon. And I'm gonna focus on just the top set here. So here we have, that's the Ahpoon top set anomaly that was called the SMD in the past. And we've talked about this in great detail in the past. The depth here is at about 7,200 feet and a D max is about, and we've talked about what D max is in the past, which is maximum depth of burial, which is the there's been about 3,000 feet of uplift over here.

15:56 When we go over to Ahpoon East into the top set, and you can see the white circle is showing you where we see these reservoirs present and probably hydrocarbon bearing. We are at a D max of 8,600 feet and at about a drilling depth of about 6,000 feet 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 1525% porosity and five to 20 millidarcys.

16:46 This is an excellent, excellent reservoir. As Jay said, one of the things that was highlighted here was we've tested the top set play at ALK-two. We've actually tested it ALK-two light oil. This was at the very, very, very feather edge of the APUNE top set play. As a matter of fact, when we originally drilled the well, we were predicting very, very thin rows for there. And that's what we saw, but we were able to test it and we got a really good result. What's the takeaway across the board for the Opoon new acreage, that we picked up to the east? One, we have excellent porosities and permeabilities.

17:47 We know this is a large structural stratigraphic trap. The structural component gives us an excellent focus for migration of oil. We're sitting on peak oil generation for the source rock. The top sets, 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. Alkade two, we had a flow test and we have the results from GeoMark. We have not changed our resource estimate. It's still about 1,800,000,000 barrels of liquid hydrocarbons in place, so that's our total resource there.

18:47 We have multiple additional targets in the slope and basin floor fans, and they are under evaluation for their resource as well. So before I turn it over to David again, I just want to point out that on the Kodiak, so here's the new acreage that we picked up for the Kodiak anomaly at this time, we're now showing you the total extent of field that we have at Kodiak. Everything in this acreage to the east, sorry, 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 Netherlands SWOOL.

19:42 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 as it relates to the eastern acreage that is not volumetric, it is in terms of our assessment of the quality of the reservoir that we would anticipate in those top sets in the eastern extension of Lapointe. Is that right? That is absolutely correct. And the reason that that's important is clearly in terms of likely recovery factor and likely flow rates of successful wells into those top sets.

20:31 That is taking it an order of magnitude or two even above what we found from the top set test in the ALK-two well where we moved. If you remember in the ALK zone of interest we were talking about nanodices. So that's less than millidarcys, less than microdices to a point where we're talking about a tenth of a millidarcys in the top sets in the ALKARE2. And here, we're talking about another one, maybe two orders of magnitude higher still in terms of that eastern extension. That's actually correct. And David, 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. We now have 4,000 barrels a day IP30 and 2,000,000 barrels of recoverable.

21:31 Yes. But that's on the basis of what we saw in the ALK-two top set test. It doesn't even get close to assessing what you might see as the results from in the Eastern extension. So our new planning basis is not yet invoking anything from the Eastern extensions or indeed the Updip Western in terms of type curve. We're simply basing it on what we've seen in the ALK-two well that we were able to analyze. So thank you for go ahead. That's absolutely correct. And of course, SLB is incorporating that into their new modeling.

22:18 Yes, yes, yes. So I said to you just earlier, 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. So right now, you'll recall in the past, we've had the Alcade 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 Teletha a well, is it a unit, is Al Qaeda well a unit, a formation, etcetera.

23:07 So we want to simplify so it's easy to understand. So you've got a tank which is Kodiak and we will be seeking to unitize that into a single development area. In addition to that, we've got the current definition of APUNE, the majority of which is in terms of the resources is here in the you can see the red along the bottom. And that is the main body of the oil that we tested in the top set up by the alkade. So it sort of it horseshoes round and it gets better as we move further south. So what we're telling you is having evaluated the well performance in these top sets, we will be focusing our initial development into the main body of the top sets in Hapun, which is why we're envisaging higher initial flow rates and the revised production projections and cash flow projections that we're going to be showing you at the end of this.

24:14 And then finally, the Eastern addition, that next cycle of top sets across, the majority of which sits within our acreage accessible from West of the Dalton Highway, so all part of the same development. And the initial well, you can see that green dot, Maghrej, that's where we would probably drill the initial well that would allow us to demonstrate the producibility of those top sets. So this area and the other area of Apun together will be unitized into the Apun development. And then as I said, the Kodiak will be the other area. And we will seek to have all our licenses unitized into those developments. So we'll be moving forward with approvals on the initially APUN with a view to final investment decision end of twenty twenty five and then Kodiak following some further appraisal with an FID in late twenty twenty eight.

25:22 Okay. I talked about new Board members. We've announced both Allegra and Linda in previous stock exchange announcements, so you're familiar with their background. What I can tell you is that now that we have three independent nonexecutive directors, obviously, Jeremy Breast came onto the board as a designee of Farallon and the Great Bear shareholders. That's now dissolved so 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.

26:18 And that allows us to hopefully build confidence among investors that every decision is being taken with a view to achieving and driving our long term strategy. We have as a result of having fuller complement on the Board, the Board committees, which historically were effectively all the same people on the Board, different people sharing those committees, now have the opportunity to begin to take on personalities of their own and to focus in hard on the issues that match them. Linda comes from a long and storied background as CFO of both public and large private companies and has taken over as the Chair of the Finance Audit and Risk Committee.

27:10 And she will be really focused on the program that drives us towards having the kind of controls that we need in order to be Sarbanes Oxley compliant and to be able to operate seamlessly and efficiently as a U. S.-listed company. It will also should be able to bring expertise in how to close the books quicker. American companies typically close their books quicker than U. K. Companies. There are a number of steps that, that requires. Sometimes it's just a shift in terms of how one thinks about it, how much work is done before you get to the year end in order to be further along.

27:56 And so she'll be working with Justin on making sure that we have a process that will shorten the time frame. This year, we were earlier than last year and next year will be earlier than this year along the way. We have asked Tony Larkin to join the team to lead The U. S. Listing transition. Tony is sitting quietly at the back of the room, and I'm sure we'll be happy to talk to anyone afterwards. But Tony will be project managing and leading that whole process because it's multidisciplinary. It requires all of us to have our butts kicked to make sure that we're staying on track on what is now a fourteen and a quarter month process because we're aiming by the end of the first quarter of twenty twenty five to be in a position where we can be listing on The U. S. Exchange.

28:55 Jeremy Breast 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, was designed for a different time and a different company. We are in the process of replacing the old remuneration plans with a single Omnibus plan that is consistent with market practice. And as we move to a U. S.-listed company, we'll be moving to be compliant and in line with market practice there. The other thing just as a technical point is the move to a U. S. Listing won't crystallize anything in terms of the termination of one plan and start anew it will be a seamless rollover along the way.

29:51 We will be in due course announcing grants for this year. And what you'll see is that the main focus of the Remuneration Committee has been in making sure that rewards are aligned to shareholders' requirements so that the vesting conditions for options will be related to value creating events and the value of awards will be related to share price performance so that the team, both the Board and management are aligned with shareholders that it shouldn't be possible for rewards to management that aren't consistent with the rules of shareholders.

30:39 I will continue to chair the nominations committee and 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 or members of the Board will change and we may need to reconfigure the Board in the listing process. But the most important job from my point of view is succession planning for all 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.

31:33 And in due course, the need for the company will change over time as we move from an exploration and appraisal company to a development company and then to a production company. The skill sets required and the numbers of people in different areas will change. So having a proper succession plan and a proper resourcing plan is critical for that. One of the things that is mentioned just at the top of this slide, Josh McIntyre, has historically been our controller in Alaska, is going to be stepping up to become Group Financial Controller, which will free Justin to be much more focused on the funding and other parts of the Finance Director role. So we'll be strengthening that finance organization and building the controls around it.

32:25 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 that I of Proton Green, which is another company that I'm Chairman of, provided the lowest cost solution because we didn't need to have a whole bunch of common areas of meeting rooms or sorry, non office areas, meeting rooms and kitchens and that sort of thing by being able to double up in share, we were able to save money. But in order to ensure that we handled it right, we went through all the governance process of a related party transaction in order to confirm that it was in the best interest not only at PANTHEON, but obviously I had to do the same thing from the other side for PROTECT on GREEN so that it was handled transparently.

33:45 In terms of the forward incentive programs, the remuneration committee is really focused on looking at the overall package because we're going to have to recruit a number of people as we build the organization to be running multiple rigs in parallel to be running simultaneous development and production operations. And so we needed to make sure we had a plan that allowed us to recruit and retain good people for the long term. And so we will have a combination of cash and restricted stock units for management that vest over periods of time so people have always got unvested rewards in the future that retain them and a continuing rolling process.

34:38 And we will ensure that the plan limits are consistent with U. Practice today and then when listed in The U. S. With U. S. Listed peers. That's the commitment that we are giving you on that. David, you say that it's relatively short break. What does that mean? So a part of typical for U. S. Companies with restricted stock units, you have units that vest onethree, onethree, onethree 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. And typically, it's smaller numbers of stock units than the number of options that you'd have granted if you were granting options.

35:26 But what it means is that they are owners and growing owners over time from day one. Restrictions and beyond just that. Restrictions of sales. So once they're vested and in your hands that you're not restricted in any way other than your belief that the share price is going to 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. The I mentioned The U. S. Listing strategy. So 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 advisers who are going to be implementing the systems and documenting them to achieve something that's obviously compliant.

36:26 And obviously, the legal firm who will be working with the investment bank and Tony, as I mentioned, will be working that program and spending a lot more time in The U. S. During that overall program. With that, let me hand it back to Jay to talk through the ARPUN development planning and where we're at on key items. Thank you, David. And so here we're going to talk about how we plan to become West Texas North. And so one of the biggest items that we have in our well is the cost of the frac sand.

37:17 We paid about 65¢ a pound for the sand that we used in the ALK-two well. I go over all the cost differentials we had, you know, we brought it out of Canada 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. And for each well, we're going to use about 25,000,000 pounds and our target is $0.20 a pound. So a significant savings over, our previous cost.

38:03 And, but it's still a very, very big number. That's $5,000,000 per well. But, and when you think that you may want to have storage for 10 or more wells, that requires a lot of trucks, a very large storage area, significant sorting and mining to do that, in the time period you want to do that. But our operations team is well underway and have talked to all of lots of various vendors on the North Slope and other, and we are confident that we will hit that $0.20 a pound. In Tubulars, we've been talking with current pipe vendors and using standard grades.

38:48 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. And with the vendors, of course, we're talking to many of those vendors and the rig companies about long term contracts. We don't see any current bottlenecks for gas compression, power gen, gas turbines, etc. So we are, we are confident, that we are on our way to making this West Texas North and more like a manufacturing process.

39:40 Now we talked a lot earlier about the recompletion of the ALK-two well and what that meant for us in our development. And 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. And as we talked earlier, these type curves are based on that reservoir data and generate 4,000 barrel a day IP30s and about 2,000,000 barrels a day of EURs. And this is our development plan starting in Q1 of twenty twenty six with a single well.

40:28 We add our second rig in Q3 and we hit about 10,000 barrels a day at that time. In Q1 of 'twenty seven, 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 are easily self sufficient when we get to those kinds of numbers. In the first year, we drilled 10 wells, we've estimated that's seven producing wells and three injection wells. And this is what we are showing the vendors that we are talking to about financing. Also, this will be important for reserve backed lending, for non equity financing.

41:16 And I'm going to turn it over to David to talk through that in more detail. Thank you, Jay. So what you'll see and if you've got a good enough memory, you'll recall when we presented numbers on the basis of what we'd seen in the original ALKARE2 long term test, we were showing a ramp up to around about 20,000 barrels a day by the end of twenty twenty seven. What so our approach to planning has been never to assume anything better than we have already encountered. And that's what the big change here is, 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.

42:17 We're talking about on average build us up to a point at which by the end of twenty twenty seven, 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, is a revised version of the chart we showed you back in November and with the new well type curve. And what it's telling you is that almost as soon as we get into production, the cumulative net cash outflow flattens off to zero further cumulative cash outflow. So the original chart showed that number going to about $300,000,000 negative cumulative cash flow.

43:06 And with this type curve, we think that the total requirement is going to be somewhere just over $150,000,000 using that conservative planning assumption of $20,000,000 per well for the first three wells, dollars 20,000,000 for the production facilities, dollars 20,000,000 for the pipeline tie in and $20,000,000 for general overheads and engineering costs to get to that point. That was the $120,000,000 up to the point of first production. And as soon as you see first production, that chart begins to flatten off. So the scale of what we're trying to raise is not as large as we originally anticipated because we've now been able to demonstrate in a physical test an improved reservoir quality and liquids quality.

43:58 And so just focusing on what do we think the borrowing base that we can support from this would be. Once we get up to the end of twenty twenty six, 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. The 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, the number of wells required to be smaller.

44:48 The key point that I want to get across with this chart is that by the end of twenty twenty seven, we'll be at a point where 60% of some 24, 25 producing wells is going to be around $350,000,000 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 of which we're also starting to think about the Kodiak development, we're not going to have a shortage of liquidity. Now why is that important? Well, there are some people who have been trying to do the maths in their head and saying, well, if a rig can drill 10 wells per year and five rigs is going to produce is going to deliver you 50 wells per year. And if you've got to drill 2,000 wells that's forty years worth of drilling.

45:49 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. And so 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. And 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 moving forward.

47:01 So we're anticipating a situation in which, yes, there's going to be drilling activity on this for the next twenty years in just the same way as there was drilling activity on Prudhoe Bay for twenty years and there was drilling activity on Kapyra for twenty years. But it's not that this is going to take forever to drill out the field. Our initial estimate is that we're aiming for between 200,250 barrels a day of capacity on the current plan by about 2,033, so within essentially seven years of startup. And then the decision will be on whether one accelerates by expanding capacity or continues just keeping the system full, but that will be an economic optimization at the time. You've got enormous optionality in terms of how many wells you drill and what timeframe depending on what the macro environment looks like.

47:58 So what it's telling you is that as we move through first production, we've got a number of steps that are taking us to the point in which we've got a final investment decision on Opun and we start the development and that takes us within about a twelve month period of the start of development to being positive net operating cash flow. And indeed on this type curve, self sufficiency happening sooner than the end of twenty twenty seven, which is when we were originally forecasting it. And that is going to allow us to move more quickly towards full production capacity down the line to between 200,250 barrels per day. So what are we going to be doing in the short term?

48:45 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. And Bob and his team are working with Netherlands Hall to get us to that point aiming at the end of the first quarter. Right now, SLB are working on the detailed development plan, so individual well placements, individual pads, what are the facilities that we need to have in place, how much horsepower do we need for reinjection, how many wells do we need for gas reinjection etcetera. That detailed plan is being developed and that will then be handed on to Netherlands' tool to produce a report on the resources of the Ahuuden development based on that underlying development plans.

49:39 We will be looking at planning the appraisal of all of those areas that require further appraisal for the FID on Kodiak. I can assure you that the state of Alaska is not going to approve a multibillion barrel development on the strength of three well penetrations. So there will definitely be another two or three appraisal wells. The precise timing of that will be a function of funding. And the we will look to drill a well into the Eastern Extension in order to demonstrate the producibility and the fluid flow rates achievable from that area. And that will help us to optimize the order of development in the same way as we move from starting out in the North to starting out in the South in those top sets, how much of the Eastern extension we incorporate into the initial development will be determined by drilling over the course of the next two years.

50:40 Again, precise timing depending on how the overall plan comes together. I know a lot of people were hoping for more commentary on funding. I'm going to just leave you by saying we told you that we would anticipate having the first 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. So you should expect that we're going to be quieter rather 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 rule one, you never go bust because you had too much cash and 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. So we're going to be using those two rules as a watchword.

51:55 We will fund this conservatively. We will make sure that we are always going forward overcapitalized against foreseeable needs for capital and that will be our guiding principle along the way. So with that, I think that's the end of the formal presentation. I think we can, Mark, hand it back to you before Yes, we that's review great, David. Thank you very much indeed. And David, I do apologize, I am muting you momentarily just so we don't get the noise playing back through for the audience online. But thank you very much indeed once again for your presentation there, David, and to the team. Ladies and gentlemen, please do continue to submit your questions using the Q and A tab situated on the right hand corner of your screen. I just want the team take a few moments to review your questions submitted already. I'd just like to remind you recording of this presentation along with a copy of the slides and the published q and a can be accessed via your investor meet company dashboard.

52:48 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 room just to to summarize them or repeat them for the benefit of those online. Can I also ask you please to open up the Q and 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 was submitted during your presentation. And 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. So the answer is under the development plan, we are not anticipating drilling until the first quarter of twenty twenty As to whether or not there will be any drilling prior to that, that will be a function of the funding strategy and I'm not in a position to share with you specifics of that because as I said to you, we'll be sharing more of that both at the end of the first quarter and during the second quarter.

53:58 We do not have sufficient funds nor have we planned to have sufficient funds to go drilling without having completed the funding 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? So the answer is we have when we've shared that target of $5 to $10 per barrel, very specifically the $5 number is arrived at using $70 per barrel for Alaska North Slope crude and planning for a 10% discount from that for the marketable liquid stream that we produce.

54:47 Applying the tariffs etcetera that you would expect to see and applying operating costs, which are too detailed to describe, but it contains a fixed component cost per well, which is around about $150,000 and then a variable cost associated with how much water and therefore how much disposal, etcetera, etcetera. But there's the end result is that at $70 a barrel and a 12% discount rate, we get about $5 per barrel. And at $80 per barrel and a 10% discount rate, we get about $10 per barrel for the range of resources that we're talking about.

55:35 So 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. So we think it's pretty resilient to what we do. When looking at the Kodiak Field and its reservoir system, is it being viewed as strictly conventional or is there potentially an unconventional component being analyzed? Before I hand that off to Bob, the majority of the areas that we previously had on the lease, we've talked about it being unconventional in the sense that it will require completion with long laterals and multi stage fracs. So 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 strategy we're going to use to produce it. But Bob, do want to talk a little bit more about the reservoir quality as we move towards the Northwest and West?

56:47 Yeah. Thanks, David. As we move to the West, and we've also we've already shown this and we've published it, we're looking at substantial reservoir with, better than 0.1 millidarcities, which is usually the cutoff for people use between what they call conventional and unconventional. And remember, we're looking at a system that's up to 1,000 feet thick. And when we were looking at that, we're seeing, in some cases, up to 50% of that reservoir is better than 0.1 millidarcs. So the answer is, yep, to the West of Theta West, a lot of the reservoir is conventional.

57:34 As we move to the East of Theta West, it would be, you know, we'd be looking at it in that terminology is unconventional. As David said, all of it is going be developed using long laterals and multistage fracs. And 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 and you optimize it to make sure that every dollar you invest earns the highest possible return. So the completions in the Far Northwest may look quantitatively a little bit different than in the Southeast, but qualitatively they'll look very similar. Could we give a timeline for next steps and company goals for 2024 and a possible 2025? I think we've covered that.

58:28 The only other thing to add that we know is going to happen in the relatively short time period in addition to The Netherlands will report on Kodiak, The Netherlands will report on the Uphoon development plan and our funding announcement that eighty eight Energy will be flow testing the Hickory well that will come in February, March of this year. From our perspective, if it flows successfully, that's great news. If it doesn't flow successfully, it doesn't influence the areas that we've already flowed successfully from. So in a sense, it's a free hit for us one way or the other. In terms of hearing about financing, I've addressed that. We're still on the same track that we outlined previously.

59:20 Would management entertain a buyout of just the Arpoon field in the next twelve to twenty four months or prefer Arpoon 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. And we are not planning we're not secretly bluffing that we're trying to sell the company while pretending not to. We're actually seeking to maximize the value of the resources reflected to shareholders.

1:00:10 Next question. Having invested around three or four years ago in PANTHEON, I watched and listened closely to presentations where it stated there were around 22,000,000,000 barrels of oil in the Alaska held acreage up for grabs. What happened to the 22,000,000,000 barrels or 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 substantially more than 22,000,000,000 barrels of in place resources. And we have always stated conservatively that we saw between 810% recovery factors in primary recovery.

1:01:02 So the numbers have actually gone up over time, not down over time. If anyone was the person who asked that question, I would invite you by all means if a further more detailed explanation would be helpful to e mail contactpanteonresources dot com, and we'll be happy to clear up any misunderstanding on that front. Would you kindly outline the process required before you're able to book reserves? And once this has been achieved, is it at that stage the industry will recognize value in the ground between $5 and $10 per barrel of oil? Jay, can I hand it to you to talk about what's required for reserves to be booked? And then I'll come back to the second part of the question. Yes, so we have to prove producibility and producibility at an economic rate.

1:01:54 And in addition, there's a lot that goes into that. And then of course you have to have funding available to bring it into production, and those are the 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. So 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.

1:02:44 So 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? I wouldn't want to say the question was, will there be fewer contingencies in the ARPUN report than in the Kodiak report? I wouldn't want to prejudge the contingencies. What I can say for sure is that by the middle of the year, we will still have a contingency around pipeline access because we won't yet have the FERC approval for the hot tap. We won't have FID. So in terms of the specifics, wouldn't like to guess, but it is an independent report and that's the nature of independent reports.

1:03:38 The yes, go ahead. I left two. The first one, please, can I take you back to recovery factors? Yes. So you just stated that we modeled our conservatively like 8% to 10% primary recovery factors. Theoretically, we read that places like crude oil by particularly using tertiary recovery units have demonstrate up to 60% recovery. What is this quality gap between the primary and tertiary in terms of 60%? What sort of is it possible to extend our expectations for second green territory recovery on our field?

1:04:25 Just but 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? Yes, that's fine. In that case, I will repeat it then. I just thought I'd test. So the question was, given secondary and tertiary recovery factors in Prudhoe Bay as high as 60% and our planning on primary recovery basis only of eight to 10%, what visibility might there be to higher recovery factors from our assets? So, the first thing is I very much doubt, in fact, I would eat my hat were I a hat wearer if we ever saw recovery factors north of 50% David, in our can I just interject a little bit since I did have a lot of knowledge about Prudhoe Bay?

1:05:18 So 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 tarmat at the bottom of the oil zone, and the gas cycling, in the gas cap. So yes, the original recoveries were estimated at 30%, but I assure you the reservoir engineers at ARCO and BP and Exxon 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.

1:06:17 But we haven't assumed any of that. Okay. And so our planning basis is that until we see any successful indication of secondary recovery being viable, we're not going to plan on it. That's in much the same way as many Lower 48 fields in The United States have they do move to 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. And so anything at this stage, given that we have no experience of pressure support, communication over long distances of ejection flood fronts, that sort of thing. It would be just pure speculation to bet on anything else.

1:07:19 So sorry not to be able to give you more comfort on that. Just want to pick up a couple of questions from online because there are a heck of a lot here and then we'll come back to the room. Can we go into the detail on the rationale behind the planned U. S. Listing? What's the cost benefit analysis? Which professionals other than bankers, brokers, lawyers and other advisers who are conflicted and will receive fees from the transaction? And then I'm going to editorialize and say, and therefore can't be trusted, are saying that this is a good idea. 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?

1:08:09 Please explain why this is not a huge waste of the Board's time and precious shareholder cash. Well, that's a compound question that I'm going to break down into its various parts. The first is that we don't rely purely on interested professionals to advise us what's a good idea. We also take independent views and talk to potential investors in The United States across multiple different classes of investor, whether it's family offices, whether it's major public equity funds, hedge funds and others. And our view as to the investability of the company is conditioned by that as well as the input from the professionals who were listed.

1:08:59 Notwithstanding that the many of the professionals who don't have an interest in whether we actually do list or not, they only have an interest in giving us the best possible advice, have argued with us the pros and cons of that. There are certainly investors who are unable to invest in an AIM listed stock. Some of those investors are able to invest in a main board listed stock and some of them are able to invest in a dual listed stock more easily than just a London based stock because we're not talking purely about public market funds. To date, think it's cost us what $25,000 or maybe a fraction more. Tax advice. Yes.

1:09:48 So but a few tens of thousands of dollars in order to properly flesh out. How much do we expect it to cost at completion? Majority would be backloaded and fees would be through commissions on any funding raised at the same time as a U. S. Listing. So 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.

1:10:38 And as to why it's not a huge waste of the Board's time and money, I can reassure you that we have not just looked at it from a point of view of is it a good idea from an equity market perspective. We've also looked at it from the perspective of is it a good idea for the company corporately. We are going to be undertaking extensive engagement with the state of Alaska, with the federal government, with local communities and with policy generally in America. And in addition to views as to what the likely impact is on the stock price of the company, There is also a view on how it helps us to manage the risks and ability to get the approvals we need of having a U. S. Personality being based in The U. S.

1:11:26 And that feeds into our decision to be moving forward with this program. Maybe in The U. S, it was in The U. S? It turns out it is for the time being, although obviously Alaska and The U. S, are they really the same thing? The answer is that we want to be both Alaskan and American in terms of how we act. There's a simple question here is what is C5 plus 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 plus 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.

1:12:29 And that's why that's a 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?

1:13:15 I'm assuming that, that question is based on because a major oil company hasn't made an approach to acquire PANTHEON, ergo, they're not interested. And I think 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 two or 3%. And investors, if they suddenly saw a major oil company having gone through the threshold and bought 3% of the company, my guess is that the share price wouldn't be what it is today. And for a major oil company, they don't typically like to start a transaction that they don't know they're going to finish. So the question then becomes, there's probably not a path to a hostile takeover at any kind of a price that reflects where we are today.

1:14:11 The question then becomes, does someone think about making an approach to PANTHEON's Board at prices similar to today are liable to receive a recommendation and shareholder approval. And I don't think we could have been clearer about the fact that that wouldn't be the case. Wouldn't? Wouldn't be the case. If someone came offering $500,000,000 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'd see activity of that nature.

1:15:02 Does that mean that there are no companies interested? The answer is no, I wouldn't think that is a fair reflection of the situation. Mark, you've just removed a question that maybe I can get it back that I was about to get to. Sorry, David, which question was that relating to? Yes, sorry. I didn't take the next question in line because I was dealing with something So more if when a listing on a major U. S. Exchange is obtained, will our shares on the ACC be transferable to that exchange, maintaining the long short status of all share purchases?

1:15:50 I believe that, yes, because what would happen is that existing positions positions will be rolled over. I don't know enough about I imagine that naked shorts would probably not be covered in that situation, but actual short positions would be rolled over in that situation. Sorry, does the Arpoon East top set qualify as a conventional reservoir? I'd refer you back to Bob's earlier answer. It may well in fact, it definitely would on basis of the numbers he shared earlier be recognized as conventional. But would that mean that it wasn't being developed with the completions that delivered the highest return on capital invested, which would likely involve long laterals and multi say fracking, the answer is that it would qualitatively look like the same kind of completion as we're planning across the entirety of the portfolio.

1:16:56 Is Negraes a historical well or the name of PANTHEON's next sapoon well? Bob, you're probably the best historian here. Bob, do you to address what's name of the wells where, or one of the locations where we have gotten permits to drill. That's all it is. And it's at that location, can actually test and also develop the Opoon East from west of the road, so on the west side of the river. So we have a permit for the pad location at Meggres and the 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.

1:17:50 MARTIN will be current shareholder dilution when The U. S. IPO is completed? I have no idea. Exactly, entirely so. So it depends what the share price is at the point that we do the IPO. It depends how much money we raise in the IPO. It depends how much other money we raise in the interim period as divided between equity and non equity funding. When can we expect an update on the chimney? So the chimney, I'm going to ban use of the word chimney going forward because obviously with the additional acreage to the east, it doesn't look like a chimney anymore sorry to the west, it doesn't look like a chimney anymore.

1:18:39 The resources attributable to the 2021 lease sale sorry, 2022 lease sale rather were incorporated into Netherlands' 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. The sorry, okay, we're moving to some different questions. So go ahead in the room. Yes. So in terms of timing of your main market, leads to the main market, would you be planning to do that before or at the same time as The U. S. I think a lot of other companies have done that sometime before, which case Alfie, you want to target later sometime this year for the main market?

1:19:27 Yes, that's a process we're working through. We don't have an answer on that yet. We'll update it back when we know. But I think it's the one thing we can say for sure is it's not going be later. Yes. Yes, of course. Sorry. Just in case anyone missed that, the question was would we be listing on the main market in London before The U. S. IPO or at the same time? And 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 $202,150,000 thousand in What seven would be technically and commercially feasible peak production for a major that is less financially constrained than you? Can you comment Well, think it depends ultimately on the pace of drilling in terms of and how much you expand the facilities in into pipeline.

1:20:24 So the peak throughput of the TAPS pipeline was 2,000,000 barrels a day, but it would be very hard to get back up to 2,000,000 barrels a day. There's a lot of oil coming in from other sources and so there are costs associated with step ups. What would be a likely peak production rate if you think about Jay, you'll remember Kuparuk River was 390,000 barrels a day peak, was it? Something around that, David. And yeah, we actually got over 2,000,000, but that required to use a friction reduction agent. And I doubt that anyone would want to revisit that. So In the room, are people who are imagining what friction reduction agents look like available from all the pharmacies.

1:21:17 But the point about it is that I think the original plan for Kaparuk River was somewhat less than 380,000,390,000 barrels a day, but the economics of expanding the facilities and expanding the throughput justified it. I could quite foresee a situation in which it became apparent once we've got enough production history to know that the length of time that we were going to exceed that two and fifty thousand odd barrels a day would justify the additional investment and therefore we would expand it. If you simply run the maths and have a continuous drilling program, you could end up at zero five million barrels per day. But would that be the optimum economic decision? The answer is there are many factors and a lot more analysis before you do it. But the planning for our initial access into the Trans Alaska pipeline is going to be in that 200,000 to 250,000 barrels a day range.

1:22:16 That's the size of access that we want. So if someone wants to do that, they need to then get You need a further approval for an expansion of that facility. Yes, another question here. Second question, can I take you back to the Afong developments, specifically the testing at ALKARE and even more specifically today the RNS which obviously have a little result of more properly processed? When we presented in November, we had a nice plan with finance and all that kind of stuff. It's been materially altered today or what you've shown, it looks a lot more favorable. How come in a situation three months later, whereby we are making a much more optimistic production?

1:23:07 Is it purely on the basis of what we have back from June? And the pressure buildup. So the pressure transient analysis, to understand the effect David, could you repeat that, please? I'm sorry, the question It was coming out to me. I don't know about others. No, no, forgive me. I should have repeated it. So the question was, we've announced a material update and upgrade of the forward projection compared to just two point five months ago when we showed the start up ramp up on the basis of the Venn type curve for based on the ALKARE test. And the question was what had led to that? And the answer is it's the combination of the geomark analysis of the fluids and the pressure transient analysis using the data retrieved from the pressure gauges.

1:24:06 So just to put 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 faces accessing the reservoir, and that is therefore the width and the height. Now if you didn't have a frac, the only thing that would really matter would be the height and the permeability. In a frac well, it's the area of the frack and the permeability flowing into that because it's now linear flow into that. So the two factors that have significantly improved our view is the frac efficiency. So we now know we can get a highly effective large area in a frac.

1:24:57 And 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. And so when you multiply those two things together, you get a significant increase in expected well performance. And is it pressure ball effectively telling you that's about the permeability? So the pressure gauge so it's the shape of the curve building up. If it builds up quickly, this is a massive oversimplification, but if it builds up quickly, it is generally high permeability. And if it builds up very slowly over a long period of time, it's generally low permeability. The precise shape of that, depending on how quickly you 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.

1:25:45 Sorry, can I make a Yes, please go ahead? Yeah, there have been a number of questions that are kind of bouncing around here. And one is, when we tested ALKADE, we had the ALKADE anomaly, the first part of the test. We had the results and we took those results and we built our models. We had not yet tested the ALKADE2 upper zone. So we hadn't tested the top set. And we had a set of models. Those models were built by Schlumberger and it said, we have an economic development that we can move forward with.

1:26:35 The alkali-two taps, quite simply, again, at the feather edge of the reservoir was saying we had a significant improvement in permeability, like 100 times better permeability than we saw in the ALKADE2, the primary test. That leads you to saying, hey, we can develop the top sets 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 top set that we had under release, we even have better reservoir performance. Now that hasn't been included yet into our analysis, it will be included. And then thirdly, as we move over to Opoon East, we even have another order of magnitude improvement in the permeability.

1:27:33 The point is, we will be adjusting and moving forward as we are proving these models up, there will be changes and it will be changes to the positive side. So what you're seeing today is our best estimate given on the test results that are verifiable as of this moment in time. So our planning basis is restricted to what we have actually encountered, rather than what we expect to be better as we move to the better areas. Correct. What's point there is, gets better going south of pipeline state. It gets better going east to the new And pipeline, we have whole core data through that reservoir.

1:28:33 So the point is, we can expect that there will be further changes, but right now what we have is a fantastic project that is economic at today's prices. David has said, you know, it's we have a good project even at $45 oil. Okay. There's another question in the room here. Go ahead. It's a follow on, David. With regards I mean, hearing that the direction of travel is getting stinky better. And you modeled from initial production test at 50% water cut.

1:29:20 Moving forward into sort of more conventional acreage, can we assume that there's less flow and therefore a better water cut to more oil in the Is it more separation? Let me address repose the question for people online. The As we move to better quality reservoir, will we see a lower water cut than we've assumed or have seen to date? The answer is quite possibly so, but again, it's not something we're planning on and it's not something we're going to speculate on. We're trying to restrict ourselves in terms of statements of data. It's what have we actually seen. We have expectations and we've shared some views as to how things might improve qualitatively.

1:30:10 But to be honest with you, the amount of water is not a major driver of development cost or recovery. It's we're going to have to handle water no matter what and in large quantities, and we have a plan for It might make a difference in terms of amount of fracs and therefore, it's huge difference the Sorry, in terms of number of frac stages. In stages. It's unlikely. The amount the water cut is unlikely to be a factor in terms of the number of frac stages. The number of frac stages is going to be to place the to drain the maximum area of reservoir that can be drained. So how close the frac stages are to each other is a function of the permeability and therefore the pressure communication, are you robbing Peter to pay Paul with one frac stage to another, but the amount of water in there is not a major factor in determining that.

1:31:05 I mean, we can have a more detailed discussion, but no, that's not a major issue. There's another question there. More finance question moving away from the geology. Going forward and consistent with the development plan, is there a plan to engage with investors, institutional investors? And what are the key inflection points that make us more investable along that process? And is that going to be affected by the migration to The U. S. In terms of the investment? Okay. So the question was engagement with investors during the course of the plan, leading ultimately at the end to when we're up and producing. And so the answer is predominantly that the mix of investors who will have an interest will change as we get nearer to production.

1:32:04 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. So this isn't a pure corporate finance game as to where do we think investors will pay the most because there are many investors who, as the earlier questioner correctly identified, they're not governed by where you're holding where the exchange is. Certainly, it's true that there are a lot of people who can't invest in an AIM listed stock.

1:32:59 And so whatever happens, that's probably not a long term sustainable place for us to be listed. But we will be during the course of the next fourteen and a bit months, we will be 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 twenty twenty five? That will depend to an extent on a cost benefit analysis. If we had the main advantage of holding the S. The U. K. Listing is probably for U. K. Investors who have invested in an ISA or alternative tax efficient wrapper.

1:33:57 And so we will take a view if the majority of capital gain, which is the main thing that people are looking to protect has occurred and the continued cost of having a U. K. Listing is not attractive versus the benefits to investors, we wouldn't. And if there is an argument for keeping it, there is certainly no presumption about the timing of when we would or wouldn't lose a UK 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? So I think we've half answered that, which is that we will be reporting on the full Kodiak resource with a better explained basis by we're aiming for the end of the first quarter.

1:34:53 And we're also aiming in terms of the funding, we're aiming to meet the timetable we've originally shared which is by the end of first quarter we should have preliminary news on non equity based funding. And by the end of the first half we should have that the full funding program for our activity tied up. It's interesting that Justin has found another position. Would you keep us updated on the new listing? I don't think Justin has found another position. We or at least he hasn't owned up to us yet. What we're saying is that the current role as the needs of the company expand, I know because I get e mails from Justin later at night and earlier in the morning that is sensible for anyone who's hoping to stay healthy.

1:35:54 What that means is that making sure that we allocate roles to allow people to focus on the areas that they can add most value and in Justin's case, that's being the Finance Director. So having someone else running the overall program of coordinating the different pieces for The U. S. Listing program, it doesn't mean that Justin is not going to be involved in it. It just means that there's someone else who's keeping tabs on top of that. Similarly, it's not uncommon for the accounting and the finance to have some degree of separation or having a financial controller. Justin has been de facto the financial controller for the last more than seventeen years. So, as the organization matures and the needs mature, sorry to disappoint Justin, you don't have a new position.

1:36:52 Alkade II was landed in a highly structured part of the Alkade 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. But the answer is undoubtedly some part of the well performance was to do with how the well was landed because it certainly came out of zone at some point. And with hindsight, we probably would have landed it lower. But the majority of the well performance was a function of the frac design implementation and efficiency. Sorry not to give a more detailed answer on that. When's the Kodiak Netherlands tour report coming in?

1:37:39 We've mentioned we've dealt with that. What can shareholders expect now in return for their investment? Or would it be logical to come back in 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. And if you don't, then you shouldn't. And that is about the extent of any investment advice that I'm going to give to anyone. When do we anticipate UK listing to become defunct? We've answered that. We've answered the question of when would we move from the aims to The UK Main Board. What is our current value per barrel? Well, the market says that we're worth about $0.10 a barrel.

1:38:30 We think we're worth considerably more. That's what we're working to demonstrate to everybody. And we'll do it by doing lots of small and boring things that will lead as I said before to a point at which people begin to recognize that achieving the targets we've set has become inevitable. That's when I would expect to see a value of more than $0.10 a barrel attributable to our resources. Can we give a targeted breakeven per barrel? We've talked about when we run the State of Alaska, Alaska North Slope cash flow model, at $70 a barrel and a 12% cost of capital, we end up at about $5 a barrel.

1:39:20 When you take that down to and that incentive is about an 80% rate of return development from memory. I don't have it in front of me, so please don't hold me to that specific number. But when you take it down to what price gives you a 20% rate of return, which would be a typical threshold for moving forward with the development, that's around $45 per barrel. That's your cost or no? That's the ANS price at which the development gives you about a 20% rate of return, which so that's sort of an equivalent breakeven. Appreciate drilling can't, I think, rather than can begin until finance is addressed.

1:40:06 Surely the company will be actively drilling once finance is secured. Is it safe to presume the technical team is planning to drill Apun East Topset so they can fire the gun immediately after financing is secured? The answer is the team is it's safe to assume the team is doing all the planning necessary for all the activities that the Board considers to add most value to shareholders and that we are certainly not going to wait until we have completed funding before we start thinking about the next thing. We are going to be planning for the range of different things we would do given different timings and availability of financing, but the whole program is built around optimizing value to shareholders. Can we request our brokers not to loan out shares to short sellers? And if they have, can we ask them restock?

1:40:58 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. Sorry, I don't think we've got an answer for that. Have we provided estimates on the slope plan system within our acreage? If not, are we planning to do so? We have historically, 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?

1:41:51 I going to be think handling that as part of looking at the full field kind of development like at Hapun. We know we have the slope systems there, and we're just kind of working on them. So I have no specific target for giving the full sort of resource on the sloped systems. Yeah. Yeah. Okay. The question asked earlier wasn't from this person, but they think what the person meant was, we've previously said 22,800,000,000 barrels oil in place with 10% recovery, so therefore 2,280,000,000 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.

1:42:47 We're anticipating when you add the new acreage and the revised estimates that, that will lead to an upgrade from the 22,500,000,000 barrels in place. We'll be sharing that over the course of the next two quarters in the two major accumulations Kodiak and Arpoon. And what won't be included in Kodiak and Arpoon will be the additional zones that we have incorporated such as Sao Fan and other things. David, I was just going to jump in just to say that for every one question you answer, you're getting another two or three. So just to remind you that there's always the opportunity should they get up, then let me know if we can follow-up afterwards. Okay.

1:43:34 Progress has you made on the tie in to TAPS? Who's responsible for driving that process? At the same time, I'm going to say Pat Galvin, who is our Chief Counsel and Chief Commercial Officer, is driving that process in Alaska as we speak, and we're taking the stepwise process necessary to get to that point. I'm not going to get into the details of it today. There's a question for can we help people to map all of the individual zone names to Apun and Kodiak Fields.

1:44:19 I'm sure we probably can at some point. What I'm going to 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 that 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 Arpoon, the only zones that are included are the top sets and the Alkade zone of interest, which is an oddity that just happens to have had a couple of wells drilled in it, therefore we've incorporated it in. Anything else is not part of that. So all you need to know is that the Apun Field is predominantly the top sets, what used to be called the shelf margin deltaic, various iterations of that, but it is now all of the top sets and the Kodiak Field is the lower basin floor plan.

1:45:21 Any progress to relay about the proposed Alaskan gas pipeline? That would be a matter for the AGDC, the Alaska Gas Line Development Corporation to share. We understand that there are discussions ongoing with potential sponsors of that, and we would anticipate being a part of the conversation given that we have high quality gas along the line of the pipeline that requires less processing than gas from the North Slope. Last webinar, Jay said five or six usual suspects. He did indeed. That's quite correct.

1:46:08 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 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, 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. Lacking. But I feel we're lacking on the Kodiak field. Okay. So there are 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 twenty twenty eight. So 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.

1:47:27 APUNE 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. So if there's anyone who thinks that Kodiak isn't important to us, the answer is you couldn't be more wrong. Kodiak is absolutely where the largest volume is and where the long term production will be supported from. What is Apun? If we forget about Kodiak, I'll assume that's not in a metaphysical sense. Apun is a giant field in round numbers 500,000,000 barrels a day, I think official number four eighty one right now. But when we've done the further work, we will be able to share a number for that.

1:48:16 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 Apun for Christmas. Apun is a giant and valuable field in its own right and more valuable in the sense that its proximity to the infrastructure allows us to build cash flow incredibly quickly to accelerate the development of the overall program. So it has its own value that would show up in the $5 to $10 a barrel range, but it also has a multiplier effect on the value that we can bring to Kodiak. The upgraded IP30 figure 4,002 is an average number over the first twelve months, a massive upgrade.

1:49:02 I have in mind the previous guidance was 1,500 to 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 top step 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.

1:49:57 Part of it is because the GOR in the alkane 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 1,700,000,000 barrels 1,780,000,000 And then at the 481, that's where you get the 2.2 odd billion barrels.

1:50:42 We will be providing updated numbers in due course. What is the current cash available and current monthly burn rate? Justin, do you want to talk a little bit about that? Yes. We announced at our year end, we announced that we had about $8,000,000 just under $8,000,000 in cash. And if you recall, there was a placement an equity placement with deferred terms. That money is presently in the process of being collected by the company, and that's about another $4,000,000 or just a little bit over $4,000,000 So that's where we're at. In terms of cash burn, our G and A was around running around $7,000,000 That will naturally increase as we move towards The U. S. Listing with additional costs, but that's a fairly representative number.

1:51:31 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. Bob, is there anything more you'd like to say about Kodiak? Well, just wanna say, the presentation on the Eastern acreage was just to say, this is the work, the new work that we've seen since the last webinar, which was highlighting the quality of the reservoir we expect to see in Apun East.

1:52:16 We are working on Kodiak now and within two months, we expect to have like a major major update on Kodiak. But I'll remind you on the last webinar, we are showing a significant improvement in the reservoir quality as we move to the West. What that all means, we're hopefully have that answered for everybody by the end of the first quarter. Line is, have the currently drilled and completed wells all being plugged and abandoned or are some of them planned as producers I'm going to add in ore injectors? Similarly, will the forthcoming appraisal wells on Kodiak sub facility plant be planned as producing It is not all the wells have been abandoned, but ultimately are likely to be. We are hoping to use the ALKARE-two well as an injector.

1:53:18 But 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, but that's not a basis for planning. Are there any more questions in the room? Erwin, yes? There was one quick question. In the last Canaccord note, they drew attention to helium. Did they? Somebody brought that. Oh, do you know what? There was so I think That was a podcast, the Chuck Gates Needs a Job podcast. And I'm sorry, there was some editing of that which created a rather misleading because 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.

1:54:21 At the end, he as he's starting to wrap up, because he'd originally intended that we were going to talk about both companies. As we started wrapping up, I simply put a placeholder for him. Don't forget, we were going to 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. I assume it was all still there. God. I yes, no, no. I mean I can absolutely assure you Proton Green is 100% focused on producing helium and carbon dioxide. PANTHEON is 100% focused on appraising and developing oil. And so it actually anyone who assumes that statement was to do with PANTHEON, I know I saw Paul corrected that in online for a few people saying, think those people have got there a bit garbled on there.

1:55:21 Neville, yes? David, I'm going to ask a very tough question. Please. That is, if the world goes to hell during 2024, as it just seems to be aiming that way, we are not able to get financing. When we look at this project as is, let's say you'd have to put it into auction, we cannot get financing. What would you say the value of the asset as it is? What do you think we can get for it? If you could if you were to try and sell it today just as is where it is? The way it is very far. I wouldn't want to speculate on what that might be. It would certainly be less than we would get if we were to get development.

1:56:09 If we I would have to take advice. If we were to put the company up for sale today and people knew that the company was truly up for sale, what price would we get compared to people making speculative offers? I don't know is the answer. That's What is the price of wild in the ground? Today? In the ground. There's no individual price that you could apply sorry, there's a general price you could apply for oil in the ground. The market'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. But I don't have a good answer to you. It's a great question.

1:57:06 For anyone who didn't hear the question, the question was if you put the company up for auction today, what would it sell for? And I don't have a good answer for that. I'll hold my hand up and be honest. There was a in the ground oil deal in Alaska not that many years ago, Paul Armstrong I think. Yes. Yes. But And I think the valuation is 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, the buyer might have said there were this number of barrels. So the number could be between $1 and $3.10 But that deal did go through. That deal did go through. And so the question is where is marginal buyer today?

1:57:54 Was that a stroke of luck? Was that a result of strong competition? There are quite a lot of unknowns that would make it unsafe to definitely read across. As to what the precise number would be, I just don't think I've got a good answer for you that I would feel comfortable was credible in terms of its foundation. And I always said to you, I'll tell you the truth when I know it 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. Could the recent share price performance of another UK company with U. S.

1:58:43 Assets listed in November of last year, share price performance has been haven't been good. Does that make PANTHEON a tougher sell or are you aiming for a different subset of you potentially less investors than that? I don't think we look like the company listed. I think every so the question was, is past experience of U. K. Companies relisting 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. And what I guarantee is that if we need money, then we're less likely to achieve success than if we don't need money.

1:59:36 The objective here must be to 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 rock hit, hoping we both get our wishes. So 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're now automatically redirect you for the opportunity to provide your feedback in order that the company can better understand your views and expectations?

2:00:24 This may take a few moments to complete, but I'm sure 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 you all.