Pantheon Resources (LSE:PANR) — Investor Update

0:01 Good afternoon, ladies and gentlemen, and welcome to the PANTHEON RESOURCES Investor Update. Throughout today's presentation, investors will be in listen only mode. Questions are encouraged and could be submitted at any time just using the Q and A tab situated on the right hand side of the screen. I'd

0:31 participation. I'd now now like like to to hand hand over over to to chairman, Chairman, David David Hubbs. Hobbs. David, David, good good afternoon. Thanks very much indeed, Mark, and thank you, everyone, for joining us today. Today, what we're going to do is explain the outcome of the mega as well. We're gonna explain why we drilled it. We're gonna explain why we thought we had a discovery on the basis of the data gathered prior to testing. We're gonna explain the well results. Then we're going to move to talk about the plan for development of and moving the company to cash flow. We're gonna explain why the w well will be the next well to be drilled. We're gonna explain its linkage to the gas sales precedent agreement and moving that forward into a full gas sales agreement.

1:20 We're gonna explain how that links into our plans for a US listing and finish by talking about the overarching strategy of the company going forward. And then we'll answer those questions that we didn't already address during the course of the presentation. So let's let's take a quick step to talk about why did we drill MEGRA as well. A number of people have have submitted questions directly to the company ahead of the webinar, and and this was a a common theme. Two reasons, really. The first, it was a very high quality prospect that could have materially improved the development economics of the overall Aupun development if it had been successful.

2:09 Second was that it allowed us to drill from a gravel pad, which meant that we would have real estate available for development activities even while the environmental regulatory process was proceeding. That is part of the reason we're able to be confident about having a short flash to bang time between approval of the development to proceed and first oil. So based on the risk versus reward and the impact it would have on the wider portfolio, the board decided to move forward with that well and much easier with hindsight. But but at the time, the decision was strongly considered to be the right decision to move forward. And so we, did, build the pad. We drilled the well. We raised the funds to drill the well.

2:59 And, incidentally, the funds we raised included for testing so that we were in a position to complete that program. We then during the course of the period between drilling and while we were analyzing the logs and cores and cuttings data, we

3:20 restocked financially, raising the $35,000,000 bond with Sun Hung Kai. And that has provided us with the runway going forward and and a stronger cash position than if we hadn't obviously raised that money. The data that was gathered indicated high oil saturations. It indicated that there was a great likelihood that we would see positive oil flows, and we released those announce announced those results of the simulation and the ranges that we expected to see flows. Then we proceeded with the flow program. And at this point, let me hand over to Max to to take us through the entire story both corporately and and in terms of the specifics of the macro as well.

4:09 Thank you, David, and thanks again to everyone for joining us today. We're gonna save a lot of room for q and a's today, so this will not be forty five minutes of exhaustive, presentation. So I think what what I would start is the investment proposition. This is almost exactly the same slide that attracted me to PANTHEON just two short months ago. Only three things have changed in the two months. One of those, of course, is the outcome of the mega as well, which talks to the upside potential of it that David just mentioned. The second one is we've secured a much stronger financial position due to the convertible bond, SHK. And the third one is the news flow around the company continues to, improve further. More positive news from the federal government and state administration promoting a gas line in Alaska, in general. So the key point is the 2,600,000,000 barrels equivalent resource remains intact.

5:09 And as we went into Meggres, we were focused on testing Meggres as well as progressing the primary business case, which, of course, was the path to commerciality for APUON and and ultimately Kodiak. So the mission or the the point here is the investment proposition remains almost exactly the same. The only difference here is how much upside did Meggres represent in the overall development plan. So speaking of Meggres, so when I arrived two months ago, the mission was, an apparent discovery with 1,340 feet of net pay. What's the most capital efficient manner of demonstrating its, flow characteristics in ultimate, commerciality?

5:54 The outcome of this, to be very blunt, is, we encounter no appreciable hydrocarbons in this well. No material oil production or gas production at all, which, in some ways is still a mystery, but we think we understand the mechanism, at this time. So so when we went into this, the original plan, as you will recall, was we didn't feel the need to test top set three because the top set one result would be indicative of the two, and that turned out to be a wise decision in retrospect. But the plan was to successfully and systematically go through six horizons to each individual interval for its commerciality. So initial test was TOPset one. The results were released on April 14.

6:39 The outcome of that was twelve days of flow testing following hydraulic stimulation, during which time we produced essentially no hydrocarbons. No no mobile oil or or gas came out of the well. So the outcome of that was, obviously very surprising given the oil saturations we encountered in the logs, the cuttings, and ultimately, And so question was, why was there no mobile or hail? Is it simply there's no mobile oil? Do we have a wettability problem? So I launched a number of tests to figure out what was wrong with this horizon and was it indicative of the horizon's more shallow. So at that point, the objective was to move to Lower Prince Creek, which at face value was a more perspective interval.

7:25 So higher oil saturations on logs and cuttings than the TOPset one, and we had the benefit of a direct core measurement this time. So direct core measurements from TOPset 1 and Lower Prince Creek, which showed oil saturations greater than 50%. In any normal petroleum system, you would expect to have mobile oil with oil saturations that high. So we're waiting for our frack crew, and we've we've talked about this many times, about the availability of that is really dependent upon the activities of other operators, especially in the spring season. But to complete the well all the way to the top of Sag 3, we recognize we needed to add cement to the annulus in the casing per state regulations.

8:10 So while we're waiting for the fracker, we chose to do that and successfully, submitted that to per regulation. Because we're concerned about the wettability of top set one and associated impact on oil saturation and mobility, we decided we would do a conventional test at Lower Prince Creek before expending the money to hydraulically stimulate it. If we get hydrocarbon on a conventional test, that would give us the confidence to move on and and fracture it and move on with the program. So we produced the well for a number of days at about 200 barrels a day of water per day being nitrogen lifted and, again, got zero appreciable hydrocarbons. So now we were concerned that, this was going to be a repeat of TOPset one.

8:59 So rather than the doing the expenditure of hydraulic fracturing and getting the same result of TOPset one, at that point, it was decided to test the viability of the system. So rather than going through sequentially all five horizons, if it didn't work in the most prospective horizon, sag three with the highest permeability and the highest porosity is very unlikely to work anywhere in the well. So after we issued the release on the nineteenth showing results of the Prince Creek being a 100% water and no appreciable hydrocarbons, we immediately moved to moved to lower SAG three. And although we got a a very high liquid rate between two and three thousand barrels of liquid per day, it was essentially pure water.

9:45 So at that point, it became clear to to the company that all of these horizons had one thing in common, which was there will be no mobile oil moving into the reservoir. So that time, rather than spend enormous amount of shareholder funds to get the same result in the other horizons, we decided to suspend this well indefinitely pending further review of why is oil not mobile and would there be a development potential for this in the future. So the outcome of all of that is there's no there's no question there's hydrocarbons in the system, logs, cuttings, direct measurements, of course. But it's also equally clear that it's not mobile using primary depletion.

10:31 So either through a fracture stimulation or conventional flow, we never, at any of these intervals, had appreciable hydrocarbons. So our guidance at the moment, there are no commercially recoverable reserves in this well, although it is a a fully charged system. Down the road, is there a possibility of of producing this through other means?

10:53 Possibly, but not in the short term and not through conventional means. And it wasn't the best use of shareholder funds to do those sort of experiments, with a live rig and live equipment on the well. So we're gonna park this for now and move on to the primary business plan, which is move on to Ophoon and Kodiak. So there's a million questions about this, the details of the assessment, which we'll get to in in the q and a. But the blunt result is through all of these intervals, we achieve zero oil and gas production despite a very robust charge system. So the resource position, it remains. So Kodiak and Uphoon West, now just Uphoon, account for nearly 1,600,000,000 barrels of certified 2C resource.

11:43 So the plan from here is to get back to the primary business plan to continue it and drill a demonstration well in Uphoon

11:51 because there's plenty of analysis, vertical wells, flow tests, simulations that demonstrate the viability of this reservoir and associated type curves for the wells. The next activity for us is to drill a horizontal demonstration well with a modern completion and demonstrate the type curve underpinning, the business case.

12:14 And in in time sequence, it looks like this. So, again, not a lot of difference what you have seen before because Meggres was never part of the development program. It was it just represented upside, and even in a success case, would have been to the right of the time sequence on this chart. So Joel in testing Meggres has already occurred. We know the results. So the next primary activity for us is that demonstration well, and then the regulatory process and tie in considerations into the TransAlaska pipeline with an FID in 2027 for.

12:50 So, again, nothing has changed in regard to our primary business plan. Just just dwell on this for a minute because a lot of people have questions about, well, if Meggres has this issue,

13:04 would the rest of our, prospect inventory have the same issue? So on the far right of this diagram is MEGREZ one, and those little yellow blobs are the top sets that we were targeting originally, as David said, to add, APUON inventory. Above that would be the sag horizons. What's in between those and our Ophoon West and Kodiak is the regional seal. So that regional seal is a trap mechanism for our certified resources in Ophoon, then down below for the Kodiak fan. These are on the other side of that. So it is a different petroleum trapping mechanism, and, there's no impact or resemblance, to the assets, to the West. So we'll have lots more questions about that, but this was not an appraisal well of up on West or certainly not an appraisal well for Kodiak who's testing an entirely different, reservoir architecture.

14:05 And other things, you know, news flow still remains quite positive. Our Alaska LNG project is moving forward. The governor of Alaska quite recently announced his intention to have first gas production, during the Trump administration, which is within three and a half years from now. That'll be a spectacular outcome for everyone.

14:25 But the point is the news flow continue needs to be quite positive and a lot of growing, optimism that, through trade negotiations, Alaska LNG will be part of that enabling this project to occur. So, again, nothing negative has occurred in this horizon, and, of course, we will be a big part of this. And, again, news flow is great. Totally really the difference between us is beyond the fundamentals of the project. Again, given the strong desire of The United States to balance trade in particular with with Asia, this project could be a huge part of that. And I think you guys are aware of everything else. So I think it's probably time, David, to to get to the questions. I know investors have a million questions about the details of the need of payment, so let's just get to that.

15:15 Yep. Absolutely. And I think I think that sorry. The light's just gone out. That's there we go.

15:21 The so I think I think that the there are a number of questions that are all all around the same thing, which I think is worth going back and restressing. And and I I think, Max, if we go to the the cross section, actually Okay. Let's talk about it. So so there are a lot of questions relating to whether what we've learned tracks across. I think you've already explained why

15:46 the MEGREZ test well is of a different geological sequence, but I think we can we can go a little bit further to say that the difference in the resources below the regional top seal, we have flowed oil in those resources. We've demonstrated not only the mobility of the oil, but in terms of the tests in the ALKADE 2 well, both into the ALKADE zone and into the top set further up in the ALKADE 2 well. We've demonstrated mobility of oil and, on the basis of the analysis,

16:18 the ability to produce at rates that would be commercial. That's the reason that in their analysis, you know, they went back to fundamentals and and came up with the type curves, therefore, the recoveries and the economics that they did. In terms of the w well, therefore, Max, do you wanna talk about what the w well is aiming to drill into and to prove? And then we can talk about how that links into the gas sales agreement and the onward development plan.

16:52 Yes. The interval of Hapun West, which would be Southwest of the Meggres location, It's the heart of our our near field. And the pipeline state one discovery well is in that reservoir interval. So, again, this is a demonstrated part of the reservoir. So the intention of w one is to drill horizontal well down the heart of this reservoir.

17:16 And at its thickest, it's about 500 feet thick. So we'll drill a horizontal well through the thickest part of the reservoir with a modern completion. And with that, we will establish a type curve, which will underpin the economics of the the full development.

17:34 So the way that links into the the gas sales arrangements, people will remember if they if they saw it and and will be hearing for the first time if they didn't. When Ryder Scott did an analysis of the resources to confirm to the state that we were in a position to offer the gas that we were offering, they talked about the need for a show me well that they could see the analysis that supported the high likelihood of being able to provide

18:10 associated gas along with the oil production at rates that would meet the contractual commitments. And in fact, they confirmed that they could see a path to doing so, but they also, in their statements about additional appraisal requirements, talked about the absence of a show me well, and that's that's the purpose for the dummy commercial demonstration well. There is some questions around what does what would a failure of dummy mean? I think we can there's a fairly simple answer, which is if W fails to support the case for the ability to provide commercial rates of gas, then it is highly unlikely that we will be more moving forward in the very short term into a gas sales agreement.

18:56 What is the likelihood of that? Given that we have multiple penetrations of the target horizon and we have flowed to demonstrate movable oil, we consider that to be very low risk. It's a different risk than the risk that as to whether Meggres would flow because as we always said, it's a prospective resource until you bring oil to surface. That's the reason that we've never talked about Meggres being more than a prospective resource, and that what would convert it to a con a a contingent resource would be successful flow testing. That didn't happen.

19:31 So the the risk profile on the WL is an appreciably different quantitative and qualitative risk than on the Meggros flow tests, and that well is certainly one that we are aiming to complete this summer in order to keep the gas pipeline project on track. There are some I think there are a number of questions around communication, Max, and let me let me just reiterate reiterate what I think you summarized earlier starting from the original from the last webinar four weeks ago. What we talked about what's happened since then, and and correct me if I get any of the sequencing out, and to an extent, it's a reiterating of of what you've said. We plugged top set one zone.

20:23 We reviewed the cement bond log. We had at the webinar said that we were not sure whether we would be cementing before or after the Lower Prince Creek. It would depend upon the cement bomb log. We talked about the uncertainty of whether the frac equipment would be available in the short or the longer term and that we would therefore

20:47 try and match the program to minimize the amount of dead time that we that that we wouldn't just be standing around waiting for the frac equipment. And I think from some of the questions, it's not clear if if the difference between the different pieces of equipment are

21:08 self evident. We have a rig, which is the ability to run pipe in and out of the hole. It's the it's the pulling unit, for want of a better description. We have the frac spread, which is the high pressure,

21:22 high rate pumping system. That's a totally different set of equipment. And then there is the testing equipment, which is the temporary flowing vessels, the separator, the tanks, etcetera. And what we were waiting for was the high pressure pumping equipment. There was there was no change of the rig. The rig was what stands over the well and and what allows intervention down the hole to run plugs or to perforate or or whatever else along the way. And the temporary testing equipment, including the nitrogen lift equipment,

21:58 So there was no issue about the availability of the testing equipment and the nitrogen lifting equipment nor of the rig to be able to intervene in the well. It was purely the high pressure pumping equipment that in the event has not yet been released to us. Now having run the the the cement squeeze to ensure well integrity, the first step ahead of

22:24 a frac, particularly where you've got if you've got a very tight horizon, there's very little point in doing a pre frac test of the well. But when you've got a higher permeability horizon where you can get useful information for planning and optimizing the frac, it's not uncommon at all to swab and do an initial inflow test to see what you've got and then to frac. So at that point, we were still fully expecting that following that initial inflow, we would be getting the frac equipment, and that that test happened in preparation for fracking the well. It was only once we didn't retrieve any appreciable amount of hydrocarbon that the decision, as as Max said, was taken not to invest the extra money in a ten, twelve, or longer day flow test having fracked it and to preserve capital for what comes next, which is obviously the the program around WN and moving forward.

23:27 That actually all occurred on Friday, Saturday. The earliest we could release was on the Monday morning. And at the time of the release, we were perforating and just starting to flow test the shallow zone, the SAG three. So there are a number of questions about why couldn't we have announced it all in one go. As you're aware, again, we we were required, but also committed that we would release each result as it became available.

24:03 And the opportunity to have announced that we weren't going to have frac equipment coming on onto the well occurred over a weekend. So we we didn't put out two announcements at the same time, one saying frac equipment's available, and then another one saying, but we're not gonna use it because the initial inflow test has demonstrated that it's not likely to flow appreciable hydrocarbons. So completely understand from the outside how the timing of things appears not to have followed the philosophy of what we described, but as the as it unfolded,

24:40 the the steps happened in the order that we expected, I I will hold up our hands and say that it would have been possible to have announced that we had done the cement squeeze before fracking the Lower Prince Creek.

25:00 And and I I accept that with hindsight, that would have led to less confusion about operations. But to be honest with you, we didn't think that the order of squeezing versus the flow test was significant or or material information.

25:21 Of course, with the benefit of hindsight, people will weigh differently how material they think that information might have been. Is that consistent, Max, with Yeah. The only thing I would add to this is following the result of t s one, we were still quite surprised that we got no oil, mobility in that well. So the question was, is that an outcome of the reservoir, or is that an outcome of introducing completion fluid? So you flowed that well back twelve days, which we felt was was ample. It's still that lingering concern. Did the frac water have an effect on the reservoir? And so when we swab and lifted the well, the the intention there was to get a salinity test, produce mobile oil, and then bring in the frac crew.

26:08 By the time we had that result, of course, after just a few days of testing, there's no need for the frac crew. We issued the result itself, but the interval was not perspective. And the outcome of that, of course, was the reservoir itself was not perspective. It wasn't the frac water in retrospect. Yeah. So numb in relation to that, Max, there are questions around the logs that were run, what was it that gave us confidence in the, the likelihood of of mobile oil, and our confusion as to why there wasn't mobile oil in the, in the initial tests. It's it's really, measuring one interval versus the other rather than an absolute. So Lower Prince Creek showed better reservoir properties both in terms of the CMR, NMR, which shows mobility of fluids in the reservoir, but also the perspective oil saturation.

27:02 And then, of course, we got a direct core measurement, which showed that the Lower Prince Creek had higher oil saturations than than T S 1. So it was clearly a more perspective interval. It wasn't a guarantee that it would flow mobile oil, but it was definitely more prospective than than TS 1, which is what gave us the, confidence to move forward and test that interval. The someone's asked a a similar sort of question that we we think that there's water I mean, sorry, oil wettability, but it could equally be a failure of a fault so that oil has just migrated out. I'm not sure it's it's an either or situation that it it's it's both end. Do you wanna expand on that a little bit? Because we covered this in the in the last webinar about, well, wetability and raw perm.

27:51 But in essence, as applied to this situation, if indeed this is a fully oil wet reservoir, the saturation you require to make oil mobile will be higher than a water wet reservoir. That may be singularly the issue here, but it could also be that we don't have a seal on this reservoir, And these are all migration paths, and what's left behind is residual oil saturation. And if it is indeed oil wet, the saturations would be higher than you would see in a water wet system. But And I think I think right. It's an and. It's not over there. Yeah. Exactly. And and I think the other thing is it would be easy to have the impression that oil wet versus water wet is a binary switch. It's actually know, you start at one end and which would be a 100% water wet, and it gradually becomes more susceptible to oil wetness. And and so it's not it's not as simple as there's a binary switch. All reservoirs are either one or the other.

28:53 It's it's a gradational thing. Can you talk a little bit about other reservoirs that have been oil wet and and have been producers? There's a bunch of them around the world. It's usually associated with carbonates. So I don't know all the, reservoirs in The Middle East by name, but in The Middle East, there are quite a a number of oil wet reservoirs. I believe the Wilcox Field in Oklahoma is. There are others. But being an oil wet field does not mean nonmobile fluids. You can if you have a 100% or a very high, high, high oil saturation and it's a little wet, it just means you ultimately will produce more water and require tertiary mechanisms to get ultimate recovery like c o two and things like that. So the they're rare, but they're not super rare. But but don't read that an reservoir means a nonperspective reservoir.

29:45 It just means that the relative permeability between oil and water will be different at different saturations compared to a water wet one. Yeah. And and back to when we when we in the press release on the May 19, we thought initially it might be a transition zone. I think partly because we saw higher oil saturations above it, and so it's possible if it was a continuous column that what we were seeing at the bottom was was lower saturations moving higher. But, subsequently, it's it's clear that we didn't have a single hydrocarbon column. Do you wanna talk a little bit about about the the independence or or linkages between, columns? Yeah. I think the, initially, when you're in the deepest part of the reservoir and you have higher water saturations or immobile oil, it's either a migration path or a transition zone. And the way you test that, of course, is you go up the wellbore.

30:42 You you wouldn't have a transition zone all the way to top of the reservoir. So so that's why we kept moving up to wellbore. And I think I would say pretty confidently that it's not a transition zone because to be transition zone, you have to have a free oil phase at the top of it, and we certainly never discovered that. But when you're in the deepest part of the reservoir, that is a possibility. But at this stage, that seems quite unlikely now that we've tested all the way to the top of the reservoir. Yeah. Yeah. I think I think that, at this point, that's the majority of the questions around Meggres. Let's let's move on to to Dubby. If we're if we're in the Dubby well, are we going to drill a pilot hole to to choose the optimum landing zone?

31:32 We're scoping the well right now. And if so we're not prepared to to describe the entirety of the well design, but that is a standard thing to do when you enter a new horizon. Because we drill into the reservoir horizontally, it's very difficult to establish lithological control where you are in the reservoir. So the wisest thing to do is to drill a pilot hole first, pick the most perspective interval, and then, land in the reservoir. So I suspect we we will do that, but, we'll announce the the full design and intentions, in due course. And in terms of the geometry of it, again, roughly not not a commitment subject to, as you say, describing the full design. How long a horizontal or lateral?

32:19 I would say as long as practical. So, again, we'll do the final well trajectory and and design and in due course and and convey that. But I would say it's between five and ten thousand feet, the lateral. Okay. What are the objectives for the well? The ultimate objective is to establish a type curve. And so first and foremost is land the well, land it successfully, do modern completion, and extended flowback to, a, get a, established type curve, but, b, understand our fluid properties better. And so the, PBT and concentration of gas, natural gas liquids, and oil to emanate from the reservoir fluids, which helped us not only design our facility facilities in a capital efficient manner, but also underpin the gas contracts.

33:08 The in terms of costs of a well, and I think it probably links into our funding rather than separating those questions. Do you want to address that? Again, it just sort of depends on the final scope of the well. And once we do that, we'll communicate that. But in broad terms, a horizontal well would be on the order of 10,000,000, and a completion would be on the order of 15,000,000. But once we get the final, scope of the well defined in contracts in place, we'll have a more precise figure and an AFE generated. And it was for I mean, it was with an eye to that, the the additional funding, was lined up, ahead of, the testing on the mega as well to, put ourselves in a strong position financially so that we were resilient to the outcome.

34:01 That brings us on to financing questions. A a key part of our financing strategy, I think we've announced in in previous webinars over the last eighteen months, has been to look at the range of opportunities to minimize dilution shareholders. I think don't we've ever said there'd be no dilution. We've said there was a possibility of achieving that, but our strategy was to to seek to maximize the retained value for existing shareholders. That continues to be the case. And and if you remember at the start back in late twenty twenty three, we said we were gonna explore vendor and off taker and potential strategic partnerships as the path forward.

34:48 During the first half of twenty twenty four, we announced that our strategy was to focus on the offtaker financing as a result of the gas sales precedent agreement with AGDC and Alaska. That continues to be a key part of our strategy, so no no change there. At the same time, we've we've previously said we have investment banks working on pre US listing funding in the form of of strategic transactions, whether that's farm out or or other asset related transactions. And the sums necessary to get to the to FID are consistent with what we previously announced that that from where we are today, we think it's going to take about a $150,000,000 from FID to first production. We think that the maximum cash draw after first production to get to self sufficiency is about another 150, so 300 in total. And we've talked about the amount necessary to get to FID, the vast majority of which is covered because it's the the step that we talked about was the need for this w or the the upper end demonstration well.

36:11 The so I think that probably covers as much as we can say on any of the specific financing questions. In terms of progress on environmental and regulation and connection into the TransAlaska pipeline. Max, do you wanna talk about the the work program that's been going on to move the development planning forward? And one bit of very good news this week is everyone is worried about the regulatory path to putting gravel pads on the tundra for developments. So we recently received our permit from the US Corps of Engineers for the w one pad. So that's a a huge success for us in terms of well preparation.

36:59 For the Trans Alaska pipeline, we're in negotiations with Aliesca on that. So we have a location identified. It's now a matter of engineering to, achieve the goal of a hot tub on the line, but no new news there, but no showstoppers in sight to to achieve that goal at this time. Are we going to have to sorry. Have have we booked, fracking equipment for the w l? Not just yet, because we don't have the window to do it. And and strictly speaking, we may not use conventional frac equipment on the North Slope either. So we're gonna consider what hydraulic horsepower equipment we need when we want it. And the window for doing that is too far away to contract specifically because, people have very narrow windows for these things.

37:51 So once it becomes clear what the drilling schedule and completion schedule are, we'll we'll book that at the appropriate time. But, certainly couldn't do it at the moment. We'd have to have a sixty or ninety day window at this point. Anyone would be prepared to blackout that long of a horizon for their equipment. Yeah. But we have begun steps logistically to secure the sand, etcetera. So there there's sort of a a a multidisciplinary planning process to make sure that all the pieces come together at the same time. The that's that's underway. The what effectiveness, I think probably that means efficiency of frac are we expecting with the w? Well, I I would point just back to we saw the alkade zone frac efficiency calculated out at about 25%.

38:47 That in the top set, we saw a better than 50% frac performance. Our modeling has been of the type curve has been based on not doing much better than that, although we would expect typical frac efficiencies up near three quarters to 80% when when compared to other basins and and use of the most modern frac designs. The I've I'll let's see what so we've addressed whether the w l has an impact on the gas sales agreement.

39:35 The there were a number of questions presubmitted that related to the sag test. Obviously, that's not relevant given the news that we announced this morning. The we've we've addressed why we targeted ahead of development. Timelines, Max, I I I think you've sort of partially covered it. Timelines related to progress on the pipeline, you know, where our aim is not to be the laggard in terms of being ready for in terms of when FID for that might be taken.

40:23 What what is the scope if our gas isn't available for the pipeline to go ahead without us? Well, that's a question for the pipeline operator, I think. We're the only source I'm aware of that can ship as drawn in that pipeline. Everything else requires some degree of acid gas removal. So I so I think that we partially dependent on us, but they would be seeking alternatives, I'm sure. But but I think we're their preferred supplier. Yeah. And I think I think that while Point Thompson has probably guessed that would meet the pipeline specification initially, there's there's additional capital not just for the for the spur to get to Point Thompson, but also that development has is is a gas field with condensate rather than an oil field with associated gas.

41:21 So the economics of that development probably mean that it would be very difficult to provide gas at the price that that our gas would be available. So AGDC have announced that they are making provision for backup gas in the expectation, incidentally, not that it's instead of the and Kodiak gas, but it's the to increase reliability of the system overall to make sure that there's there's always gas available. The what are we going to do to rectify the mistrust in the market around board of directors' decision making, how does that affect our our plan going forward?

42:15 Is that a question for me? I well, I think it's for both of us. I was I was I I mean, I was just contemplating what what the I mean, the the correct answer is by continuing to use the best available information to consider it carefully to and and to deliver on what we say we're going to deliver. I think it's worth pointing out that that operationally, over the last two years, we've delivered operations in the time frames we talked about delivering them. We can't control geology. We can control what we what we control. There's no doubt at all that the, you know, the outcome of the mega as well came as an unwelcome surprise. But, Max, do wanna talk a little bit about the peer review and other things we did to to assess before making announcements?

43:12 And and and then I I might just contemplate what the alternative would be if we hadn't shared the data and analysis as presented to us by experts. I I will start with the opening question. I think it was two months ago I was asked that very question, and I joined this company to get on the path of commerciality, to pivot from exploration, enterprise, to to development. And I said, what you should expect out of your CEO is activities and results. And so the the first activity, of course, is a disappointing one. There is no mobile oil in this reservoir. But I hope you everyone appreciates that that outcome was done in the most capital efficient manner possible. Had we gone through all six intervals with exhaustive testing, we would have the exact same result and spent enormous amount of shareholder money. So the objective here is to be as capital efficient as we possibly can.

44:05 But also along the way, we engage a lot of experts, be they from Schlumberger, Core Labs, and everyone was, as surprised as we were that given what we saw in cuttings, core, and logs that there was no mobile oil. So so along the way, there was exhaustive testing in every imaginable way to understand this phenomenon, which ultimately led to the decision making to expedite this, given what we saw was a very repeatable phenomenon through through the horizons, I would say. Yeah. And and I think look. When the board takes its obligation very seriously to disclose information. If we had all of the internal analysis and the external peer review of that analysis saying, we think there's a high probability of mobile oil being produced in the test, and we had chosen not to share that And to say, notwithstanding that there are lots of people who think this is a very high quality and very high likelihood outcome, we you you should treat it as being zero. There'd be as many people complaining that we were not, you know, fairly and and even handedly sharing that information. So what we promised was not the that we could guarantee positive outcomes. What we promised was that we would be candid with people, that we wouldn't hold back bad news.

45:34 You know, it doesn't get better with with age, that we would make sure that you were in a position as far as possible allowing for time zones and anything else to have the same information in summary form that we were using for making the decisions that we made. And so, you know, we we will commit to continue doing that, that we will you know, we can promise you candor and and an honest appraisal of of where we see where we're at. The there are some questions about The US listing, and and I I wanted to come back to that because at the start, we said this is what we're we're going to discuss. The it's quite clear that a when we talk about why we drilled the mega as well, you know, there were reasons linked into the development program, but there were also reasons linked into the market story for a potential US listing.

46:33 And that having that well and in the success case, that would clearly provide a huge following wind into a US listing. There is nothing that changes the view that this story is best presented and particularly as it derisks and and with the the WL that becomes clearer to the market that the right place for this to be traded and to be listed is on a US exchange. We're still moving forward. Again, the the program is predominantly based on minimizing the costs upfront and then contingent costs based on the success of of that listing program.

47:19 We are still targeting a end of year, start of next year timetable. Nothing about that has changed. And when we look at the progress we've made, the there were a number of steps required in terms of implementing and documenting controls that would be compliance. Most of that is just good governance whether we were listing or not, and we would have done. Because as we move from drilling one well a year and the systems that are resilient to that to a full development, absolutely no point in trying to build a full development on a, you know, on on a foundation of sand. It needs to be a solid foundation for building that.

48:06 The in terms of other steps, the restatement of our IFRS accounts, The US GAAP that would be necessary for US regulatory filings is a relatively small cost in the overall scheme of moving to The US listing. The large costs are obviously underwriting fees for the capital raised and legal fees in writing the regulatory filings and and handling all of that. Those are costs that we have not yet incurred, and we absolutely will not incur unless we believe there's a high likelihood of success in a US listing. But The US listing continues to be a key part of our plan moving forward to provide access to capital and, hopefully, the rating that's necessary when aligned with the rest of our funding strategy, which is to progress on the monetization of the gas, to progress on strategic transactions that would provide funding, and to put ourselves in a position where, to the greatest extent possible, we're not raising money when we need it, but when we decide to and that is consistent with the plan in under which we raised an additional $35,000,000 of firepower back in February of this year and the pro progress of the plan going forward.

49:27 Max, is there anything else you want to to say in relation to that? No. I think just as we said upfront, the Meggres is a disappointing result, but all other aspects of our business plan, including that, are intact. So I think that brings us we're just coming up on fifty minutes. We intended to keep this to less than an hour. The the message we would like you to take away is we absolutely understand and and feel personally the disappointment at the result of this world test. It's not what was expected based on the technical data. However, we now have removed that uncertainty and and that step in the process towards commercialization.

50:15 We are a 100% focused now on the steps necessary to deliver the path to cash flow self sufficiency that we laid out eighteen months ago that we are moving forward to derisk the gas availability through the W well, drilling the Shomi well that that was talked about in the the documentation around the gas pipeline, and to taking the steps forward to a US listing and, ultimately, in 2028 with the hope that with following wind from regulators and the administration, that timetable may be brought forward, to delivering oil into the TransAlaska pipeline at the earliest opportunity.

51:05 Max, is there anything else you'd like to add before we hand back to Mark? No. I would just say that, you step away from this. This well needed to be drilled. As as David mentioned, they represented proximal inventory on the other side of the highway, very capital efficient if it worked out, and there's a structure above that. It's very disappointing that despite a very strongly oil charged system, we were unable to get primary oil mobility, but, that just represented upside in the plan. All aspects of what we want to achieve remain. And what you you should expect from me and the board is to get on with. So onto the path of commerciality and free cash flow sufficiency self sufficiency. So, Mark, just before handing back to you, there are a number of questions that that were either relatively niche or came in quite late during this discussion.

52:01 We will attempt to aggregate to cover the broad themes and provide written answers to those questions on the IMC website. If there are general questions that are of a more long lived nature, we will post them also to the PANTHEON website. There are a number of questions which, honestly, the way that they have been framed, we're not going to respond to nor nor indeed will those questions be published on the website. I would ask that at a minimum, whatever disappointment people may have about the results of the well, the the civility is is no bad thing. So with that, Mark, back to you.

52:48 That's great, David. Max, thank you once again for updating investors. If ever, please ask investors not to close this session as we'll now automatically redirect you to the opportunity to provide your feedback in order that the company can better understand your views and expectations. Only takes a couple of moments complete, I'm sure it'll be greatly value to the company. On behalf of the management team of PANTHEON RESOURCES PLC, we'd like to thank you for attending today's presentation. I wish you all a good rest of your day.