Pantheon Resources Plc (PANR) Earnings Call Transcript & Summary

Good afternoon, ladies and gentlemen, and welcome to the Pantheon Resources plc Investor Presentation. [Operator Instructions] Questions are encouraged. It could be submitted at any time using the Q&A tab situated on the right-hand corner of your screen. [Operator Instructions] Given the significant attendance on today's call, the company will not be able to answer every question received during the meeting itself. However the company can review all questions submitted, and we'll publish those responses where it's appropriate to do so. Before we begin, we'd like to submit the following poll. And I'm sure the company will be most grateful for your participation. And I'd now like to hand over to Executive Chairman, David Hobbs. Good afternoon, sir.

Good afternoon to everyone. Good morning if you're in a time zone where it's morning. And it's a great pleasure to have an opportunity to talk through the results of the Netherland, Sewell report on Kodiak and supply some additional context around, if not take you on operations. You'll see that there are a lot of presenters today because we want to make sure we covered everything that needs to be covered. So without further ado, let's move on in. Please take a moment to read the disclaimer. You can read it in your own time as the presentation has been posted on our website, so that will be available there. And so we've got a pretty full team to address a wide range of topics. We will take the opportunity to finish addressing the questions that we first started dealing with when we announced the Pantheon strategy that has been ongoing for the last couple of months. So today, we'll hopefully cover everything that was originally asked. We will do our best to answer any other questions during the course of today's session. But as told, we can't guarantee that we'll have enough time. Since we've made a lot of progress, of course, the last couple of months, it's worth just restating to remind everyone what our strategic goal is that is to deliver sustainable market recognition of $5 to $10 per barrel of recoverable marketable liquids by 2028 at the minimum possible dilution of value to existing shareholders. And that's what we are on track to do and the steps that we've taken over the last 2 or 3 months have moved us forward in that regard. This webinar will update you on further progress towards that goal. Our agenda today will be to address the results of the Netherland, Sewell & Associates report. But in addition to that, Bob and Jerry will be sharing the potential upsides from further appraisal that key off the Netherland, Sewell numbers. Bob will be talking about the characterization of the fluids. And then Michael talking about the test in the Alkaid-2 well at the Shelf Margin Deltaic and progress towards that. Tony Beilman will be talking about the development planning work. And then [ Galvin and the team ] will address the 5 contingencies that were referenced in the Netherland, Sewell report, which is -- which are the steps that will be necessary to reclassify from resources to reserves in due course. And then finally, Jay and I will update you on progress against some of the milestones, and we'll move into Q&A. So Bob, can I hand it over to you to talk about the Netherland, Sewell report?

Thanks, David. Welcome, everybody. Look, before we talk about the upside, which we'll get into in a minute, I just want to review the results of the Netherland, Sewell report. And this was -- it took us a year to get to this. It's working with Schlumberger, our team working with Schlumberger, sorry, SLB and Netherland, Sewell. And a lot of work has gone into this, and it's a small table, but those are big numbers. And just to highlight it again, we've got nearly 1 billion barrels of total marketable liquids in the 2C. And our 3C estimate, we have almost approximately 2 billion barrels of total marketable liquid. This is a great result for us. And we should regard this as the result of a lot of work, a lot of effort amongst a huge number of geoscientists and engineers to get to this point. Next slide, please. Again, what I'd like to do is highlight what is actually going on in the reservoir because that report discusses oil in place -- sorry, oil numbers, NGLs, condensates and gas. And -- but I'd like to take you through a very simple story about -- actually what is happening in the reservoir. So all the information we have, all the test data we have tells us that we have an oil reservoir -- a light oil reservoir. The charts you see here are from GeoMark. It says that the source rocks are in the oil-generating window the -- that we have light oil that all the gas we have is -- that's in -- that we've seen is associated gas, which means it's dissolved gas in the reservoir. The complication becomes slightly post this statement is what happens when we actually begin testing the well and we drop the pressure in the reservoir below -- it's called bubble point, which is the dissolved gas is coming out of solution. That will be addressed by our engineers in a few slides down the line here, and they'll be discussing what's going on after we drop a little bubble point and we're testing the well. But simple story, we have black oil, associated gas, oil -- the source rocks are in the oil-generating window. Next slide. Again, this is a picture of every single test that we've made on all our reservoirs, all of them show the same thing. We have black oil, light oil between 35 to 38, 39 API oil. And again, the gas is associated gas. Next, so let me turn it over to Jerry, and what we're going to do now is discuss the appraisal upside on Kodiak through drilling as we go and start appraising this and drilling into what we call the, Chimney, the recent acreage we picked up in the last lease sales. So I'm going to turn it over to Jerry now.

All right. Thanks, Bob. What I want to talk about here is a model that we've constructed to extrapolate reservoir from known subsurface controlled Talitha-A and Theta West up dip into the Chimney and in the west part of the Kodiak field. Our data set -- our subsurface data set is really dominated by two data points, Talitha and Theta West. Those two, Talitha-A has the denser by far data set. It's got a whole set of LWD, wireline logs, FMI and also sidewall core samples. Theta West because of whole conditions were really restricted to LWD logs. So that, I think, imparts somewhat of a bias on our subsurface description and what we want to do is to counter that bias by forecasting what porosities and permeabilities how they should behave going up dip. So the next slide. So this model is really based on simple geological principles. It's built on compaction and the principle is simply that porosity decreases with burial depth. So as we go up dip from Talitha-A up to the Northwest, we're getting shallower structurally, modern-day structure, but also in the maximum burial depth. There's been less section routed off up there. So we get a double benefit there. So average porosities will increase from about 9% at Talitha-A. This is across the gross interval of the Kodiak fan complex up to over 12%, almost 13% up in the Northwest part of the Chimney. So if you can go to the next slide. So I think more importantly, what we can do in this exercise, I'll show you in a minute, is we can calculate the percentage of porosity that's greater than the conventional reservoir cutoff of 0.1 millidarcy. This is a standard cutoff that's employed to determine conventional versus unconventional. And we can calculate what percentage of the gross rock volume is greater than that cutoff. So now I think it's worth spending a few minutes walking through how this is done. This is a series of animation. So yes, the first one now we're going to look at porosity and permeability relationships. So we need three things. We need to be able to relate porosity to permeability, we need Dmax, and we need a line, a slope, a compaction slope. So how do we do that? Well, first, we'll do the -- in the yellow oval that's the porosity/permeability relationship. We look at -- perhaps our closest analog just to the northwest, Meltwater and Tarn. We also have more local samples at pipeline in Talitha. And those give us a cutoff of about 12% porosity, which would translate into 0.1 millidarcy. So we have that. Then we can go to a subregional relationship here, that's plotting Dmax versus porosity. And you can see the increased porosity to a place on the left there with decreasing burial depth. So if we can construct a line like that locally at Kodiak and we can reconstruct Dmax, then we can calculate for every point in the Kodiak fan, what the porosity distribution is. And hence, what the -- where that -- how much of that rock is about 0.1 millidarcy. So to do that, to get Dmax, we go to the map in the middle, that's based on published USGS data. And what that shows is how much of the section has been routed off. So it's missing section that's not present now that we need to add to the modern day depth to restore to Dmax. And that variation is pretty significant. It's about 1,500 to 2,500 feet difference from north to south. So we want to get to slope. So the way we do this now, the technique is to plot up all the log data points at Talitha and Theta West, so that's not really a vertical line. It's all of the porosity log points plotted up at their Dmax. And so we connect the means, that's the red line there, and that's our slope. So with that slope and a Dmax, we can calculate anywhere what the average porosity is and we can calculate what the distribution of those porosities would be. So here's how that looks in practice. On the top left, that shows the actual porosity distributions for Talitha in red and Theta West in blue, such as a histogram in 1 percentage point bins for each well. And then in the center, what we're showing is the Theta West actual, it's the blue curve. And then the red one is Talitha using this model, moving it up dip to the Theta West Dmax, and you can see it's almost a perfect match in terms of average porosity. So with that same principle, we can just -- we can go ahead and [ cap a ] porosity everywhere in the Kodiak Fan Complex. So what this -- the plots on the bottom show is that while we're doing this, remember, we're projecting every single point the porosity log along that slope, decompaction slope. At Theta West, only about less than 5% of the gross interval is greater than 12% porosity, just that little green on the bottom. On the next plot to the right, if we project that up along the slope, the compaction slope, we get to the Theta West location, where about 24% of the porosity samples are greater than 24% -- sorry, 12%. And then as we move up to what we call the Theta West location, which was on the previous slide, there we're getting up to about 37% porosity. So you can see the procedure, it's like an integration of the distribution curves as we move these porosity points up dip. And so here's with that, it looks like we can take a collection of points that span the depth interval of the Kodiak fan complex from deepest the shale was. The average porosity, so just the average thinking of those histograms, it's the average porosity is linear, as you'd expect, from using that linear function. But the percentage of porosity and the percentage of gross rock volume that's greater than the 12% or 0.1 millidarcy is nonlinear. It's steeply increasing as we go up dip due to shallower structure, but also less Dmax. So as we get up to the northwesterly part, much of the Chimney, where more than 50% of the reservoir should be considered conventional or more than 0.1 millidarcy. So that's a summary. I think with this, we'll have great implications on recoverability as we move up dip from the known subsurface control at Talitha and Theta West. So I think I'll turn that over to Bob.

So just a -- comment about Jerry's works. What we're going to see as we crossover and start appraising the Chimney is, we're going to see better reservoir deliverability, which is going to give us probably higher recovery factors. And in the case of what Jerry is describing, an increase in volumetrics as well in place volumetrics because we're going to have better porosities and permeabilities. This is really a placeholder for work done by Roger Young. We plan to have Roger present his work in detail, but he had some medical issues that he had to take care of, and he's been out of commission for several weeks. So I'm going to do a poor man's job and summarize Roger's work. And later on, we will have a bit of a webinar or so Roger can actually show this. So second factor that's going to impact, and in this case, it's going to impact reservoir, our understanding about reservoir deliverability and recovery is the fact that the reservoir we're looking at in the Theta West and in the Kodiak, the Kodiak discovery, is a very -- it's thin-bedded laminated sand and shales, which means that when we examine the data in detail when we have it, such as, I think, an FMI or a whole core, what we see is centimeter scale beds. Now our logging tools that we have, so the MWD and the -- all the electric logs, tools that we have, are actually going to be averaging a lot of that data over a foot or 2 feet. So basically, we're kind of smearing and averaging out the information in these thin beds. Now that's not going to affect our gross rock volumes. But what Roger has been able to see going back, looking at the whole core data pipeline looking sidewall cores and looking at the log data is, we are not seeing the higher porosity/permeability beds. They're being smeared into an average background, which just basically means that what we can expect to see is almost 2 to 5 porosity units above this average background that we're getting in the conventional logs and the wireline logging tool. And as we go up dip to Theta West, we expect to see in the higher porosity zones up to 15% to 20% porosity range. And permeability is much better of 0.5 millidarcy. The only way we're going to be able to see all this is take whole core. So it's incumbent on us when we're drilling our next well that it's not just a test of flow rates, but we need to collect a significant amount of data to verify what we've been talking about over the last few slides. And getting this whole core data is going to be hugely important for our reservoir characterization. But this one slide here is telling us with the work that Jerry has also done is that we can expect to see better recovery factors and better reservoir performance as we move to the north into the Chimney. And turn it back over to you guys.

So the next thing we want to address are the 5 contingencies from the NSAI report on Kodiak. And in this section you will hear from Michael Duncan. And Michael, welcome back. The last time you saw him, he was one day removed -- from some very serious knee surgery. So welcome back to the walking, Michael.

Thank you. Good to be back.

From Pat Galvin and Tony Beilman. So in Section 1, technical data that demonstrate sufficient rates and volumes to sustain economic viability and we've got questions about that. Michael Duncan will do that. The field development plan and regulatory permits that we had Galvin. Viable gas and water utilization and disposal methods, Tony Beilman will take care of that. Our ability to market our oil and our NGLs and condensate, no one better than Pat Galvin to take on that task. And then David and I will comment on all of the work that we've been really doing the last really two months to fund the complete development project, and as David said earlier, with the least amount of dilution for our current shareholders. So with that, I will turn it over to Michael.

Thank you, Jay. Happy to be here a little further move from surgery, as you mentioned, and recovering appropriately, glad to be walking again. But yes, looking forward, obviously, our next steps that we've discussed and the things we're really excited about operationally or showing our path towards the true economic viability of these reservoirs, upcoming is Shelf Margin Deltaic test. And that is a quest to understand new fracking techniques, its request to understand the PVT data in the reservoir a little better. And as we got a lot of this determination is based on our pressures that we see. And so it's another opportunity for a piece of the puzzle in our virgin reservoir pressure campaign. And so those three commence soon. We are applying a new fracture technique to the Shelf Margin Deltaic. Tony might discuss that a little more. But it's finer proppant, it's thinner fluid, it's the next step, as Tony to be mentioned in our frac generations, and more correlative to what you see at present day in, say, Permian or other places. So we're plugging that frac to the Shelf Margin Deltaic test. To give a quick operational update on what's happening, we still believe we're on schedule for -- to start in September. So we're really at the fun part right now. For the camp analogy, we're all packing our bags and making sure we have our gear before we head up there. And equipments descending on the slope, people are beginning to descend on the slope. We have boots on the ground with the early operations, and so that's happening right now. In parallel to that, we do have ongoing analysis with Schlumberger. We're looking to future development plans and modeling how these -- how these new frac designs will propagate in the development. So looking forward to that. And as Bob said, of course, operationally, whole cores are going to be very significant to our future. Bob, I apologize for this. I might pass this to you really quick to talk or to Tony really quick, talk about the recombination of fluids. Tony or Bob, would you guys like to take this one?

Sure. I think as everybody knows, the reservoir flows that we're dealing here, unlike water is highly compressible. So a clear understanding, as we talked about earlier, Bob mentioned and Michael mentioned, was having some PVT analysis as we move forward. For those who don't know, PVT analysis really just means pressure, volume and temperature analysis with these compressible fluids. The volume is highly dependent on the pressure and the temperature and as fluid changes in pressure and temperature from a reservoir moving forward, that's a big consideration. And we want to make sure that -- we understand that. And as Bob mentioned earlier, on the Alkaid-2 GeoMark -- GeoMark laboratories was retained to start that process and they looked at the fluids that came out of the Alkaid-2 and kind of gave us some good reservoir numbers to work with. Then we took those numbers and that data and provide that to Schlumberger, who have active simulation model where they can model what they were seeing and take that fluid and put it back to a reservoir condition. And what the conclusion of both GeoMark and Schlumberger is, we are, as Bob mentioned, a solution gas drive reservoir. We're not sitting in the gas reservoir, it just a solution gas reservoir. We're currently producing below the bubble point, and so the alternative numbers that we're seeing. And based on that, this slide here shows you some of the snap views and what Schlumberger's modeling did, and based on that analysis, they matched the GOR, which was a big number we needed to map of what we were seeing off the Alkaid-2. So we're pretty confident we have a good handle on what the reservoir is looking like and then moving forward with the test that we have on the Alkaid-2. We're hoping that we'll have a good understanding of what's going on in the SMD formation as well.

And before we move on, could you just maybe give a little more color on the new -- the frac versus the frac we put on the horizontal portion that we're planning now, Tony?

Sure. So what we've done different on the frac job, we've been a little bit more selective [ burping ] perforation selections, then we've changed the fluid, type of fluids and the chemical ad that we're adding to it, a little bit better to help with the flowback. And then lastly, we've moved to 100 mesh sand. We've gotten away from the 30/50, which we believe kind of hurt us a little bit on the sand flowback as well as -- and then we've also double the rate. I think we're somewhere around 400,000 pounds in about 11,000 gallons going into this stage. So that's kind of becoming our horizontal model and so we've kind of taken it to put it in this vertical section. And incidentally, Schlumberger did a pretty detailed analysis of all the fracs that we've done, and this is kind of sitting in the middle of where they recommend that we said as well.

And what we're trying to do is determine the efficiency of this new frac.

That's correct. We need to find out what the frac had to know out of the reservoirs behaving with these new jobs. It's not really an idea to maximize production. We're probably going to flow this back slowly, so we can get a better feel for how the fluid is behaving. We're going to run some bottom whole pressure data, so we can see what the reservoir pressure looks like.

Great. Thanks. Pat, over to you.

Thank you, David. I've been asked to just give an overview of what permitting will look like going into a development project. And really, this is fairly standard for any project in the North Slope, but we happen to have the minimum aspect of it because of our location. The primary driver is going to be the unit plan of development, which comes from the Department of Natural Resources done in conjunction with a plan of operations, and that will be sort of the overview across the entire development plan. Then -- because we're going to initially have pipelines that will connect our facility to the hot tap location, we're going to need to get right of way for those pipeline locations long, whichever route is best determined for those. The hot tap itself is going to be approved by the State Regulatory Commission. That location, you can see here on the slide is located really within sight lines, just a little around a mile from the Alkaid pad that we're proposing. And then finally, we've got an air quality permit requirement that would be part of any development that has emissions. We're intending to minimize those air emissions. So we don't expect the air quality permitting to be significantly onerous. The one thing about this slide to note is really what's not on this list. Typically, historically, with any North Slope activity, you would see a wetland development permit, a wetland fill permit from the core of engineers, because of the recent Sackett decision from the U.S. Supreme Court, that has changed the entire outlook for wetland permitting on the North Slope. Previously, we would have expected nearly all of the land that we would be developing would be subject to a wetland determination and Wetland Permit. With the Sackett decision in the new initial proposed regulatory changes, it's actually flipped it around to where we expect very minimal designated wetlands. And likely, we can avoid a federal permit requirement across most of our development acreage, which significantly changes the overall permitting expectation and may even avoid the environmental impact statement process that most other projects have to go through. So we're watching that one closely as that develops in the wetland rules become more known and applicable, and we're seeing significantly positive movement on that. And I think that's the primary overview right now.

Yes, back to you, Tony.

Sure. As Michael mentioned, we were working with Schlumberger or SLB. It's been hard to switch back and forth so -- but anyway, their work is taking forward the data that we had, that are modeling, the best development practice for the development plan that we can come up with and how we can maximize both the production reserve and minimize the cost of development, and we hope to have that done in the first quarter -- or quarter 2 of next year. We've actually engaged them and we've already started that process. So hopefully, we'll -- and we'll get that data done. They're taking the data and putting in a dynamic model, which is really handy because we can watch it as you can see like different sensitivities that will help address all those questions that are coming, which includes how we're going to handle the gas, how we're going to handle the water and so forth. So really excited about the report coming out.

And handling the gas and water is critical because we're going to have a lot of excess gas and we will produce water throughout the life.

Yes. Water is not unexpected, the gas is not unexpected, but it's a good thing. It's kind of a double-edged sword. Gas is providing some very valuable liquids and really [indiscernible], but we still got to get rid of it.

And a lot of energy.

And a lot of energy. So we'll be able to -- and we're pretty excited about the plan that's going to come out as well. Great. Pat?

So in terms of getting our product to market, it's important to note, as we've covered in previous webinars that our entire marketable liquid stream, including the NGLs and the condensates are all going to go with the oil down the Trans-Alaska pipeline. And as we've noted, Trans-Alaska pipeline is a common carrier pipeline, which means it's open access, regulated by the Federal Energy Regulatory Commission to allow for new shippers like us to bring that to market. The NGLs will be transported along with the crude and included in our stream and in the valuation of our stream, which gives us the opportunity for uplift associated with our higher-value NGLs that are going in with the oil. As we've covered in previous webinars, the entire stream is evaluated and broken down to its individual components. Each of those components has been priced separately, and there is an adjustment on basically what you put into the pipeline versus what you get out, depending upon the value of those individual components in your stream in comparison to the others. Our initial analysis indicates that really, from a conservative standpoint, we're looking at about 90% of the current stream value, which means that in the end, if we put in 100 barrels at the input to the pipeline at our hot tap, we would right now anticipate getting out about 90 barrels at the terminus when we take it out.

Tony?

Okay. So where are we in terms of going toward our goal of between $5 and $10 of value for Pantheon based on our resource estimates? And going from left to right, you can see we're starting to shale some of the areas. That means those that we have started to have progress on. You can -- and the big thing, of course, that we haven't talked about today is how do we finance the $350 million that we've talked about -- David has talked about in the past. But in reality, we don't really need to raise all of that $350 million today, and we're pretty certain that we won't need to raise all of it in the future from our shareholders. And that is why we have the team here in Houston this week working for. We've been meeting with investment -- the resource groups of investment bankers. We've met with the service providers to talk about how can we partner with this great project and reduce the amount of capital [ investment part ]. And the amount of capital is truly required to get to first significant production is about $120 million of the $350 million, that is the headline there. So that's what we're moving forward. We're working very diligently on that. We've had some great meetings. We will have some more. In addition, as you know, we have a data room that's open. We had some interest in companies coming and looking at into our data room. So we are moving on all fronts to finance what's ahead of us. And as you heard, we had the NSAI report on Ahpun that probably will spill over into the first quarter of next year as they get very busy toward the end of the year doing end-of-year reserve reports for others. We had the Alkaid-2, reentry of the Shelf Margin Deltaic test coming up. That's an exciting time for us, and all of the work that's going on behind the scenes technically and with -- moving toward a potential U.S. listing and getting a permit to put our crude, our liquids into Trans-Alaska Pipeline.

David, would you like to add?

Yes. No, thanks, Jay. And just to reiterate, every conversation that we're having is about how we reduce the [ pull-on equity ] because that will end up being a balancing item. And so talking with lenders about what they will need to see before, we're able to grow our borrowing facilities, the 350, don't forget was based on 300 associated with the initial production and 50 associated with the further appraisal on Kodiak. And so that 50 will be invested in the time line that leads us towards the FID in 2028, as mentioned. And based on how we can assemble a project to ensure trouble-free operation that together all [ the date ] that we need along that way. So coming back to the 300, which is the residual for bringing us to cash sales efficiency, that is the point at which we don't require any additional capital, whether it be debt, whether it's equity, whether it's [ mezzanine ], whether it's -- financing, whatever it may be. And so drawing back from that anticipate the need for around 120 that won't be fundable from reserve-based lending by the time that it's been spent. That if you recall, was made up of a very conservative assumption of $20 million for the hot tap, $20 million for the upgrading facilities to add to the existing facility that we already have, adding [indiscernible] unit. And I know every time I say $20 million worth of facilities, the team looks at me and [indiscernible] across this -- we know we can do it a hell a lot cheaper than that. But we want to make sure that we plan conservatively because if you ever need dollar, that dollar always cost you more than you expected to or is it be planned for and definitely to call on money that ends up being much cheaper. And then although we had a pathway and we've described the pathway down $13 million per development well in today's, obviously, escalation over time because this is a 10- and 20-year drilling program. But we're assuming that those initial wells are going to come in at above that budget. So we need to make sure that we properly funded ourselves for that. And of course, there's some overhead to keep the business running to maintain the engineering studies and development planning and regulatory planning, and so that's where we get to the total of 120. Every conversation we're having is based around how can our partners in this development will reduce that quantity down to something ultimately, it may be possible to get it to zero, that's actually their promised, but our goal is driving towards zero. And every night, Justin, Jay and I go to bed, a separate bed, we're thinking at the same thought, which is how we make sure that we can raise the funds in terms of the -- into the minimum valuation to our shareholders. So some of the things that we've done over the course of the last few months, we've identified where our office is going to be in Houston. In fact, it's right next to or to where we're sitting today. We're borrowing an office altogether here in order to move forward with this webinar -- and using the conference facility there. We have begun the process of those financing discussions. And in order to reduce the supply of equity or this equity into the market, you saw we did the deal with [ IVTL ]. And we are working on a daily basis to ensure that the ability to bet against some -- because there is an assumption of supplier stock is an unsafe assumption to be made.

And I would just like to add the market obviously reacted very favorably, we believe, because the share prices. We moved up smartly.

That's right. I mean, the steps we're taking, there's a lot of boring stuff going on. There are all small steps that lead to a point. And as I said, in an earlier webinar when people said, "Gosh, 2028 is a long time away for the brand you're talking about." When we get to the point at which that value becomes inevitable, we expect that to be reflected in the market sooner. And that's why we're doing all things to put in place, the steps necessary to deliver that goal in 2028. With the advisers are at work expected to report shortly on the tax implications of either a U.S. or a new listing or a change in domicile of the company, and we absolutely recognize that there are implications to different groups of shareholders of decision we take, which is why we're not trying to take that decision lightly and make sure that we consider all of the angles on that. So in summary, we will arrive at the point in late 2025, we hope and it was early 2026, where we're in a position to take FID on the good development with all [indiscernible] state, all the financing sort down, and that's the point of which resources will be classifiable as reserves if all of those other contingencies address and to move forward during that period to build up the production to make sure that we've got the Kodiak FID in 2028 to continue building up to what we think is going to be one of the most exciting projects in the last couple of decades onshore in the United States. And with that, I would just like to add that many of the meetings we've had this week have been surprisingly positive. So for first or second meeting, very positive. And in no small measure pretty close, but being able to bring the report the other table, it means instead of just being [indiscernible] show up in Houston saying we've got a great project, the right people are opening the door and engaging in a serious way. Let's hand back to Paul, and then...

David, thank you so much and to the rest of the team from Pantheon Resources. [Operator Instructions] I'd like to remind you that a recording of this presentation, along with a copy of the slides and the published Q&A can be accessed via your Investor Meet company dashboard. David, if I may -- if I may invite you just to open up the Q&A tab. It's on the right-hand corner of your screen. You'll see questions from investors. Firstly, thank you to everybody for engagement. If I may, David, if I ask you to just read out the question and give responses obviously where it's appropriate to do so, and I'll pick up from you at the end.

Thanks very much indeed. So the first one, is there any correlation between the Alkaid-2 and the Alkaid test with energy assets they're planning to test this winter, assuming both Alkaid and 88 Energy flow well at commercial rate, is there any chance of a merger of both companies or JV or asset acquisition? Well, let me just handle the first at first, and then ask Bob to comment. The first is, we're not going to talk about any potential transaction or speculate about that, whether with 88 Energy or any other. But we have got a very good working relationship with 88 Energy involved. And let me hand that over to Bob.

Yes. I mean -- yes, thanks, David. We do have a very good working relationship with 88 Energy and we've -- over the last several months, we've been working together very collegial relationship, sharing data. Obviously, I can't express any opinion at all on their data at Hickory, we're under confidentiality. But as a general statement, we're working towards helping them in any way possible to get a positive result down there. Anything positive that happens down there is good for us. So we're certainly working -- is giving much information as we can to make that happen.

So the next question is, what kind of results in the upcoming SMD testing would Alkaid demonstrate to industry participants and potential following partners that the SMD/Alkaid are resounding commercial success, leaving the room put out. Although the right answer to that is, there is no results, but would possibly need no room for doubt. But in simple terms, if we can improve the quality base demonstrate the efficiency of the frac and the utility of the revised and updated frac design, that will only add to the perception of the likelihood of success. What I can tell you is that the perception that it is uncertain has been widely held among the investor communities and it is about the industry community. We're certainly not finding that people are a down to about the likelihood of the viability of the assets and the conversations that we're having.

Well, let me just add also that we're not planning for a headline slower. That's not the purpose of the reentry of the test. As Tony and Michael said, we're about data gathering and determining the efficiency of the new frac design.

And we need to remember that our intent is to understand the reservoir fluid and how they're behaving and how the frac performs so we can plan future frac designs. And that's really the main driver behind how we're [ growing ].

And next one is, you're talking about having an asset quote for some time. You've been very positive in conjunction with an institutional investment ratio in the U.S. Is that something that's progressing. Justin, do you want to respond to that?

Sure. I think you touched upon a few of those points previously, but there's two parts to that question. The first is the listing and the second is the roadshow. Addressing the first, obviously, budgeting relationship, it's important to get it right and to make those right decisions. So we're meeting as many groups as we can to choose the group that's relevant, the divisional story. We [indiscernible] the capability, not only on the equity market side but on the investment banking side, but also project finance, and those kinds of things. And then as David, I think you mentioned having that [indiscernible] now ends, really increased our credibility going through those meetings, and we've certainly been taken very, very seriously. So that's that. There's a question about which exchange [indiscernible] NASDAQ, NYSE, which level on those exchanges, or do we has long [indiscernible]. Dual list, we're considering all those things. And we've appointed very serious tax advisers to assist us with our structuring to make sure we get that right because as everybody has heard the size of the price here -- right beside the price here is norm. So it's very, very important to make those decisions and pay them appropriately. On the second part of the question on the institutional roadshow, yes, actually, we haven't done one yet, but we will be doing it shortly. And the reason for that is, obviously, we want to get the middle and to report back profit, and also we wanted to put this webinar in to the public market to allow us to have more serious conversations with all those people. So the answer is, we're doing a non-deal road show pretty soon. It will be not a one-off program that we repeat from at a regular interval to build up those relationships. And our broker in London, kind of [indiscernible] that at the moment.

The bet is on your stock, [indiscernible] not commercially recoverable. Could you give us a percentage of probability on your [indiscernible] commercial? And again, we're not in the business of offering percentages. You can read into certainly my view on the basis of my investment in the company. The advisers we're working with are in no doubt adds to the commerciality of it, but nothing is ever a certainty in this business. [indiscernible] dynamic modeling, what else will be Netherland Sewell and SLB reports support other than a farmout process when you currently anticipate the initial reports being finished and that conclusion shared by RNS. Certainly, we've already talked about the likely delivery for the Ahpun reports. Tony, do you want to just say a word or two about how we'll be using the SLB work in development line that you already mentioned?

Sure. As I mentioned, part of the project that we have ongoing with Schlumberger is to do a project development plan, which includes how we're going to handle all of the stream and stuff. So that is still anticipated. The plan concluded. It should be around the first quarter, second quarter of next year.

Great. Well, I think it's on the information release to date appears so far to be confusing regarding what was found off the Theta West-1 flow Basin Floor Fan, was this done on purpose because of the 2022 lease form?

Yes. The answer, it is confusing. I mean, what we've seen in the Upper Basin Floor Fan is one set of data from the [ PAS ] is telling us something about it. And our log analysis is telling us something slightly different. What we found in all our gases is when there's a correlation, one-to-one correlation between the VAS and the log data, we've had success. Everything we've tested when that happens has been positive. At this stage, we're still doing -- we're still analyzing that and trying to understand why we're seeing these differences. And eventually, somewhere the future appraisal of Theta West, we're going to be banging into the Upper Basin Floor Fan again and hopefully maybe do a test in it. But right now, we're -- we don't have plans to target any well for it.

So Bob, I'll combine a couple. How are [indiscernible] predictions performing? And if the 3D attributes at the Theta West-1 location predicted the other Basin Floor Fan [indiscernible], hey, what lessons were learnt, you sort of addressed the second half there and have already begun.

So in terms of the [ E size ] again, I think their predictions have been pretty much spot on, particularly Theta West, particularly an Alkaid-2, we've had very correlation -- we certainly can see light oil and reservoir.

Okay. So we've talked about -- well you've addressed the [indiscernible] are consistent in [indiscernible] has not gone away. It is a part of future appraisal, but it is not hard for the resource that we're describing [indiscernible] for time being. The orientation of the new Chimney leases suggests a [indiscernible] fan light oil force regression can choose seismic lens to define prospect limits of the new resource act.

I think I should take that question. I'll answer it by saying, [ Brett ], at this time, we're not going to do that. I'm assuming that [indiscernible] Brett. So I think we'll pass on that.

It is possible sandwich reservoir in the [ Hugh ] shale has different oil than the lower Basin Floor Fan any implications for development. Again, Bob, if you want to...

I think we're -- again, this has to do the Upper Basin, the Upper Basin Floor Fan. Again, we are seeing differences in there in terms of the hydrocarbon content or the presence in reservoir. So it will have implications when we appraise it in the future.

[indiscernible] east of Chimney [indiscernible] building or development more challenging?

I guess that's probably my question. Should I take it on, David?

Yes.

I guess the most correct answer is, yes, it will make it more challenging if the implication is will make it so that we can't develop it, the answer is no, that it won't preclude us from further appraising or developing it.

Right.

Can I make just an objective statement there about that Chimney acreage. And just to highlight something about it, again, and that's the work that we've done that Jerry's done, the work that Roger has done. All of that is highlighting that, that acreage, we'll have a substantial amount of the reservoir is going to be what we consider conventional reservoir substantial amount. We're going to have better recovery factors and it's going to impact the -- particularly Jerry's work is going to have an impact on the oil in place. hydrocarbons in place. So it is a very cool piece of acreage.

Yes. Thanks, Bob. It's only a small section of the U.S. [ 900-foot ] [indiscernible], given whether operational constraints [indiscernible] well could have produced the near commercial rates from this [indiscernible]. And guessing Michael, do you want to address that?

Sure. Yes, there is viability of the concept that we could have connected to more rock. We're always dealing with timing and resource constraints in the winter. As far as what we would have hit had we stimulated more rock, I don't know that it's appropriate to speculate towards that. But yes, there's absolutely viability to concentrate that with time and resources and without some of the constraints of winter ice operations in one season, and with -- even with some of our new frac approaches, that there's a lot more rock we got stimulated and a lot of excitement for what that can mean.

Bob, can you comment on the implications of 88 Energy testing program for Pantheon projects and should then need the resources be unitized with 88 Energy?

Part -- I'm going to pass on the unitization part and just answer that, again, what a positive result there will have a positive implication for us. And again, we're working towards that to help as much as we can to ensure that happens.

Next question was around $350 million. I think we dealt with in the webinar. Another question in a recent interview, you said the [ silver bullet ] report would allow us to have high-value conversations, are they ongoing? We talked about -- it definitely causes doors to be open less skeptic even otherwise might have been and we are talking with a number of people, industry finance, service organizations, regulators. The key point is that it provides that validation of the development case that we've been talking about means that [indiscernible] as being a good investment of their time to engage with us. And indeed, we are in high-value conversations with a number of different organizations. On the resource table slide, the discussions focused on oil and NGLs that the residual gas resource is not discussed in the valuation sense. Why is that? And is there any value to be created from the gas? Let me just give a quick answer to that, which is that our base state and all our economic analysis and the argument for the resource being commercially developed lie upon three basic foundations. The first is that we influence the same across the entirety of the resource base even though there's reason to believe that we will see proportionately less gas in other locations in our acreage. The second is that the reservoir rock is all at 4 as the Alkaid-2 [indiscernible] Alkaid-2. That is, by all measures, the lowest quality rock we have in our development. And so we are actually confident that if we can economically develop those rocks that everything else is going to be proportionately more valuable and more commercially attractive. The third tenet is that we will have to reinject all of the gas and water that we produce the water into aquifers not into the reservoir. Again, back into the reservoir and we have allowed for one injection well for every three production wells that we have. You can add that up over those 3,000 or so wells that we would expect to have as part of this development. And that tells you that we're going to be investing $5 billion or $6 billion over the course of the next 10 to 20 years to handle gas injection. There are other options for handling that, not least of which is to take that gas to the north and building a pipeline to gas injection is needed in the way gas injection easier may well represent an optimization that we haven't even begun a factor, but that will be part of the development planning work that Tony and Michael are taking with SLB. Furthermore, should that become a gas uptake route and there are in the public domain discussions about gas uptake from the North Slope weather to an LNG plant on the North Slope itself or LNG plant [indiscernible] on the South Coast. And of course, that would materially alter the economic outlook. So that, I think, in simple terms, is what the gas means and the opportunity for us [indiscernible] How accurate or confidence [indiscernible] with the porosity extrapolations, are there any key assumptions? Bob, do you or Jerry, you want to take that?

Well, I'll take that one and say, so far, predictions from Talitha to Theta West looks pretty good. The geologic model that Jerry is actually talking to is pretty standard stuff of -- as you go deeper, your porosities and permeabilities go down. So if we go shallower in the other direction, which is what we're continuing to do from drilling Talitha to Theta West to Theta West-2 location, we're going to continue going up dip, we'd certainly expect the porosities and permeabilities to improve.

Let me just add something to that. The model I showed was based solely on compaction. We also expect, as we go up to the North and West that we should see improved reservoir phases development as well as we get closer to the settlement source. But that has -- that's not shown in the numbers that you saw in that.

And all of your data really is based on empirical data. So it is an extrapolation of empirical data.

Just in a very straightforward application of porosity versus depth relationship.

Correct. But I think the key point is this is not a unique hypothesis based on Pantheon's acreage or Pantheon's activities. This is just generally well-accepted geotechnical analysis.

Correct. Kodiak looks compelling, current commercial is that we won't be drilling this for 5 years, given the size and scale of this field and the current economics to ensure this isn't going to drill for so long. The answer is that Kodiak, we will be getting to as quickly as we can get the [indiscernible] development consent. And of course, moving away from the Dalton highway, and requires additional work than just putting pads alongside the Dalton Highway. So the answer is, once we've got to the point of having development conscience and financing in place and cash sufficiency, we will have a portfolio of some 2,000 development locations, that in terms of economic optimization, whatever one does, it will be to choose the next highest value opportunity for deploying capital. And so our current plan says, yes, we start off alongside the highway developing Ahpun and then we move gradually and we get to Kodiak in due course. The answer is as soon as we have consent from that then Kodiak enters the portfolio of investment opportunities, and we optimize to maximize value in terms of the risk advantage that we added for every dollar invested.

We're certainly going to be appraising Kodiak.

[indiscernible] 2028 call out.

Yes, we're going to be appraising this very as soon as we can.

Will the Ahpun CPI improve more detail on commerciality in comparison to Kodiak [ CDR ] The simple answer is that the initial work on the development economics will be done in conjunction with SLB as part of the contract we've led to them. And then in due course, as we remove contingencies relation with the assets, as noted in our earlier discussion, then it will make sense for an independent expert to define on the value. And of course, if we need that in relation to financing, then of course, we will do that. But for the time being, we're seeking to spend the minimum amount of money to move the project forward as far as possible. And every step we're taking, but the question we ask ourselves is does this investment effort and time of money moves nearer to our objective of delivering $5 to $10 per barrel near to the objective of becoming financially self-sufficient so that we become a price maker, not a price taker. The answer is it doesn't move us there, then we don't do it. And it does move us in that direction, then we do, do. Does the gas in solution make Alkaid reservoir unlikely target in the future? No, the gas in solution has positive as well as negative in terms of supplying energy for development. And in any case, the gas delivers around about 100 barrels per million cubic feet and that adds to the economic attractiveness of development. So yes, we see the Alkaid interest and the other horizons in the Shelf Margin Deltaic will make up until -- will be attractive for decisions. And do any of management have any personal financial requirements as they did last year that could lead to a sale of shale that household or options? I'm not aware of any member of the executive team for having personal financial requirements nor would I expect to ask them to declare them on a webinar with other people, but all directors are subject to the [ sharing code ] that we have for Pantheon team management, and we'll be able through all the regular processes. But we're unaware of anyone wanting to sell. And I would be surprised if anyone wanting to sell. And certainly, I can answer myself -- the [indiscernible] would it include the Alkaid Deep as well as the original Alkaid anomaly. Bob, you're probably best placed to talk about the scope for the initial and the subsequent report.

The answer is what it's going to have is the Alkaid anomaly -- Alkaid Deep and the Shelf Margin Deltaic -- sorry, the Alkaid anomaly and Alkaid deep. That's what the next thing from Netherland Sewell will be. It won't include the Shelf Margin Deltaic because they'll be still evaluating that from the test. So the first thing out is Alkaid and Alkaid Deep.

Tony, I think this one's for you. You mentioned 2,000 to 3,000 cubic feet per barrel earlier. You indicated 500 in the slide today, can you just explain is an artifact of how the analysis [indiscernible]

Absolutely. As again, that slide came from Schlumberger, and that was calculating where the reservoir stood at a saturation point. If everybody recall, I mentioned that we were producing in the reservoir was below the bubble point. So that number is reflective of what the reservoir would be at its bubble point. With that modeling, Schlumberger determined the bubble point to be somewhere around 4,500 and 4,700 pounds. So that number reflected to what it would be if the reservoir was at 4,500, 4,700.

And [indiscernible] determining, just before we said, Tony said, we picked up that slide from SLB. [indiscernible] be confused by that. And I said it's too late, but the presentation is being uploaded and you may have to explain it. So thank you, Tony.

And we actually believe the reservoir is slightly below, so that makes it even more complex.

Yes. So final one that we've got here, does team see any engineering risks in rejecting gas into a relatively tight reservoir? Tony, do you want to take that question? Do you see engineering risks in reinjecting gas into relatively tight reservoir?

I do not see the risk as far as reinjection. Obviously, we produced quite a bit out of the Alkaid-2. But I think what will happen [indiscernible] mentioned, David, will probably have a combination of reinjection. We may have to take some of that to some of the -- more permeable area than reservoir, but that's part of the model that will tell us what we need to do with. So that's part of the task that Schlumberger given.

It will typically be a horsepower.

Yes. It's more of an economic question than it is an engineering question.

Yes, that's correct.

That's great, David, and to the whole team, thank you very much indeed for your engagement, and thank you once again to all the investors for your questions and your engagement. And David, if any further questions do come in, obviously, we'll make those available and we can add any responses to the platform if it's appropriate to do so. I know investor feedback, particularly with the number of investors on today's call, it would be important to you, and I'll shortly redirect those on the call to give you their thoughts and their expectations. But David, if I may, before doing so, if I could just hand back just for a couple of closing comments and then I redirect investors for feedback.

Thanks -- presenting to you today has been closing our process has been going on for 2 to 3 months where we said we would sweep up all the historical questions that have been asked prior to our webinars. And going forward, we will continue to use the Q&A function in relation to these webinars as we have anything to update, anything that's price sensitive will be released from an RNS as you would expect. The steps we've taken, that none of them have been large transformative, flashy steps that would cause any kind of re-rating. There are things that we need to do both in the eyes of the industry, potential partners, potential providers of funding and service providers in order for the project to be treated with the seriousness that we treat it. We have no doubt as a Board that we embarked on the right course action. And we hope that confidence will build over time among investors, and it will come along with us on the journey, that what we've seen is that we're taking thoughtful steps in relation to financing to ensure that we are not the wrong side of the curve in terms of needing to access funds from a position of weakness and instead you build a position of strength, and we will continue that work on an ongoing basis. We will plan conservatively, and we will make sure that we have all the pieces in place to deliver on the plans that we set out just as we said that we had anticipated mobilizing the -- all American rig during September. And there's work going on, but we will only put the rig on site at a point that everything is available and that right now looks like it will be next week during the final week of September as we thought it would be. In terms of where we will drill the next appraisal well in the west, in that further update on location with Kodiak field. That will happen again when we've got all the right pieces assembled to make sure that we get the data and that we need the [indiscernible] development forward. So I'll just leave you with -- thank you for joining us to this webinar and don't hesitate if you have any questions, didn't have an opportunity to be asked here, then contact pantheonresources.com is the place to send them to. We will ensure that we respond to anything with you as quickly as we're able to look at a minimum sweep up questions and respond to people or [indiscernible]. And I look forward to addressing you from Houston once we [indiscernible] in London has completed [indiscernible] process. I'm unable to understand that should be in early November but [indiscernible] is getting together here on a regular basis already. Thanks very much, and over to you Paul.

That's great. Thank you very much, indeed, to David and to the team from Pantheon Resources. Ladies and gentlemen, please be asked not to close this session as we'll now automatically redirect you for the opportunity to provide your feedback in order that the company can better understand your views and expectations. It's only going to take a few moments to complete, but I'm sure it'll be greatly valued by the company. On behalf of the management team of Pantheon Resources, PLC, we'd like to thank you for attending today's presentation. Good evening to you all.