Pantheon Resources Plc (PANR) Earnings Call Transcript & Summary

Good afternoon, and welcome to the Pantheon Resources plc Investor Presentation. [Operator Instructions] The company may not be in a position to answer every question received during the meeting itself. However, the company will review all questions submitted today and will publish responses where appropriate to do so. Before we begin, we'd like to submit the following poll. I'd now like to hand you over to David Hobbs, Executive Chairman. Good afternoon, sir.

Good afternoon, everybody, and good morning to those who are in the United States. Thank you very much for joining us. Before we begin, let me start by saying that both Bob and Justin are very much alive, well and fully engaged with what we're doing. One of the questions from the last webinar and submitted to this one was asking the question. Our plan was not to have everybody on every webinar, but those who were associated with the specific content that we're presenting. The webinar today is about the Ahpun field and the Alkaid-2 results. But before we get into the topic matter, I'm obliged to share our disclaimer and you'll have the opportunity to read that at your leisure on the saved version of the presentation. So Ahpun, as everybody should be aware, is the accumulation that includes the shelf break deposits, the Alkaid zone of interest in the deeper section of that encountered in the Alkaid-2 well and potentially in the future, any of the slope plan systems. The expected ultimate recovery from that set of accumulations is 500-plus million barrels of oil or pipeline liquids into Trans Alaska Pipeline. And so we'll be going through today the specifics around Alkaid-2 and how that feeds into the Ahpun development. The next webinar will be after we've RNS-ed the Netherlands Sewell & Associates report. That is expected by the end of this month, and we will schedule the follow-up webinar to discuss and allow questions and to cover the presubmitted questions on Kodiak that we weren't able to cover in the last webinar or this webinar at that time. So the main presenter today will be a combination of Tony and Michael. Michael joining us from Anchorage; Tony here with us in Houston. And so many of you know or have seen Tony before. He is drilling and operations and completions expert at many outstanding drilled and completed hundreds of wells, and has come at this from -- looking from the outside in, having opting to review all the data. And what he'll be presenting today is his assessment of the Alkaid-2 well because he joined the company after that data was gathered. And I'm delighted that he's had that opportunity to review and has decided to join the company on a full-time basis. And we welcome you aboard at the last webinar, I mean we welcome you aboard again. But don't expect it to happen too often. This is probably your last welcome to the Pantheon team. But my guess from knowing Tony for a number of years is he wouldn't have joined it if he didn't think of something exciting here. So, Tony, with that, let me hand it over to you.

Well, thank you, David. You're right in that assessment. I think you've got -- Pantheon had a fantastic opportunity here and very promising and from an engineering standpoint, very intriguing. So I'm honored to be a part of the team. My goal when I first joined is one of the tasks that Jay gave me was to go back and look at the completion efforts that we did on the Alkaid-2 and kind of discussed the performance of where we thought we were with the Alkaid-2 and how we could improve the Alkaid-2 in future -- Alkaid development well, let's say, offsetting the Alkaid, what do we need to do to improve the performance? And so those are the goals that I'll try to achieve in today's discussion. What you see up here in this chart is on the left is the decline curve with the historical production from the first 30 days. The top left curve is the oil, the bold line is to forecast. The lighter colored line is the actual historic from our flowback history from February and March. The bottom left curve, the red one, is our gas production that we experienced during the flowback on the Alkaid-2. And again, the bold line is to forecast tied back to the actual production.

Tony, I apologize. Somehow the bottom right has got flipped in the transition from PowerPoint to PDF. That's my fault, not yours.

I thought I was going to have to stand on my head to read this. So the economics is presented in that curve that's actually turned sideways. But what it yields, and it shows us that the EUR is 260,000 barrels of liquid, which includes the NGL and the black oil that we produced. That ties back to the initial 30-day production test, which we call a 30-day IP, which is a 30-day practical production test, if you will, of 505 barrels per day. That does include the NGL liquids that we have from the gas. The economic value of that forecast and historic is at $6.5 million on a net present value of 10%. That is based on a $70 a barrel at the well head. So this is the goal that we hope to -- that we intend to discuss today, and it's really just a post analysis of the fracture treatment we did on the Alkaid-2. And a couple of key points that are going to come out is we want to discuss the pressure response, a typical pressure response of a hydraulic fractured system and that was presented years ago by a scientist with Amoco Co. named Ken Nolte. And then the part of the discussion will be what is our pressure response telling us about the frac extension and, more importantly, about the effectiveness or efficiency of our frac, hydraulic fractured program. We want to determine how our treatments compared to other effective treatments in unconventional bases throughout the U.S., and we'll see a slide that will discuss how treatment started in the unconventional world. We'll call them generation 1 and then so on through generation 4. And then what we're going to do is also look at what causes sand flow and remedies in future treatments. This is the treatment that was done on the Alkaid-2, and I'm going to pass this off to Michael because he was the one that was involved in a lot of this work before my time.

Thank you, Tony. Hopefully, you can hear me well. Yes, I want to walk through the quick overview of the design and some of the philosophies that went into it real briefly. To just set the stage with this first time interaction at this level of formation, we took some steps to be conservative. The idea being that reliably pricing a fracture treatment was paramount. And the cost of consequences from not understanding how to interact with formation could be severe if we didn't pick a reliable treatment. And so we did so. With spacing, we picked the target stage spacing of about 150 feet, and that was mostly successful, some minor adjustments on the fly. For perf cluster spacing, we spaced a perforation cluster, is about 26 feet, shot 72 holes. That's about twice the holes that were needed. And we took a philosophy once again, trying to ensure success of over perforating that giving some room for contingency if there was trouble with perforations not opening up or near wellbore issues. And so that's certainly an example of a decision that was made to put us on the more conservative side and ensure placement. We use 40-70 sand with a 30-50 tail. It's once again not understanding the formation, how it would flow yet this first time to interact at this level. That's a coarser profit. Part of that is for supply chain reasons and part of that was for the reason that we weren't sure how this would treat. And so we picked slightly course of proppant than used elsewhere to make sure we had high conductivity and that we weren't conductivity limited. We put a proppant concentration near wellbore that was higher than what you'd see, once again, trying to ensure good conductivity. And so we put 3 pounds per gallon near the wellbore. And you had treated nice. Our average frac grading was 0.65 and our average ISIP was 1731.

Okay. And just -- I think there's -- it will come up in questions in due course, Michael and/or Tony. It seems that there's always a risk reward in any frac design. What you're trying to do is you can crack a nut with a sledgehammer, but you may not end up wanting to eat all the nuts you cracked with sledgehammer. So you do need to find out where the limit is in terms of how much sand or how little sand you can get away with how much -- how fast you can pump, how much entry. So maybe you can speak to why is it because I'm sure it's the question that's on everyone's minds, is why is it that we didn't go to a fourth or fifth generation track immediately? Why did we choose to go the way we went? And Michael, you touched on it in terms of wanting to be conservative to make sure that we actually got the jobs pumped, but maybe you can expand a little bit on that.

I'd be glad to. We had to do a lot of new things for this one, in mobilizing sand and getting new horsepower. And plus, there are a lot of things we didn't know as in leak-off permeability and how does it treat. But being remote and trying to react on the fly to potential errors would have been very, very costly. And we had seasonal work, and it was very time constrained to begin with. And so as you said, in this case, the first thing is to make sure to use your analog, to make sure the nut was cracked even if we used an oversized hammer. And so we took that philosophy to mitigate severe complications if things went in an unknown direction, like if we couldn't get into perforations as an example. And yes, this is -- it's kind of where all the basins start on a more conservative side. You always start one operational success and then from there fine tune.

And frankly, I would add to that is, as Michael mentioned, most -- all the bases start somewhere in the same area that Pantheon started, frankly, because they don't know if the rock is going to respond the same way. And you got to get a handle on the way that rock's going to respond. I think the stage that was pumped on here clearly gives us that information that we can move forward with a more efficient design, if you will, a more effective design. But I don't think you could really design that without having this data as an input.

On which point, Tony, get to -- how effective it was the same. I'm sure I was going to...

This kind of illustrates or kind of this does illustrate the point that I was making about where do we go from. And you have to start with what did we achieve. And this is a material balance off of production history, flowing pressure and shut-in pressure. It's a combination of 4 charts. The top left is the flowing pressure over a square root time type plot. And then the bottom left curve is the type curve that would be generated based off that history match. Those black dots within those 2 curves are your actual history. And so the type curve has a really good match. And then probably the most important 2 curves or the forecast and then, which is the lower right and then the curve on the upper right gives us a lot of information about what happened during our frac job or what do we achieve. And I want to highlight 2 points in that curve. First of all, I want to point out that yellow box has nothing to do with the drainage area. It's just to highlight the probability of where we were going to try to match. And I gave it a wide range, so it could feel -- the computer could be feel free with coming up with its own numbers as far as the efficiency of our frac job. And I'll discuss that in just a second. But let me point out in that curve, you can see there's 4 items that are highlighted, but I want to draw your attention to the first one, which is the drainage area. It looks like we were draining about 42 acres out of this lateral that we drilled on the Alkaid-2. And then secondly, I want to point on the third item, which is the X of f. X of f is just another fancy way of saying frac extension, horizontal frac extension. And you can see that we -- it calculates that we've got 176 feet of frac extension. I want to draw your attention to the circle part under the table, and some of that data in that circle is already highlighted in that curve on the upper right. But one of the things I want to draw your attention to is right below the Ad, the P50 Ad is a term called P50 Nf. That number is 6. And what that shows is that's the number of stages that essentially was effective on this frac job. That does not mean there was only 6 stages out of 32 stages that took the frac. It's just a summation, mathematical summation of what the effectiveness would be of that frac. And what that tells us is our frac job was just right under 20%.

So in essence, whether it was 6 fracs at 100% or 12 fracs at 50% or if I do the math for 30%. But the point being it's just an indicator of how effective it was versus the idealized efficiency.

That's correct.

So how does that compare with the wells you've done in the Permian most recently? Is that good, bad, indifferent?

That is typical with Gen 1 and Gen 2 type jobs when people first get into a basin. But once you get a clear understanding of how the basin treats, you should be in the 80% numbers. And I'll present a chart that illustrates that later on in this discussion. We talked earlier about how the evolution of the frac treatments have changed over years, really. And so I'll put this table together to show you what Gen 1 through Gen 4 -- generation 4 type frac treatments look like. And every basin I've been involved in, in the Lower 48s has all experienced these different generational changes. And really, this generation 1, you might say, is around 2011 to 2012. But every basin that came along, started somewhere in the Gen 1, Gen 2 at some point in time. And you can see the numbers that have changed over time. For example, the stage size gotten bigger and then it got smaller and then it's kind of landed on somewhere around 180 to 190 feet per stage. There are some basins that are still in the 150-foot area. Nobody's into 250 to 300 foot, which is what started in Gen 1. I need to point out that Pantheon did a really good job of trying to capture. As Mike mentioned, there were some balancing acts that had to go between efficiency and risk/reward, as David mentioned as well. And so you can see what the Alkaid-2 look like. And the yellows that are highlighted on this table are essentially where the Alkaid-2 was as it compared to other generation. So I'm going to talk a little bit about...

Tony, sorry to interrupt you. If we go back, there's a couple of examples in there that just I'd like to highlight because we talked about some of these risk/reward decisions, but there's a couple in here that are really showcased. And for example, what I mean is -- we talk about the stage sizing. And in the case of the Alkaid, we recognized that we wanted shorter spacing on the stages, but we ordered all of our material in advance because we don't have a local sand source yet. And so having to mobilize all the sand and mobilizing all the equipment. We did so, but even in all the measures we took to keep sand dry and through all the supply chain when we got sand at the North Slope, some of it, a portion of it, was mishandled or damp and we couldn't use it. And so in that case, with reduced supply of sand, we spaced our stages just a little more because we didn't have the materials. We had to reduce our material consumption slightly. And so that's an example of the differences that were operational or the differences that were risk-based. In this case, we had to do it all planning materials well in advance, mobilizing months in advance, and we didn't have the ability to shift on the fly because of that. So that's an example on the stage spacing size, even though we recognized that we would have liked to have tightened them a little more.

And I guess, in reality, there are degrees of flexibility when you're in multi-well operation and development, you've got degrees of flexibility that you don't have when it's a 1-well operation. And so the conservatism of some of the choices is a reflection of that, also the difference between single-well and multi-well operations.

Absolutely. In the multi-well case, we could have just taken a little more from our supply chain. And that's standard and that's easily done and those decisions are common on the fly. Another example on this is some of the course of proppant. We did have to order in advance and we had never interacted with the formation at this level before. So understanding what connectivity we needed in the proppant back and how much we need to place, we definitely placed more course proppant near wellbore than was needed. And in hindsight, with the analysis and with the data, it's very easy to make that decision and adjust. With the decision being made as it was, we had to order sand month before we ever pumped. And so there was a lot of discussion about what was needed about the benefit of coarser sand or finer sand. Coarser sand was chosen and as Tony said, now with this data, it's such an easy change to make moving forward. We now know how it acted and where to go. And so these are some of the choices that were made, were done well in advance of how -- well in advance of interacting with the formation. And as you said, the operationally -- the operational success of placing multiple fracs across the wellbore is paramount. And so these are some of the early factors that went into the decision to make sure we got this done and got connection with the formation.

Great. Thanks a lot, Mike.

So first, I want to jump into this chart. This is really just a basis to give everyone an understanding of what we look at during an actual job. And there are certain things that you can see on a pressure response chart during the job. And so Ken Nolte is the guy that came up with his analysis. And so you can see the different Type 1s, Type 2s, and each job, each stage will have all of these components in it. And once you get your growth established, what you want to see is a Type 3 basically a net pressure increase during the job that you're doing. If you get a net negative pressure drop, i.e., if your pressure drops during the job, you have what's called an unrestricted frac height growth. And what that means is your fracs are going vertically. And that's not unusual because you'll grow vertically first until you see a boundary. And then once you see that top boundary, typically the reservoir boundary or heavy shale streak or something that dissipates the energy, then you'll start seeing a horizontal growth, which is ideally what you want. But I need to point out that you have to design jobs that take into the frac height grows. And that was one thing we didn't have a clear indication of what our frac height was going to be during the frac job. We can look at logs, but you're never really going to know until you actually do a job. So that is what's important about this curve. So I'm going to take these curves, this information here and I want to put it on some of the production -- well, some of the actual injection stages that we did on the Alkaid. Here are 2 stages and actually there are 2 slides or 4 stages, and I've highlighted where we sit with respect to those growth intermodals that were outlined in the Ken Nolte literature. And so what you can see is every one of our charts were in the Type 4, which means we're having a vertical growth, and we haven't maximized our vertical growth in order to start maximizing our horizontal growth. So we're -- what's interesting about this chart, and I think more importantly, on the next slide, is you can see that our net pressure Type 4 is actually flattening out. So we don't really have a pronounced pressure drop, but it's fairly flat. This is kind of indicated. And then on Stage 18 in this chart, you can see the pressure starting to just climb right at the tail end of that job. What that tells me is we just need to have a little bit more fluid and extend that job a little bit further, and we would have got a better horizontal growth. And so that's what highlights that. And then David asked a question earlier is, what do we see in some of the other basins? And I want to highlight...

If you want me to...

Yes, that's the -- so that's what we see in other basins. This is a Permian Basin job that was done about a year ago. That I did, yes, I did a year ago. So anyway, I performed or Jay did it. But anyway, what you can see is same type of net pressure negative slope in the early beginning. But then you start seeing the pressure increase. And we're looking at the red line. The red line, I guess, in the second stage is the black line. But the red line is the pressure response during the job. Both this job and the job that you guys did up in the -- on the Alkaid were pumped at the exact same rate, 80 to 85 barrels a minute. And so you're seeing a pressure increase. This is ideally what you want to see because that means you're getting horizontal frac extension away from the wellbore. And I will give -- there's a slide in, the next slide... Okay. So based on that, we looked at what needed to -- what do we need to do to change to get that kind of response on our pressure response. So our design goal was to maximize horizontal extension and to contact larger drainage area. And how we do that? We have to compensate for the frac height, we have to maximize our lateral placement and minimize our sand production during flowback, which is where we start getting away from the high conductivity and start getting into the slick water and more water pump and start using a little bit of 100-mesh. In fact, that's what you've seen in every basin is they've increased the amount of 100-mesh that they use in the jobs over time. So this is where I would propose that we go as future design. This is the actual treatment that we did that was reflected in the previous charts that we did in Permian Basin a year ago. And what you see on this one is we pumped a lot more fluid than we did in the Alkaid. And the reason why, as I mentioned earlier, are one of those last stage, I think it was Stage 18, on the Alkaid, you started seeing a little bit of vertical -- I mean, a little bit of net pressure gain. And that just tells us we wrapped here at that threshold, we needed to pump a little bit more fluid. And that's where these designs came from. And this is essentially almost twice the volume that was pumped in the Alkaid.

Fluid.

I'm sorry, yes, fluid, not sand. And so what are the goals that we put out was what will it look like if we correct or not correct, if we add a more efficient design in the Alkaid-2. So I took the Alkaid-2 and I implemented this, the frac design that we did in the Permian Basin. And this is the result. This is again the same material balance that we discussed earlier. And this time, we upgraded the production to reflect what an additional contact area would look like. And this is the match that we've got. And again, same layout. You see the pressure response and a production response in the upper left. You see the type curve in the lower left, and you see the calculated area in the upper right. Again, those blue and red line is just a probabilistic area of what we wanted to calculate to see how close we are to it. I think I would like to take away from that, and you see it in the box, and we also see it in the circle is that our drainage area doubled and our horizontal extension almost doubled. And what that gave us, and really in the circle you can see it, where we were talking about 6 stages out of 32 being the efficiency, we're now at 28 out of 32. So we're now in that 80% window that we talked about, wanting to achieve. And so that's where we plan on going forward with.

Sorry, this is -- I don't believe Microsoft has just got to get their act together because when we convert to a PDF, it seems that trips up every time. So this is, of course, the chart we showed from the previous webinar, but why don't you quickly run through?

Sure. This is if -- so this reflects what our model would have shown if we have a different frac job. If we -- and really it just simply conducting more area within the wellbore because we had longer frac extensions. And what you see it does is it yields a little over twice the EUR in the previous -- actually 3x the EUR of the previous job. And this one shows that you could achieve 1.2 million barrels EUR as opposed to 300,000 barrels. I think it's actually 260. And 1,500 barrels per day versus 505. Again, that includes the liquids that would be coming with the gas. Again, the simple economics would be at $70 barrel and the present value at 10% would yield a $29 million NPV10, and that's at a $13 million well cost. And there are additional things that we can improve, and I think we touched on it back in the June webinar was that we have the option to extend the lateral extensions from 5,000 to 10,000, which will be an additional performance increase. But that's not incorporated in these economics that we presented here.

I'm sorry, it's incorporated, the 1.2 million barrels because we [ only took that ] on ForEx. So we've taken an aggregate ForEx, which is 2x on the exception and only 2x on the ground. So we haven't assumed it's as efficient as the... Right. So one of the questions you saw in the previous chart that the model economics were based on a $13 million well cost. And I think it's useful, Jay, maybe for you and Michael to go through.

Yes. So we spent a lot of time on this. Tony helped us as well, but Michael and I worked on it extensively. And a lot of the cost, I think I mentioned in the June webinar were a lot of onetime costs. Michael talked about sand transport. But if we go from the top, of course, we drilled a pilot hole. We had some issues setting the plug to kick off that plug, but in addition to not drilling a pilot hole, Tony and Michael have worked on drilling time savings, and that's a $5 million plus or minus reduction in the cost. The frac optimization is really just the fact that we had to mobilize equipment out of both Louisiana and some from Russia. We worked daylights only. And the combination of only working for half a day and having time lost to warm the equipment up and shut the equipment down in addition to the other onetime costs are another about $4 million. The sand transport, and as Michael said, we worked literally it was more than a year, wasn't it, Michael, in advance when we started looking at where to get the sand, how to transport it and we went through many, many iterations of how to get sand to the North Slope. And of course, in the future with multiple well operations, we will have a local supplier, about another $4 million. Once you've got a pad, you don't have to put that cost in. We did an extensive logging that we would not do in the future. And there are other lots of little bitty minor things, rig commissioning, mode demo, double handling sand, water transfer system, et cetera, et cetera. We are confident. And Tony and I have talked about this, we're confident we can get down to the $13 million well cost.

Yes, there's a lot to be said. A classic example would be once we're in development, we don't have to do pilot holes. We don't have the effort involved in setting plugs to plug back, time drilling off of those plugs. So those are key elements that just add up because most everything out there is charged on a day rate anyway.

Thanks, Tony. Michael, anything to add?

Yes. I think you definitely highlight it. It's just for these one-off wells to take equipment from all over the planet and bring sand up from a different country. It's so much. And little things like for this job, we had to take time to get the new frac pumps to communicate with the existing frac spread on the slope. And so all of those things are captured here. This is certainly a reasonable progress to where it could be. And it's -- none of these are abnormal steps. Having a frac fleet that works together and communicates together on a daily basis is standard. Having local sand sources have been already identified. And so its -- this just a real representation of what changes when we move from bringing equipment all over the planet to do one well and then sending it all home versus when we have the right equipment, commissioned, ready to go on location, moving well to well. It's -- these are known and reasonable steps.

And one thing I would add to that, Michael, on the frac side. We own a fracture in the daylight. And once you get into the development stage, that's a 24-hour operation. And again, back to everything being on a day rate, your efficiency of your day is basically 15 minutes out of an hour is actually going towards work because you've got a lot of wait time.

Okay. Just to settle the daylight. This was in September. So there was actually nighttime on the slope. For those who are wondering, it wasn't 24 hours of daylight. We actually had a sunset and nighttime.

Yes, basically there was 1 crew. There is only 1 crew and that was the limiting factor.

So that brings us to the end of the formal presentation. Paul, maybe I can hand it back to you and we can run through the pre-submitted questions and then go through questions that are -- have been submitted during the presentation.

[Operator Instructions] First question reads as follows. Whilst the proposed Alkaid-3 new gravel pad not built and the well not drilled, any plans to drill there in the near future?

Yes, the additional gravel pad, which we do have a permit from the state of Alaska for is the previous name frac the pad. And we chose not to drill an additional well into the Ahpun field until we have completed the planned frac of the SMD at the Alkaid-2, which we planned for September. It's thus providing the best information on our reservoir fluid composition and our frac propagation to test the next iteration of our frac design. So it was planned for that way. And that's why we didn't put the gravel pad down and drill the well.

Next one, we've got here. We've been told by Pantheon that Alkaid-2 pilot hole in the horizontal better reservoir properties in Shelf Margin Deltaic and zone of interest. What permeabilities and processes were measured in any side wall or full core taken? Any grain size data to suggest a better reservoir? Did the Alkaid-2 multi-stack fracking horizontal liquid rates confirm better reservoir permeabilities and connectivity?

Well, let me just start by returning to an answer from last week, which is that we're going to release the tabulations of data behind some of the charts -- most of the charts to the extent we can that are shared in the webinar so that you get better accuracy, and you don't have to spend the time trying to digitize our pictures. But where we don't share detailed data, and some of that implied in the question, is detailed because it's proprietary information that's got value. For example, you're aware of the data trade with 88 Energy on the Hickory well for the Talitha well. So if we give away too much information, then we potentially limit future commercial opportunity. But we will, in due course, and particularly when the Netherlands Sewell report on the first stage of Ahpun is released, there will be some more data on that. But yes, the permeabilities and porosities were better. Why don't I hand it over, Michael, maybe you want to...

Sure. On the Alkaid, we were able first time to interact on a big scale. And enjoying the horizontal, what we saw is that the reservoir continuity and then we saw porosity-permeability throughout the extent of it. And so that gives us a lot of excitement in moving forward with the Alkaid and with the future developments of that system. When we look at the Shelf Margin Deltaic, we haven't interacted with it at this scale. And so we're very anxious for that test and to see how it will come together. And we're ready to move forward.

Next question here is, does anything stuck sidewall core testing or well logging, NMR, et cetera, in the Pantheon wells provide water saturation data to differentiate bound versus mobile water saturations?

I think, again, probably we're not going to get into the great detail of that. The core log analysis does provide estimates. The flow test actually represents the empirical evidence. So it supercedes whatever you might do from the core log. And we confirm that there will be some mobile water in all wells from the start of production. I think we'll deal with it more specifically later in the questions. But we know we're going to have to handle water and sufficient gas volumes through reinjection into our own reservoirs for recovery, or at worst and maybe piping gas North to Prudhoe Bay as happens from some other fields on the North Slope. Or even if the Alaska Gas Development Corporation's pipeline goes ahead and that's going to track down the corridor of caps [indiscernible]. So there may be a lower cost opportunity to sell gas there. But we're not relying on it. We've made the assumption that we're going to have to deal with produce water and produce gas and reinject it.

And David, the next question again is around that water flow back, some of which I think you've covered off and if you've anything further to add. In the Alkaid-2 horizontal well test, describe the water flowback and saliency results to suggest the frac water was coming back or they had been imbibed into the reservoir. And if the shorter-term test, does any water cut flow back into inflow suggest mobile formation water concerns?

Michael, why don't you take that?

Sure. Of course, when we bring the well on, it's all frac water and some of these are fresh, so as expected. When we shut in Alkaid-2, our estimates are 60% to 70% of the water being produced was formation water and the subsequent 30% to 40% is the frac water. There is mobile water from formation and we anticipate that. In all of our wells, we expect somewhere around a 50% water cut is where these well level had overlie.

And that's not unusual. I mean that's pretty standard in many, many basins around the world.

Next question we've got, did the Alkaid-2 well test have slugging problems, water, oil and gas rate plot plus pressure data would be illustrative to understand reservoir and operational behavior? I know you've touched on some of these points, David, but if there's anything to add to that.

Yes. I mean, as we said, we'll post the Excel file that has the daily water, gas, oil. It will include also the calculation of the NGL yield from the gas to give you the inferred total liquids rate. The simple answer to the first part is, no, we didn't have slugging problems.

That's great. What permitting and time line would allow development and production for Alkaid-2? Does the distributor zone near the Dalton Highway require an environmental assessment or environmental impact statement?

Well, we did reference in our recent RNS and the webinar that we've begun seeking the required regulatory approvals for both the TAPS -- hot tap and free Ahpun field development area. Being situated in the stub area and so close to the pipeline in the Dalton Highway, it offers such a tremendous advantage. We've talked about location, location, location in our development scenario. So we're moving forward on that as we speak.

That's great. The Alkaid-2 result disappointed the market with a lower flow rate than expected and a mixture of hydrocarbons, including oil compensate, NGLs, et cetera, not pure oil, yet your strategy webinar appeared to be based upon a development mode of a perm. The stock price tells you the market isn't convinced by Alkaid. What is it that will give you confidence that you can make it to development?

Tony, why don't you take that?

Sure. Well, the company's post well analysis indicate that the frac treatment delivered somewhere around 20%, 25% -- actually 20% of what the theoretical design was to achieve. This can be explained either by less lateral extension of the frac wings into the reservoir or only by a small portion of frac stages actually contributing to the production or a combination of both. We're currently working with SLB, which is the Schlumberger Group engineering team. And we've explored the opportunities to improve the frac outcomes. I think we're all on the same page of what we need to do. And I touched on that a little bit earlier in the discussion about how we need to improve the frac treatments and they're currently working on that as well. And then as we mentioned earlier, also, we have the opportunity to extend the lateral length in future development wells to 10,000 foot. Experience of other basins where multiple stage fracs of long laterals have been successfully deployed. It shows the efficiencies have dramatically increased. And that's really why there was a shell boom for so many years is because of the success of the hydraulic fracturing. And Jay, I think you want to add to that.

Yes. And also, we have not assumed any change in the compositional mix of the reservoir fluids and the quality bank adjustments appropriate to that mix of oil condensate and NGLs. Nor the quantities of the gas require reinjection or otherwise. So we're taking that all on board and planning for it.

Great. Alkaid-2, the gas oil ratio was greater than predrill expectations. Can you explain the possibility that we intercept the gas cap with the frac? But you also mentioned another theory that it was a kind of solution gas. Can you please explain your current thinking and how important this conclusion is to the planning of future wells?

Sure. I think it was in the March webinar that this question also came up when the possibility of a gas cap was first muted by our going from SLB. We've not seen on logs or in any drilling cuttings or anything evident to suggest that there is gas cap. It is one of a number of potential scenarios, but it doesn't actually make any difference. What we know is the empirical result was that we produced more gas than was originally expected, and that we're expecting and planning for there to be more gas than originally expected going forward. It may have fracked in to the unseen gas cap. It could be that the reservoir is absolutely at the bubble point and that any drawdown is going to release excess gas. I think we talked about thinking in terms of if you shake a bottle of Coca-Cola, you're going to release a lot of gas. And that's because when you take the top off, you drop below the bubble point of the Coca-Cola in the bottle. So that's what we're planning for. We will probably drop the laterals slightly deeper into the reservoir, but we know that over the life of these wells, we're going to be producing at below bubble point as soon we get any appreciable drawdown, that's why we have to plan on there being a lot of gas produced with the oil and that we will be stripping liquids in order to create combined stream and multiple liquids to go into the main oil line of the taps. But the key point is the volumes we're planning for are based on the models that Tony and Michael have discussed or being able to get twice the IP30 from doubling the lateral and no more than twice from improving the efficiency of the frac. And as Tony said, doubling the efficiency of the frac is a very demanding target. And I think that, that speaks to why we have great confidence in the commerciality is that we're well within the envelope of commerciality if we simply achieve half of the efficiencies that other basins are with their multi-stage horizontal fracking.

Next one, you did cover off on the slide in the presentation. Just in case anything further to add, please, can you comment on the implications for Pantheon share price and valuations of achieving a $13 million cost per development?

Well, I would just say that, obviously, we did talk about it, and we're very confident that we can achieve that $13 million target.

But just to be clear, commerciality doesn't depend...

Does not, yes. We're commercial well above that number. But obviously, the lower that number, the better off we are.

That's great. Can you provide guidance on the potential range of improved flow that such frac design improvements could deliver and their implications to project value? Are there any potential risks with these planned improvements?

Well, I think, Tony, you covered that mostly in the presentation, but do you want to add any comments?

Sure. Like you said, I think we did that in the presentation, but I think the frac design, again, in summary, just needs to be a little bit bigger on the fluid. We need to focus a little bit more on the lighter proppant and less on the connectivity and probably reducing the perforation. Now that we know how the well is going to take it, we can feel with confidence we can reduce the cluster perforations to half of what we shopped before. So I think all of those things are going to improve the stimulation that we propose going forward.

And you're confident that we can achieve the kind of improvements that you talked about.

I am.

That's why you said it.

That's why you say that.

What work has been done post SMD blockage to ascertain reason and avoid repeat for Alkaid-2 SMD test?

Michael, do you want to...

Yes, it's -- there's no unambiguity until we've seen particularly yet nor have we had opportunity to investigate it further within the intervention. So the answer to that I think is the most clear is that we're working with our frac design, working with engineers, service providers to ensure that we address all potential concerns. And by that, for example, I mean swelling clays, I mean chemical compatibility, I mean fluid compatibility. And so we've successfully placed a lot of fracs, not exactly sure what the results were, what caused the difficulties at Talitha. But we will take every step to make sure that we won't proceed forward until we've taken every step to ensure that our fracturing that will be compatible with the system.

Again, something that we've covered off a little bit here, just talking about vendors. But for the frac optimization, it was mentioned during the last presentation, I think, again, here, the very high cost had to be paid due to being held hostage to a single vendor. How did it come that we're in this situation, how do you know it's not going to happen in the future? For the sand transport, how did it come that we didn't use a local vendor, something you have touched on? And why did you go to -- why did we go to a vendor in Canada? Could you please disclose the names of these 2 defenders or selling for commercial reasons that may not be possible? Back to you.

We went to Canada because that's where we could get the quantities of sand that we needed. A single vendor, obviously, it wasn't our choice to have a single bidder bid on those. We went to multiple vendors for every operation that we were conducting. And in the end, there was a single bidder that had bid on the frac treatment. We had one rig that we could use as a result of many things we've talked about in the past. Michael, do you want to add anything?

Well, just before you do, I was just going to say, we've touched on this point, we've more than touched on this point multiple times. When you're drilling one well in isolation, the -- it's not exciting enough for service providers to be putting forward their best foot mobilizing their equipment and our beck and call. In terms of the initial discussions we're having with service providers for the development stage of the thing, it's an entirely different tone of conversation because with long-term visibility, they're prepared to sharpen the pencil to try and win the work because the development of Ahpun is a 500-plus well development. The development of Kodiak is more than 1,000 wells. And if you think through what the proportion of the service costs related to the drilling contractor, related to the pumping contractor, related to the sand supply, these are material quantities that can be planned along in advance, and we're finding that the time of those conversations is entirely different.

The only thing I'd also like to add, that's very well set on both parts is the time with which we did the Alkaid-2. And just to look back, that was the time of pandemic of supply chain strikes. That was a time of high oil price and personnel shortages. And so we had lots of vendors that said, I have the frac iron, but I can't get the people to drive it up to you. And we will not take that risk without a personnel. And so a lot of those have eased already just because the pandemic has quieted down. The trucker strike in Canada is over, the oil price boom is now better staffed and all of the vendors have gotten more iron available and more people. And so -- once again, we still have to fight these one-off wells, and we still have a long ways to go. There are still some challenges that will -- the development will solve, but there are also some additional challenges of the Alkaid-2 timing that have eased.

Okay. Were there any mistakes made during the first design that could have been avoided open brackets with the information that was known at the time?

Well, I think we addressed that pretty well in the presentation as to the trade-offs and risk management. So why don't we move?

Sure. No problem. And the next one we've got, what was the justification of the previous Alkaid-2 well design? Why wasn't 10,000 feet lateral used initially? Again, I think you have covered some of that off as well.

But one pipe availability, cost, looking at what we wanted to learn, we felt we could learn with a 5,000-foot lateral. It was a more of a test well than a full-field development well. And all of those led into -- and time, timing pressures led into drilling a 5,000 foot versus a longer lateral.

Why did Pantheon decide to stop trucking Alkaid-2 oil and NGLs for sale to taps before the flaring permit expired? The well was already paid for, and if trucking the oil was profitable, it could have been used as a source of cash for the year.

Well, we ended our first 90-day permit. We did not have a permit from the state to flare for 270 days. What they actually told us is we will give you a 90-day permit. And after that time period, you can come back and ask for an additional 90-day permit. We have the data that we desired, and so it would have been a very, very public hearing again. We were flaring a lot of gas and liquids. And so we chose not to extend that, plus it was not truly profitable with all the add-on cost to truck the oil up to...

And of course, all that we were selling because we didn't have...

Yes, we have -- yes, we were selling only the black oil. We weren't -- we didn't have a refrigeration unit, so we could capture the condensates and the NGL. That would have made a huge difference since we've had that -- those additional barrels.

Okay. That's great. With regards to the move of HQ to Houston, is it planned to move the legal entity from the U.K. to the U.S.?

The answer to that will depend on the tax and regulatory advice. Our goal is to make sure we can access the best capital market, whether that's with a purely U.S. listing or it's a joint U.K.-U.S. listing, whether we're listing up as a foreign issuer on a U.S. exchange or we are making the holding company, a U.S. entity, that will be the result of the initial work that we've begun with tax advisers on processing the answer. So I don't have a specific answer for you, but I can also tell you that it's not predetermined.

That's great. What makes you think you've done enough to guarantee being able to raise the 350 million for the Ahpun development?

There are no guarantees, let's just be clear. We believe that by opening as many different channels of potential financing, that includes we've gone through them extensively. And in the interest of time, I'm not going to go through it again here. But we're trying to come up with a resilient plan, which is not held hostage to any individual channel of finance freezing over that we don't require all the money at once. We are looking at those structures that deliver the lowest viable dilution of value for investors, whether it's dilution into the asset or it's dilution into the corporate equity. Because we recognize that we want today's owners to end up owning as much of the value as possible. And our plan is that as we do the right things in the right order to move towards that strategic goal of delivering a sustainable market recognition of $5 to $10 per barrel of expected recoverable resource, there will come a point at which that future becomes inevitable. That will become a point at which a discounted version of that value instead of representing $0.10 a barrel will move towards whether it's 2.5, 4, 5, up to 10, depending on exactly where we're at and what the oil price outlook is, et cetera. That's where the growth and the leverage to investors comes from.

I know you just have gone through the hour, but we've got one more pre-submitted question. If you have got the time there are amps of questions during the meeting itself. So let's just get on with the last one. The last webinar raised doubts on proceeding with the SMD test if the necessary equipment price was too high. Given the last fund raise was in part, especially for the SMD test, with the lack of an appropriate test rate ethical and compliance issues.

Look, yes, if we did no test, then, of course, there will be an issue having said that we were raising the money to do the test. We may have done too good a job of explaining why we're not prepared to be held hostage, but that's not as to a binary will we or won't we do the test. That's about the scheduling with which we're prepared to move forward. And if delaying slightly delivers a better price for doing it and maintains our leverage in the negotiation with service suppliers, then we're absolutely prepared to do that. But we have ring-fenced the money that we raised. That portion to achieve that test, we absolutely fully intend to proceed with that test. But we won't hold to a predetermined time line if that leads to costs that we don't think are reasonable for shareholders to bet.

And right now, we're still planning on a September start for that test.

That does conclude the pre-submitted question. As I say, you see you've had a number to coming through during today's presentation. Thank you to all the investors for those. [Operator Instructions]

Happy to do so. So first one on the list, although it doesn't look like it's first in terms of the time stamp, presented an ideal frac for Alkaid-2 with this approach work the same in, say, the SMD and would you be having to guess and adjust the future wells. Broadly, the stack of formations with the SMD at the top underneath the regional top seal down into the zone of interest, the rock mechanics are already similar. So we anticipate that the improvement in design that we've learned from the Alkaid to frac would indeed allow us to move a step forward in the SMD test. That's the reason we're doing it, and also to get a good sample of the reservoir fluids in order to...

I'm thinking it's transferable across to the other reservoirs, too. So we think it's transferable across all of our reservoirs.

Next one, how much frac water is left to be recovered? I think Michael addressed broadly that we were at 70% formation water at the time...

30% frac.

Yes, we're still some. But in truth, we were heading towards a point at which we could see that 50% water cut in new one. The next one, the RNS said, initial analysis indicates significant improvements in reservoir quality, which could lead to a material upgrade. We'll be able to talk about revised figures when the Netherlands Sewell report on the Alkaid zone of interest, which is the first part of the report on the Ahpun field overall. And then in due course, as we add the SMD into the Ahpun assessment, we will RNS the results and share. And that's what we're able to share those revised figures with people. John R. Let's see -- sorry, in the drilling in the gas capital -- yes, well, I think we discussed that, but we haven't observed a gas cap directly anywhere. We have observed a proclivity to produce gas at very low drawdown, which is consistent with being at or right at the bubble point. And so all our planning is on the basis that we're going to produce gas. Even if we drop down in the reservoir, the drawdown at the wellbore and more broadly in the reservoir is always going to pull us down to below the bubble point and we will produce a lot of gas. What's the assumption guarantee -- what's the assumption of gas production and forecast you presented? We've just assumed that there is no change from what we accounted, which we think is a worst case. And so we wanted to make sure that we were comfortably commercial without having to invoke any improvement in performance. Will we need supplies as results? Will we need supplies from Russia for future well operations? Other alternatives if Russian suppliers become unavailable. Mike, I think we're not planning any Russian supplies in the SMD frac, and our next activities won't assume any Russian suppliers. I think it was just there was a point, again, when the world was a different place where you got what you can and where you can.

Correct, yes.

Status of the NSAI report, so we're still anticipating the Kodiak report before the end of July, and we will RNS it in its entirety and have webinars discussed and address any questions on the report and on Kodiak more generally. How many wells will be needed for Ahpun? We expect some 500 wells producing, and we think that we need -- right now, our plan conservatively is for every 3 production wells, we need 1 injection well. But that's the base case from which any optimization, whether it is moving gas to up to Prudhoe Bay or it is if there were a gas pipeline being able to sell into that would obviously be the other thing we did. What is the minimum result you need to say to make this next stage viable to raise in order to finance it? Well, the answer is what we need from Netherlands Sewell is an estimate of resources that demonstrates that we're exceeding the commercial threshold. And the commercial threshold is set by what is the cost of capital necessary. What's the rate of return necessary for capital to be applied, and for there to be enough gap between the rate of return and the cost of capital to create material present value per barrel because there's no point in moving forward with something if your hurdle or if your cost of capital was 12% to 15%, would you move forward with the development that only provided 20%? Probably not. But if you've got a development that provides 50% rates of return, then probably yes. And as we showed individual wells, the marginal well that you had is extremely high rate of return, much higher than the average field development rate of return. Michael, do you want to just respond to some operational changes in frac treatments as a result of damage to some frac sand in transit? What changes are you making to reduce the risk of the repeat?

We've been working with our source specifically. So the fascinating thing is the sand was handled 5 different times from source to being able to pump it. And so -- we've gone through each of those 5. Some of them will be eliminating. So we'll be wrapping sand differently at the plant in the future if we buy from the same plant as expected. So we'll be wrapping it and using that, using moisture control to ensure that it's wrapped appropriately and ready to go. We'll load it into CONEX as soon as possible, even though it's already double bagged wrapped. So it'll take effort on that front. And then we'll do quality control checks at each point to better identify if and where the problem arises. Then last, we'll have especially for the Shelf Margin Deltaic, we'll have the ability to supplement if we do see some in advance. And so all those will assure that as long as we're using the supply chain, we can identify and correct any issues.

And of course, long term, we will have a local supplier. So that will mitigate a lot of that -- the handling issues long term.

And sand capabilities.

Yes, that's the next question. And so just to be clear, again, when you're only dealing with one well and no reliable long-term offtake. Local supply is not going to invest or at least if they are, then they're going to look to recover the whole of that investment in one job. So the answer is we anticipate local supply that we're working to develop with a local supplier, a long-term relationship that will guarantee the frac in the time frame necessary for the upcoming and subsequent Kodiak development. Next Alkaid cost. So the next Alkaid well, if it's not part of an overall program, there's no chance of getting down to $13 million because of the reasons we discussed about the difference of moving from a one-well operation to a multi-well operation. we are forecasting that it will take us a few wells to get down to the $13 million, and that our funding plans have made assumptions that our initial wells are more expensive than $13 million each. Why didn't the company raise more funds last year? I don't think we did raise money last year. It was the year before, if that's what you're talking about. And we raised $90-something million -- sorry, I think I misinterpreted. Why didn't we raise any money at all last year. Sorry, rather than why wasn't the fund raises we did larger. I think we addressed that in the last webinar as to why we didn't. But again, there are reasons for raising money at particular times and the ability to raise money at particular times and hindsight makes it much easier to know when you should have raised money that you didn't. It's quite clear that things didn't work out the way that we are anticipated when the decision was made not to raise money last year, but we have to deal with the world as we find it today rather than as we would wish it worked out. And that's what our strategy is designed to address, which is not only the world as we find it today, but also to be resilient to a number of different states of the world going forward. Were in a merger with another nearby explorer office and economies of scale for development shared services on the North Slope? I'm assuming that, that refers to 88 Energy on the basis that I think they're the only nearby explore. We are working extremely cooperatively with them in terms of sharing information between the companies to give them the best chance of having a success with the Hickory well test. And we're also looking at how do we benefit each other by sharing services and procurement, where that's appropriate. You don't need to merge with anyone to achieve that result. So we -- yes is the answer. We are certainly not being standoffish in terms of being prepared to work with anyone to achieve the best result for everybody. David P. asks, is there a reason why you show 1 billion barrels recovered for the Kodiak where previously, we've given a figure of 1.7? The 1.7, if you remember, was the combination of the lower basin floor fans and the upper basin floor fans. My memory is that, that was about 1.4 and just under 300 million. So the number, in round numbers, we're showing about 1.5 for Kodiak as it is right now. It's not that there's been any specific downgrade. It's literally just trying to reflect order of magnitude numbers. The actual number for Kodiak will come from Netherlands Sewell before the end of the month on current schedule, and so we expect that to...

And we're focused on the lower basin floor pan right now...

Yes. What additional costs due to Alaska climate exists versus lower 48 explorer, higher wages, lower updates versus down dates, et cetera? I don't think we've got a specific answer for you on that. Can I ask that you submit that question to [email protected] so that we don't lose it, and so that it's top of our minds when we come off this webinar and we will send to you a considered answer to that rather than something off the top of our heads? Steve H., given that Alkaid left us with an 85% loss on the share price, is that not an argument to proceed with in the next 6 months on production test and doing that demonstrates conclusively the desired improvements to improve the share price? So the answer to that is, there are arguments for spending money on a variety of things. And clearly, there were some actions that may or may not increase the share price. The current overhang on our share price, I think, is not so much a technical question as a perception that we need to raise more money. And so before we would move to an additional long lateral and multi-stage frac of a well in Ahpun, we would want to make more progress in terms of getting all the right things done that allow us to demonstrate the ability to raise finance because clearly, if all we did was to raise additional equity in order to invest in an additional well, then it wouldn't have entirely addressed one of the overhangs on the share price, which is how much are you going to be raising and the perception that funding was the biggest overhang. So our strategy is not a go from here to there without many intermediate steps. But at the same time, we are -- there are many facets to what we're doing that are designed to minimize overall dilution. And there's no one action within the strategy that at a stroke solves the dilution problem. So that's the reason that we're not proceeding Alkaid level for one option versus doing all the right things in the right order under our strategic objective. [ Taylor Bell ] asks what happens in my AIM shares if you list in the U.S.? If we did end up with only listing in the U.S., then, of course, it would be because there have been a share exchange that meant that everyone who owns shares on the AIM, own the same proportion of the company of the U.S. listing. We're not saying at this stage that we know for sure that it's not going to be a dual listing. It may be that we upgrade the AIM listing to a full LSE main board listing and have a dual listing. I'm now speculating because I don't want to preempt the advice. What we won't do is incur our necessary tax leakage, and we want to consider it from the perspective of investors, not just in the U.K., but in Australia and Singapore and the Middle East, in North America or in Mainland Europe as well. And there are probably investors from other places as well. So we want to do a comprehensive job of making sure that we make the right decision on where to list, and to weigh any cost of that against the improved access to capital on better terms than otherwise we would be able to do. And I think that brings us to the end of all the questions, including the ones that were submitted live on that. Apologies for running over, but we felt it was more important to have left no question unanswered or if we couldn't answer it to provide a path either to an answer or explain why we weren't going to answer it. In summary, what we've shared with you today is the analysis -- the principal analysis of Alkaid-2, why it is that we are confident that we've demonstrated the reservoir is capable of supporting completions in 10,000-foot laterals, multi-stage frac that will comfortably exceed the economic threshold and support our ambition, firstly, to develop Ahpun to then use cash flow self-sufficiency to prevent us from being victim to outside forces as we move into the development of Kodiak, give us the negotiating leverage with our service providers and with potential industry partners in order to minimize the value dilution, all designed to deliver a strategic objective of sustainable market recognition of $5 to $10 per barrel of expected ultimate recovery by the time we get to Kodiak final investment decision through [ May '28 ]. With that, Paul, let me pass it back to you.

Fantastic. David, thank you, and the rest of the team, for updating investors today. Can I please ask investors not to close the session. You'll be automatically redirected to provide your feedback in order that the team can better understand your views and expectations. It's only going to take a few moments to complete and that's 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. That concludes today's session, and good afternoon to you all.