Good afternoon and welcome to the Pantheon Resources plc investor presentation. Throughout this recorded presentation, investors will be in listen only mode. Questions are encouraged, can be submitted any time using the Q&A tab situated in the right-hand corner of your screen. Just click Q&A, scroll to the bottom, type your question and press Send. The company may not be in a position to answer every question received during the meeting itself. However, the company review all questions submitted today, and we'll 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. 1 of the questions from the last webinar and submitted for this 1 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 result. 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.
Ahpun, as everybody should be aware, is the accumulation that includes the shelf break deposits, the Alkaid zone of interest and the deeper section of that encountered in the Alkaid-2 well, and potentially in the future, any of the slope fan systems. The expected ultimate recovery from that set of accumulations is 500+ million barrels of oil or pipeline liquids into Trans-Alaska Pipeline. 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 Netherland, Sewell & Associates report. That is expected by the end of this month.
We will schedule the follow-up webinar to discuss and allow questions and to cover the pre-submitted questions on Kodiak that we weren't able to cover in the last webinar or this webinar at that time. The main presenter today will be a combination of Tony and Michael joining us from Anchorage, Tony here with us in Houston. Many of you know of or have seen Tony before. He's a drilling and operations and completions expert of many years standing, drilled and completed hundreds of wells, and has come at this from looking from the outside in, had an opportunity to review all the data.
What he'll be presenting today is his assessment of the Alkaid-2 Well, because he joined the company after that data was gathered. I'm delighted that he's had that opportunity to review and we welcomed you aboard at the last webinar, but I mean, welcome you aboard again. But don't expect it to happen too often. This is probably your last welcome to the Pantheon team. My guess from knowing Tony for a number of years is he wouldn't have joined it if he didn't think there was something exciting here. Tony, with that, let me hand it over to you.
Well, thank you, David. You're right in that assessment. I think you guys, Pantheon had a fantastic opportunity here and very promising and from an engineering standpoint, very intriguing. I'm honoured to be a part of the team. My goal or when I first joined this, 1 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 discuss the performance of where we thought we were with the Alkaid-2 and then how we could improve the Alkaid-2 in future or Alkaid development wells, let's say, offsetting the Alkaid. What do we need to do to improve the performance? Those are the goals that I 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 for the first 30 days. The top left curve is the oil. The bold line is the forecast. The lighter coloured line is the actual historic from our flowback history from February and March. The bottom left curve, the red 1, is our gas production that we experienced during the flowback on the Alkaid-2. Again, the bold line is the 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. The economics is presented in that curve that's actually turned sideways. 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 produce. That ties back to the initial 30-day production test, which we call 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 PV-10.
That is based on a $70 barrel at the wellhead. This is the goal that we intend to discuss today, and it's really just a post-analysis of the fracture treatment we did on the Alkaid-2. Couple of key points that are go ing to come out is we want to discuss the pressure response, a typical pressure response of a hydraulic fracture system. That was presented years ago by a scientist with Amoco, a guy named Ken Nolte. 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 hydraulic fracture program. We want to determine how our treatments compare to other effective treatments in unconventional basins throughout the U.S.
We'll see a slide that'll discuss how treatments started in the unconventional world. We'll call them generation 1 and so on and through generation 4. What we're go ing 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 go ing to pass this off to Michael because he was the 1 that was involved in a lot of this work. This is before my time.
Thank you, Tony. Hopefully you can hear me well. Yeah, I wanted 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 placing reliably a fracture treatment was paramount, and the cost of consequences from not understanding how to interact with the formation could be severe if we didn't pick a reliable treatment. We did so. With spacing, we picked a target stage spacing of about 150 feet, and that was mostly successful, with some minor adjustments on the fly.
For perforation cluster spacing, we spaced our perforation clusters 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. That's certainly an example of a decision that was made to put us on the more conservative side and ensure placement. We used 40/70 sand with a 30/50 tail 'cause once again, not understanding the formation, how it would flow yet, this is the first time to interact at this level. That's a coarser proppant. 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.
We picked a slightly coarser 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. We put 3 pounds per gallon near the wellbore and, yeah, it treated nice. Our average frac gradient was 0.65, and our average ISIP was 1,731.
Okay. Just, I think it'll 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 know, you can crack a nut with a sledgehammer, but you may not end up wanting to eat all the nuts you crack with sledgehammers. 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, you know, how fast you can pump, how much entry. Maybe you can speak to why is it. 'Cause I'm sure it's the question that's on everyone's minds, is why is it that we didn't go to a 4th or 5th generation frac immediately?
Why did we choose to go the way we went? 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 1 in mobilizing sand, in getting new horsepower, and plus there were a lot of things we didn't know, as in, leak off permeability and how this would treat. But being remote and trying to react on the fly to potential errors would have been very, very costly. We did seasonal work, and it was very time-constrained to begin with. As you said, you know, in this case, it was the first thing was to make sure to use your analogy, to make sure the nut was cracked, even if we used an oversized hammer. 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.
Yeah, it's kind of where all the basins start on a more conservative side. You always start, want operational success, and then from there, fine-tune.
Thanks.
You know, frankly, I would add to that, as Michael mentioned, most all the basins start somewhere in the same area that Pantheon started, frankly, because they don't know if the rock's go ing to respond the same way. You got to get a handle on the way that rock's go ing 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.
All right. Well, on which point do you want to get to, how effective was this? I just realized I've got a bright window behind me, so I'm just go ing to change that while you talk.
This does illustrate the point I was making about where do we go from. You have to start with what did we achieve? 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. 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. The type curve has a really good match. Then the bit.
Probably the most important 2 curves are 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 frack job or what did we achieve. 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 go ing to try to match. I gave it a wide range, so it could feel free with coming up with its own numbers as far as the efficiency of our frack job. I'll discuss that in just a second. Let me point out in that yellow.
In that curve, you can see there's 4 items that are highlighted, but I want to draw your attention to the first 1, 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. Then secondly, I want to point to the third item, which is the X of F. X of F is just another fancy way of saying frack extension, horizontal frack extension. You can see it calculates that we got 176 feet of frack extension. I want to draw your attention to the circle part under the table. Some of that data in that circle is already highlighted in that curve on the upper right.
1 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 frack job. That does not mean there was only 6 stages out of 32 stages that took the frack. It's just a summation, mathematical summation of what the effectiveness would be of that frack. What that tells us is our frack job was just right under 20%.
In essence, whether it was 6 fracs at 100% or 12 fracs at 50% or I can't do the math at 30%. The point being, it's just an indicator of how effective it was versus the idealized efficiency.
That's correct.
How does that compare, you know, 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. Once you get a clear understanding of how the basin treats, you should be in the 80% numbers.
Right.
I'll present a chart that illustrates that later on in this discussion.
Cool. Okay.
We talked earlier about how the evolution of the frac treatments have changed over years, really. I put this table together to show you what Gen 1 through Gen 4, generation 4 types of frac treatments look like. Every basin I've been involved in the lower 48s has all experienced these different generational changes. Really, this generation 1, you might say, was around 2011 to 2012. Every basin that came along started somewhere in the Gen 1, Gen 2 at some point in time. 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 180-190 feet per stage.
There are some basins that are still in the 150-foot area. Nobody's in the 250-300 foot, which is what started up in Gen 1. I need to point out that Pantheon did a really good job of trying to capture. As Mike mentioned, there was some balancing acts that had to go between efficiency and risk reward, as David mentioned as well. You can see what the Alkaid-2 looked like. The yellows that are highlighted on this table are essentially where the Alkaid-2 was, as it compared to other generation. I want to talk a little bit about
Tony, sorry to interrupt you.
Yeah.
If we go back, there's a couple examples in there that I'd like to highlight, 'cause we talked about some of these risk/reward decisions, but there's a couple in here that are really showcased. 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. We ordered all of our material in advance because we don't have a local sand source yet.
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. In that case, with a 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. 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.
that, you know, that's an example on the stage space and size, even though we recognized that we would have liked to have tightened them a little more.
I'm guessing, Michael, in reality, there are degrees of flexibility. When you're in multi-well operation in development, you've got degrees of flexibility that you don't have when it's a 1-well operation. So the conservatism of some of the choices is a reflection of that, also the difference between single well and multi-well operation.
Absolutely. In the multi-well case, we could have just, you know, taken a little more from our supply chain. That's standard, and that's easily done, and those decisions are common on the fly.
Yeah.
You know, another example on this is some of the coarser proppant. We did have to order in advance, and we had never interacted with the formation at this level before. Understanding what conductivity we needed in the proppant pack and how much of it we need to place, we definitely placed more coarse proppant near wellbore than was needed. In hindsight, with the analysis and with the data, it's very easy to make that decision, then adjust. With the decision being made as it was, we had to order sand months before we ever pumped. 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. These are some of the choices that were made well in advance of interacting with the formation. As you said, the operational success of placing multiple fracs across the wellbore was paramount. 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.
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. There are certain things that you can see on a pressure response chart during the job. Ken Nolte is the guy that came up with this analysis. You can see the different type 1s, type 2s, and each job, each stage will have all of these components in it. You know, once you get your growth established, what you want to see is a type 3, basically a net pressure increase during the job as you're going.
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. What that means is your frac are going vertically. That's not unusual because you'll grow vertically first until you see a boundary. Then once you see that top boundary, typically the reservoir boundary or a heavy shale streak or something that dissipates the energy, then you'll start seeing a horizontal growth, which is ideally what you want. I need to point out that you have to design jobs that take into the frac height growths. That was 1 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 go ing to know until you actually do a job. That is what's important about these curves. I'm go ing to take these curves, this information here, and I'm go ing to put it on some of the actual injection stages that we did on the Alkaid. Here are our 2 stages, and actually there's 4. There's 2 slides with 4 stages, and I've highlighted where we sit with respect to those growth intervals that were outlined in the Ken Nolte literature. What you can see is every 1 of our charts were in a 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. 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 or type 4 is actually flattening out. We don't really have a pronounced pressure drop, but it's fairly flat. This is kind of indicated. 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 needed to have a little bit more fluid and extend that job a little bit further, and we would have got a better horizontal growth. That's what highlights that. Then David asked a question earlier, what do we see in some of the other basins? I want to highlight.
If you want me to go to that's.
Yeah, that's what we see in other basins. This is a Permian Basin job that was done about a year ago.
Well, you did a year ago.
That I did. Well, yes, I did a year ago. Anyway, actually, Schlumberger did it. But,
Yeah.
Anyway, what you can see is same type of net pressure, negative, slump in the early beginning, but then you start seeing the pressure increase. We're looking at the red line. The red line, I guess in the second stage, it's 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 on the Alkaid were pumped at the exact same rate, 80-85 barrels a minute. 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. There is a slide in the next slide.
Let's just go back to this 1.
Based on that, we looked at what we need to do to change to get that kind of response on our pressure response. Our design goal was to maximize horizontal extension and to contact larger drainage area. How do 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 pumped 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.
I'll catch up with you, David.
This is where I would propose that we go with future designs. This is the actual treatment that we did that was reflected in the previous charts that we did in Permian Basin a year ago. What you see on this 1 is we pumped a lot more fluid than we did in the Alkaid. The reason why is, as I mentioned earlier, on 1 of those last stages, I think it was stage 18 on the Alkaid, you started seeing a little bit of net pressure gain. That just tells us we were right there at that threshold. We needed to pump a little bit more fluid. That's where these designs came from.
This is essentially almost twice the volume that was pumped in the Alkaid.
Fluid.
Of fluid.
Fluid, yeah.
I'm sorry. Yes, fluid, not sand.
We can touch on that.
1 of 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? I took the Alkaid-2, and I implemented the frac design that we did in the Permian Basin, and this is the result. This is the same material balance that we discussed earlier. This time we upgraded the production to reflect what an additional contact area would look like. This is the match that we've got. Same layout. You see the pressure response and the 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.
Those blue and red lines is just a probabilistic area of what we wanted to calculate to see how close we are to it. The thing 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. What that gave us, and really in the circle you can see it, are where we were talking about 6 stages out of 32 being the efficiency, we're now at 28 out of 32. We're now in that 80% window that we talked about wanting to achieve. That's where we plan on going forward with.
Sorry. Adobe and Microsoft have just got to get their act together. 'Cause when we convert to a PDF, it seems to trip us up every time. This is, of course, the chart we showed from the previous webinar, but why don't you quickly run through?
Sure. This reflects what our model would have shown if we had a different frack job. Really, it's just simply contacting more area within the wellbore because we had longer frack extensions. What you see it does is it yields, you know, a little over twice the EUR as the previous. Actually, 3x the EUR of the previous job. This 1 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 PV10 number, and that's at a $13 million well cost. There's additional things that we can improve, and I think we touched on it back in the June webinar, that we have the option to extend the lateral extensions from 5,000- 10,000, which will be an additional performance increase, but that's not incorporated in these economics that are presented here.
No, sorry, it is. It is incorporated. The 1.2, 'cause we only took 2x rather than 4x.
Oh, yeah.
You know, we've taken an aggregate 4x, which is 2x on the extension and only 2x on the frac. We haven't assumed it's as efficient as the-
That's correct.
Yeah. Right. 1 of the questions you saw in the previous chart that the model economics were based off a $13 million well cost. I think it's useful, Jay, maybe for you.
Yeah.
Michael to go through.
Yeah, we spent a lot of time on this. Tony helped us as well, but Michael and I worked on it extensively. A lot of the costs, I think I mentioned in the June webinar, were a lot of 1-time costs. Michael talked about sand transport. 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. In addition to not drilling a pilot hole, Tony and Michael have worked on drilling time savings, and that's $5 million ± 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.
You know, 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 1-time costs are about GBP 4 million. The sand transport and as Michael says, 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 iterations of how to get sand to the North Slope. Of course, in the future, with multiple well operations, we will have a local supplier, about another GBP 4 million. Once you've got a pad, you don't have to put that cost in.
We did extensive logging that we would not do in the future. There are other, you know, lots of little bitty minor things, rig commissioning, mob, demob, double handling sand, water transfer system, et cetera, et cetera. We are confident, 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. You know, a classic example would be, you know, once we're into development, we don't have to do pilot holes. We don't have the, you know, the effort involved in setting plugs to plug back, time drilling off of those plugs. So, you know, 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?
Yeah. I think you definitely highlight it. It's just for these 1-off wells to take equipment from all over the planet and bring sand up from, you know, a different country, it's so much. Little things like for this job, we had to take time to get the new frack pumps to communicate with the existing frack spread on the slope. All of those things are captured here. This is certainly a reasonable progress where it could be, and it's none of these are abnormal steps. You know, having a frack fleet that works together and communicates together on a daily basis is standard. Having local sand sources have been already identified.
This is just a real representation of what changes when we move from bringing equipment all over the planet to do 1 well, and then sending it all home, versus when we have the right equipment commissioned, ready to go on location, moving well to well. You know, these are known and reasonable steps.
1 thing I would add to that, Michael, on the frac side, you know, we only frac during the daylight. Once you get into the development stage, you know, that's a 24-hour operation. Again, back to everything being on a day rate, you know, your efficiency of your day is basically 15 minutes out of an hour actually going towards work because you 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.
It was, yeah. Basically there was 1 crew.
Yeah.
There was only 1 crew, and that was the limiting factor.
Yeah.
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 have been submitted during the presentation.
Absolutely, David. Thank you and the team for the presentation. Ladies and gentlemen, as David said, do please continue to submit your questions using the Q&A tab situated in the right-hand corner of your screen. Just while the team take a few minutes to review those questions submitted already, I'd like to remind you, a recording of the presentation, along with a copy of the slides and the published Q&A, can be accessed via your investor dashboard. As David said, we did receive a number of pre-submitted questions from investors, and thank you for those. I'd like to start off the Q&A session with those. First question reads as follow: Why was the proposed Alkaid-3 new gravel pad not built and the well not drilled? Any plans to drill there in the near future?
Well, yes. The additional gravel pad, which we do have a permit from the state of Alaska for, is the previous name Theta Pad. We chose not to drill an additional well into the Alkaid field until we had completed the planned frack of the SMD at the Alkaid-2, which we plan for September. It's thus providing the best information on our reservoir fluid composition and our frack propagation to test the next iteration of our frack design. It was planned for that way and that's why we didn't put the gravel pad down and drill the well.
Thanks, Jay. Next 1 we've got here. We've been told by Pantheon that Alkaid-2 pilot hole and horizontal, better reservoir properties in the shelf margin delta and zone of interest. What permeabilities and porosities were measured in any sidewall 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 and most of the charts to the extent we can that are shared in the webinars so that you get better accuracy, and you don't have to spend the time trying to digitize our pictures. 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 know, you're aware of the data trade with 88 Energy on the Hickory well for the Talitha well. If we give away too much information, then we potentially limit future commercial opportunity.
We will, in due course, and particularly when the Netherland, Sewell report on the first stage of Alkaid is released, there'll be some more data in that. Yes, the permeabilities and porosities were better. Why don't I hand it over, Michael, maybe you want to.
Sure. You know, in the Alkaid, we were able for the first time to interact with it on a big scale. In drilling the horizontal, what we saw is that the reservoir continuity and porosity permeability throughout the extent of it. That gives us a lot of excitement in moving forward with Alkaid and with the future developments of that system. When we look at the shelf margin delta, we haven't interacted with it at this scale, and so we're very anxious for that test and to see how it'll come together. We're ready to move forward.
That's great. Thank you very much. Next question here is, doesn't any dense dark 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 go ing to get into the greater detail of that. The core and log analysis does provide estimates. The flow test actually represents the empirical evidence, so it sort of supersedes whatever you might do from the core and log. We've confirmed 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. We know we're go ing to have to handle water and sufficient gas volumes through reinjection into our own reservoirs for enhanced recovery. You know, at worst, maybe piping gas north to Prudhoe Bay, as happens from some other fields on the North Slope.
Even if the Alaska Gasline Development Corporation's pipeline goes ahead, and that's go ing to track down the corridor of TAPS, past Pantheon Field. There may be a lower cost opportunity to sell gas there. We're not relying on it. We've made the assumption that we're go ing to have to deal with produced water and produced gas, and reinject it.
David, the next question again is around that water flowback, some of which I think you've covered off. Anything further to add. In the Alkaid-2 horizontal well test, do the water flowback and salinity results suggest the frack water was coming back or that it had been imbibed into the reservoir. In any of the shorter-term tests, does any water cut flowback or 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 salinities are fresh, so, as expected. When we shut in Alkaid-2, our estimates are 60%-70% of the water being produced was formation water, and the subsequent 30%-40% is the frac water. There is mobile water from formation, and we anticipate that. In all of our wells, we expected somewhere around a 50% water cut is where these wells level out over life.
That's not unusual. I mean, that's pretty standard in many basins around the world.
Thank you. Next question we've got. Did the Alkaid-2 well test have slugging problems? A 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 is anything to add to that.
Yeah. No. 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. Thank you. What permitting and timeline would allow development and production for Alkaid-2? Does the disturbed 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 for Ahpun Field development area. Being situated in the disturbed area and so close to the pipeline and the Dalton Highway, it offers us such a tremendous advantage. We've talked about location, location in our development scenario. We're moving forward on that as we speak.
That's great. Thanks, Jay. The Alkaid-2 result disappointed the market with a lower flow rate than expected and a mixture of hydrocarbons, including oil condensate, NGLs, et cetera, not pure oil. Yet your strategy webinar appeared to be based upon a development mode of a boom. The stock price tells you that the market isn't convinced by Alkaid. What is it that will give you confidence that you can make it to development?
Anybody.
Sure. Well, the company's post-well analysis indicate that the frack 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 frack wings into the reservoir or only by a small portion of frack 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 frack 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 and about how we need to improve the frack treatments, and they're currently working on that as well.
As we mentioned earlier, also, we have the opportunity to extend the lateral length in future development wells to 10,000 feet. The experience of other basins where multiple stage fracks of long laterals have been successfully deployed, it shows the efficiencies have dramatically increased. That's really why there was a shale boom for so many years, is because of the success of the hydraulic fracturing. Jay, I think you want to add something.
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 that will require reinjection or otherwise. We're taking that all on board and planning for it.
Great. Thanks, Jay. Alkaid-2, the gas oil ratio was greater than pre-drill expectations. You've explained the possibility that we intercept the gas cap with the frack, but you also mentioned another theory that it was, it could contain 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 mooted by our colleagues from SLB. We've not seen on logs or in any drilling cuttings or anything, evidence to suggest that there is gas cap. It is 1 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 into a hitherto 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 go ing 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 go ing to be producing at below the bubble point as soon as 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 a combined stream of multiple liquids to go into the main oil line of TAPS. The key point is the volumes we're planning for are based on the models that Tony and Michael have discussed of being able to get twice the IP 30 from doubling the lateral and no more than twice from improving the efficiency of the frac. As Tony said, doubling the efficiency of the frac isn't a very demanding target.
I think 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 efficiency that other basins are with their multi-stage horizontal fracking.
Thanks, David. Next 1, you did cover off on a slide in the presentation. Just in case there's anything further to add, please can you comment on the implications for Pantheon's share price and valuations of achieving a $30 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.
Just to be clear, commerciality doesn't depend on.
Yeah. Commerciality does not. Yes. We're commercially well above that number, but obviously, the lower that number, the better off we are.
That's great. Thanks, Jay. Can you provide guidance on the potential range of improved flow that such frac design improvements could deliver and their implications for 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 comment?
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 conductivity and probably reducing the perforation. Now that we know how the well's go ing to take it, we can feel confident we can reduce the cluster perforations to half of what we shot before. I think all of those things are go ing to improve the stimulation that we've proposed going forward.
You're confident that we can achieve the kind of improvements that you talked about?
I am.
That's why he's here.
That's why he's here.
Thank you, guys. What work's been done post, to lift the SMD blockage to ascertain reason and avoid repeat for Alkaid-2 SMD test?
Michael, do you want to?
Yeah. It's... There's no unambiguous answer we've seen for Talitha yet, nor have we had opportunity to investigate it further with any intervention. The answer that I think is the most clear is that we're working with our frac design, working with engineers at service providers to ensure that we address all potential concerns. Excuse me. By that, you know, for example, I mean swelling clays. I mean chemical compatibility. I mean fluid compatibility. We've successfully placed a lot of fracs. Not exactly sure what the results were, what caused the difficulties at Talitha. 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 will be compatible with the system.
Thanks. Michael, again, something that we've covered off a little bit here, just talking about vendors. 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 we know it's not go ing to happen in the future? For the sand transport, how did it come that we didn't use a local vendor, something we have touched on, and why did we go to a vendor in Canada? Could you please disclose the names of these 2 vendors? Obviously, I know for commercial reasons that may not be possible, but back to you.
We went to Canada because that's where we could get the quantities of sand that we needed. 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. In the end, there was a single bidder that bid on the frac treatment. We had 1 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, well, more than touched on this point multiple times. When you're drilling 1 well in isolation, it's not exciting enough for service providers to be putting forward their best foot, mobilizing their equipment at 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+ well development. The development of Kodiak is more than 1,000 wells.
If you think through what the proportion of the service cost related to the drilling contractor, related to the pumping contractor, related to the sand supply, these are material quantities that can be planned long in advance. We're finding that the tone of those conversations is entirely different.
The only thing I'd also like to add, that's very well said on both parts, is the time with which we did the Alkaid-2. Just to look back, that was a time of pandemic, of supply chain strikes. That was a time of high oil price and personnel shortages. 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'll not take that risk without our personnel." A lot of those have eased already just because, you know, the pandemic has quieted down, the truckers strike in Canada is over, the oil price boom is now better staffed, and all of the vendors have got more iron available and more people.
Once again, we still have to fight these 1-off wells, and we still have a long ways to go. There are still some challenges that development will solve, but there are also some additional challenges of the Alkaid-2 timing that have eased.
Yeah. Okay.
Thank you very much. Were there any mistakes made during the first design that could have been avoided [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. Why don't we move?
Sure. No problem. The next 1 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.
1 pipe availability cost, looking at what we wanted to learn, we felt we could learn with a 5,000-foot lateral. It was more of a test well than a full field development well. All of those led into timing pressures, led into drilling a 5,000 foot versus a longer lateral.
Thank you, Jay. 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 had the data that we desired. It would have been a 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 costs to truck the oil up to Hilcorp.
Of course, all that we were selling because we didn't have NGL.
Yeah, 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 if we'd had those additional barrels. Good point, David.
Okay. That's great. Thank you. With regard to 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 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 advisors on precisely the answer. I don't have a specific answer for you, but I can also tell you that it's not predetermined.
That's great, thank you. What makes you think you've done enough to guarantee being able to raise the GBP 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. We've gone through them extensively and in the interest of time, and I'm not go ing to go through it again here. We're trying to come up with a resilient plan which is not held hostage to any individual channel of finance freezing over. 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 a dilution into the asset or it's dilution into the corporate equity. We recognize that we want today's owners to end up owning as much of the value as possible.
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-$10 per barrel of expected recoverable resource. There will come a point at which that future becomes inevitable, that there will become a point at which a discounted version of that value instead of representing $0.10 a share 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 in and the leverage to investors comes from.
Thank you very much indeed, David. I know we just have gone through the hour, but we've got 1 more pre-submitted question. If you have got the time, there are some questions during the meeting itself. Let's just get on with the last 1. The last webinar raised doubts on proceeding with the SMD test if the necessary equipment price was too high. Given the last fundraise was in part explicitly for the SMD test, would the lack of an appropriate test raise ethical and compliance issues?
Well, look. Yes, if we did no test, then of course there would 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 a binary will we or won't we do the test. That's about the scheduling with which we're prepared to move forward. 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. We have ring-fenced the money that we raised, that portion to achieve that test. We absolutely fully intend to proceed with that test.
We won't hold to a predetermined timeline if that leads to costs that we don't think are reasonable for shareholders to bear.
Right now, we're still planning on a September.
Yeah.
Start for that test.
Thank you very much. That does conclude the pre-submitted question. As I say, you can see you've had a number of questions come through during today's presentation. Thank you to all the investors for those. David, if you do have time, if you and the team could just click on that Q&A tab and just where appropriate to do so, read out the question and give your response, and I'll pick up from you at the end.
Happy to do so. First 1 on the list, although it doesn't look like it's first in terms of the timestamp. Presented an ideal frack for Alkaid-2. Would this approach work the same in, say, the SMD and would you be having to guess and adjust for 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 broadly similar, so we anticipate that the improvement in design that we've learned from the Alkaid-2 frack would indeed allow us to move a step forward in the SMD test. That's the reason we're doing it.
To get a good sample of the reservoir fluids in order to-
We think it's transferable across to the other reservoirs too.
Yeah, of course.
We think it's transferable across all of our reservoirs.
Yeah. Next 1. How much frack water is left to be recovered? I think Michael addressed broadly that we were at 70% formation water at the time.
30% frac water.
30% frac water.
Yeah. We're still some.
In truth, we were heading towards a point at which we could see that 50% water cut in the oil. The next 1. 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 Netherland, Sewell & Associates report on the Alkaid zone of interest, which is the first part of the report on the Ahpun field overall. In due course, as we add the SMD into the Ahpun assessment, we will RNS the results and share. That's the point at which we're able to share those revised figures with people. John R. Let's see. Sorry.
That's your no gas cap.
In the drilling, no gas cap. Yeah. Well, I think we discussed that 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. 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, Gary T, of gas production in the forecasts you presented?
We've just assumed that there is no change from what we accounted, which we think is a worst case. We wanted to make sure that we were comfortably commercial without having to invoke any improvement in performance. Will we need supplies? Ezra has asked, will we need supplies from Russia for future well operations, are there alternatives, if Russian suppliers become unavailable? Michael, I think we're not planning any Russian supplies in the SMD frack, and our next activities won't assume any Russian supplies. I think it was just there was a point, again, when the world was a different place, where 1 got what you can, where you can.
Correct. Yep.
Status of the NSAI report. We're still anticipating the Kodiak report before the end of July, and we will RNS it in its entirety. We will have a webinar to discuss 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. That's our sort of base case from which any optimization, whether it is moving gas 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 Netherland, Sewell is an estimate of resources that demonstrates that we're exceeding the commercial threshold. 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 you, if your hurdle rate or if your cost of capital was 12%-15%, would you move forward with a development that only provided 20%? Probably not.
If you've got a development that provides 50% rates of return, then probably yes. As we showed in individual wells, the marginal well that you add 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 a repeat?
We've been working with our source specifically. The fascinating thing is the sand was handled 5 different times from source to being able to pump it. We've gone through each of those 5. Some of them we'll be eliminating. We'll be wrapping sand differently at the plant in the future if we buy from the same plant as expected. We'll be wrapping it and 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. We'll take efforts on that front, and then we'll do quality control checks at each point to better identify if and where there a problem arises.
Last, we'll have especially for the shelf margin delta, we'll have the ability to supplement if we do see some in advance. All those will assure that as long as we're using the supply chain, we can identify and correct any issues.
Of course, long term, we will have a local supplier. That will mitigate a lot of the handling issues long term.
Absolutely. Sand drying capabilities.
Yeah. Yeah, that's the next question. Just to be clear, again, when you're only dealing with 1 well and no reliable long-term offtake, a local supplier is not going to invest. At least if they are, then they're go ing to look to recover the whole of that investment in 1 job. 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 sand in the timeframe necessary for the upcoming and subsequent Kodiak development. Next Alkaid cost.
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 1-well operation to a multi-well operation. We are forecasting that it'll 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. We raised $90-something million. Sorry. I think I misinterpreted the question.
Why didn't we raise any money at all last year? Rather than why wasn't the fundraises we did larger. I think we addressed that in the last webinar as to why we didn't. There are reasons for raising money at particular times and the ability to raise money at particular times. Hindsight makes it much easier to know when you should have raised money, but you didn't. It's quite clear that things didn't work out the way that were anticipated when the decision was made not to raise money last year. We have to deal with the world as we find it today, rather than as we wish it had worked out.
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. Would a merger with another nearby explorer offer some economies of scale for development and shared services on the North Slope? I'm assuming that refers to 88 Energy on the basis that I think they're the only nearby explorer. 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 their Hickory well test. 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. 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 recoverable for Kodiak, where previously we'd 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-
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 Netherland and Sewell before the end of the month on current schedule. We expect that to-
We're focused on the lower basin floor fan right now.
Yeah, Anthony H, "What additional costs due to Alaska climate exists versus lower 48 explorer, higher wages, lower up days versus down days, 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 contact@pantheonresources.com so that we don't lose it, and so that it's top of our minds when we have come off this webinar. We will send to you a considered answer to that rather than something off the top of our heads.
Steve H has said, "Given that Alkaid left us with an 85% loss on the share price, is that not an argument to proceed within the next 6 months on a production test in our pool that demonstrates conclusively the desired improvements to improve the share price?" The answer to that is there are arguments for spending money on a variety of things. Clearly, there are 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.
Before we would move to an additional long lateral and multi-stage frack of a well in our pool, we would want to have made 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 1 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. Our strategy is not you know go from here to there without many intermediate steps.
At the same time, there are many facets to what we're doing that are designed to minimize overall dilution. There's no 1 action within the strategy that at a stroke solves the dilution problem. That's the reason that we're not proceeding hell for leather for 1 option versus doing all the right things in the right order under our strategic objective. Iqbal asks, "What happens to my AIM shares if you list in the U.S.?" If we did end up with only a listing in the U.S., then of course it would be because there'd been a share exchange that meant that everyone who owned shares on the AIM owned the same proportion of the company on the U.S. listing.
We're not saying at this stage that we know for sure that it's not go ing 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 pre-empt the advice. What we won't do is incur unnecessary tax leakage. We want to have considered it from the perspective of investors, not just in the U.K., but in Australia and Singapore and the Middle East and North America or in mainland Europe, as well. There are probably investors from other places, as well.
We want to do a comprehensive job of making sure that we make the right decision on where to list, and to weigh any costs of that against the improved access to capital on better terms than otherwise we'd be able to do. 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 post-well 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 frack that will comfortably exceed the economic threshold and support our ambition, firstly, to develop our pool, 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 a sustainable market recognition of $5-$10 per barrel of expected ultimate recovery by the time we get to Kodiak final investment decision in 2028. 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-