Pantheon Resources Plc (PANR) Earnings Call Transcript & Summary

Hello. I'm Jay Cheatham, the CEO of Pantheon. And welcome to our webinar on the interim results of the Alkaid #2 well, and it will follow with a Q&A. For those of you who are watching this live, if you're in the U.K. or Europe, good afternoon. If you're in Asia, it's late night. And if you're in the U.S., it's midday or early morning. We have a great lineup for you today. First off is our Chairman, Phillip Gobe. Now Phillip has extensive experience on the North Slope of Alaska, he'll tell you about that. But he also has extensive experience in drilling horizontal wells, multi-stage fracking, operations, et cetera. When Phillip was the drilling manager for ARCO's Gulf Coast operations, he managed up to 18 rigs, and these were not cookie cutter wells, these were highly deviated multi-pressure wells in the Gulf of Mexico. And he also has so much experience in multistage fracking. Next up is Michael Duncan, our VP of Operations and Engineering. Michael is going to talk to you about the economics of full field development for Alkaid and our operations to date and the operations going forward on the Alkaid #2 well. After Michael, is Pat Galvin. Pat is our Chief Commercial Officer and our General Counsel in Alaska, and he's going to unravel the very unique pricing protocol that delivers the combination of oil condensates and NGLs into TAPS and determines what that stream is worth to each individual producer. Pat was also the revenue commissioner for the State of Alaska. Fourth up is Dr. Ed Duncan, a consultant for Pantheon. Ed is a professor in the college of Geoscience at the University of Texas in Austin. Ed's going to talk about source rocks, oil maturity, oil generation and what that means across our portfolio of projects. And finally, Bob Rosenthal, our Technical Director, is going to talk about farmout, partnering, data room and plans for CPR report on a couple of our projects. But before I turn it over to Phillip, I want to talk a little bit about the uniqueness of the North Slope. And this is our disclaimer that we pass through. I want you to please read it. Now whether it's the options available from the service providers that's unique or the unique way, the NGLs are blended into the crude stream to become Alaskan North Slope crude that's then shipped down the TAPS pipeline to Valdez or the town of Deadhorse that supports the industry on the North Slope, where there are less than 100 permanent residents, but over 5,000 that commute from elsewhere or the fact that Pantheon was the first company on the North Slope to do a multi-stage frac. We did 29 stages and that was -- those were slickwater fracs. The first ever done on the North Slope of Alaska, when literally thousands of those have been done in the Lower 48. Now there's been a lot of speculation about whether Alkaid is economic. Michael is going to show that even at our current rates of 137 barrels of liquids per day per 1,000 foot of lateral and our current product mix and pricing, it is a very robust project. Also, as management, we understand the disappointment that resulted from our guidance of 150 barrels of oil per day per 1,000 feet of lateral in our latest RNS. And what we announced was 200 barrels of oil per day and about 350 barrels of condensate and NGLs, which equates to about 137 barrels of total liquid hydrocarbons per 1,000 feet of lateral. We believe the market didn't understand that all of these liquids transverse the Trans Alaska Pipeline as ANS crude, and we expect to receive 80% to 90% of ANS value at today's mix, which we believe will only increase. And I would like to remind you that we're only about 1/3 through the clean out and clean up. We still have sand in this lateral and we remain confident in this project. So before I turn it over to Phillip, it will be a long webinar today in order to get through all the topics that are foremost on shareholders' minds. We'll post it to our website at the conclusion. I believe the webinar will demonstrate to shareholders while we remain confident in Alkaid and in our entire portfolio of projects. Now to you Phillip.

Thank you, Jay, and welcome, everybody, and thank you for the privilege of your time today. I thought it might be instructive to run through my career, just so everyone can get an appreciation for the skill set that I bring to the Board of Pantheon Resources. I began my career in 1976 with a company called Atlantic Richfield in the Permian Basin of West Texas near the towns of Odessa and Midland. After sitting rigs for several years, I transferred to the Gulf of Mexico, where I began sitting rigs, offshore, Gulf of Mexico. I worked my way through the ranks all the way up to district drilling superintended, where I had operational responsibility exceeding rigs of 18 offshore rigs during ARCO'S most prolific drilling campaign in the Gulf of Mexico. From drilling, I moved through every discipline within the operating environment from production operations to materials and logistics management, environmental safety and training and ultimately ended up my operating career in 1991 on the North Slope of Alaska. Of course, the highlight of my operating career was being appointed the operations manager for Prudhoe Bay on the North Slope of Alaska. This was ARCO'S largest operation in Crown Jewel as well as the largest oilfield in the United States. The North Slope of Alaska has many, many attributes and uniqueness. And one of those is it's a resource rich part of the world, which I fully expect to play a very important role as the world seeks energy security and further sources of supply. After leaving the North Slope, I ended my career with ARCO at a company called Vastar Resources, a wholly owned subsidiary of ARCO. Vastar Resources was a highly regarded exploration and production company in the independent world, so successful in fact that British Petroleum acquired the company in 2000. From there, I did further work at 2 other publicly traded companies, one as the Chief Operating Officer and the other as the Chief Operating Officer, President and Director. After retiring from full-time work, I moved into Board service. I've served on 5 public companies and 1 privately held enterprise. Currently, I'm the Chairman of ProPetro, one of the largest frac companies in the Permian Basin, and I also sit on a Fortune 500 company called Pioneer Natural Resources, the largest independent in the Permian Basin. From the vantage point of both ProPetro and Pioneer, I've picked up many interesting characteristics of the horizontal drilling campaigns, both in the Lower 48 and on the North Slope. As I read through a lot of the material from the analysts from our last RNS, I see that a lot of comparisons are made between us and the Lower 48 in terms of horizontal drilling. And I'd like to talk about a few of the similarities and some of the differences because sometimes I think people can come to conclusions a little bit too quickly when they're looking at the 2 dissimilar operations. Let me start with the similarities. Both areas began drilling their laterals conservatively. Lower 48, particularly in the Permian Basin shale started with 5,000-foot laterals. They needed to understand what they were dealing with. On the North Slope, the Pantheon team also drilled a 5,000-foot lateral. And unlike the early experiences of the Lower 48, they were actually able to stay in zone the entire length of the lateral, which is just a real tribute to the technology transfer from the Lower 48 to the North Slope of Alaska today. As you all know, laterals have continued to increase in length, up to 15,000 foot, and I suspect could be longer. And we will go through the same learning curve and our laterals may or may not go out that far, but we'll take our learning and the technology transfer to determine what's optimal for us. The second similarity is Lower 48 shale plays had to experiment both in terms of completion design and completion fluids. They went from longer lateral stages to shorter lateral stages. But ultimately, it's the multi-frac operation that provides the best result. The purpose of the multi-frac stage is to crack as much rock as you can to ensure the best production performance and ultimate recovery of the wells. Much like everywhere in the world, whether it's an unconventional or conventional, generally, your work -- your first wells are not your best wells. As you apply learnings from your own experience and take technology transfers that are available, you will find that all of our wells, I believe, will continue to improve. So let's move to a little -- a few of the dissimilars that I see. These differences begin with geology. The shale players when they began drilling their wells had a very good idea of what the subsurface looked like. After all, the Permian Basin has been around for 100 years, and it's probably the most penetrated basin in the United States. So when they started their laterals, they had a pretty good idea of what they were dealing with. Different for us on the North Slope, this is a new field development, and we don't have all the data that the Lower 48 players had. So the drilling is not as simple, I would say, as the Lower 48. Having said that, the Pantheon team did an exceptional job of executing the first lateral in this new field, highly successful. Permian Basin players and other shale players are quite willing to experiment with their lateral length and also their completion design. Pantheon does not have that luxury, although we do have the benefit of understanding what people learned in the Lower 48 and applying it to the North Slope of Alaska, which has really took us much further down the learning curve than the shale players had to go through to get to where they are. I'll turn my attention to the service companies and equipment. As activity declined on the North Slope for the last several decades, it follows that the service industry also declined in terms of people, equipment and service capability. They are redeploying their people and their equipment to the most profitable places in the U.S. and around the world. Having said that, our team was able to execute a 29-stage multiple frac with the available personnel and equipment on the slope. The good news for us, I believe, as I mentioned earlier, where I think Alaska will play a critical role in energy security and supply with the new development showing up on the North Slope, specifically Willow and others, we would expect that the service intensity would pick up, and we would begin to attract more equipment, better personnel and better outcomes for the North Slope. The one thing I think is important to keep in mind is shale companies have had over 10 years to refine their drilling and completions technique. We're just beginning on the slope. But we were able to capture a lot of the 10 years of experiences that the E&Ps went through in the Lower 48 to apply to the North Slope. And I would expect the same outcomes that the shale players saw from their refinement process to ours. lower drilling costs by 30% to 50%, better production performance, 20% to 30% as well, and ultimate recoveries to increase by over 50%. I expect all of these efficiencies to accrue to the Pantheon team. It's an exciting time for us. We've got the right people. We're applying the right technology, and I believe we will be very, very successful on the North lobe of Alaska. With that, -- before turning it over to Michael Duncan, Pantheon's Chief Operating Officer, I'd like to turn it over to Bob Rosenthal, our Technical Director on the Board for a few comments. Bob?

Thank you, Phillip. I'm actually going to turn off my camera, having some Internet connection problems. So here we go. So again, thanks, -- so before I turn it over to Michael, there are a few topics I'd like to address upfront. Those are related to the gas, natural gas liquids. Those are NGLs and condensate production we see at Alkaid #2. Look, we always expected to see some gas production, and we knew that the gas was going to be rich, which just means that it had a high content of NGL to condensate. What we didn't expect is the amount of gas and therefore, the higher proportion of NGLs and condensate to oil. But as Jay has already stated, Alaska is unique and these products have a tremendous value. Over the last few weeks, a lot of new data has been analyzed by a number of outside contractors and consultants. This includes GeoMark, one of the leading geochemistry groups in the world who are looking at our oil and gas samples. SLB, once known is Schlumberger, and we're going to talk about them a few times, and we're going to make mistakes and not calling them SLB, but they're now known as SLB. SLBs is studying our early production data, and Roger Young was revisiting the log data from the Alkaid #1. After all this analysis, we know that Alkaid #2 horizontal was in oil through the whole 5,000 foot of its lateral. I'm going to repeat that, it was in oil through the whole 5,000 feet of its lateral. But it looks like we might have fracked up into a small gas cap. Now Michael will talk about that in more detail in a few minutes. But when I say small, I want everybody to understand that we're looking at less than 2% of the gross rock volume of the total Alkaid reservoir, which just translates into a very small percentage of the resource. And following me, Michael and Pat will discuss in detail the commercial implications of all this. Now one important thing I'd like to remind everybody that our acreage holds over 20 billion barrels of oil in place over multiple reservoirs. The Alkaid #2 is designed to test what level of production we can expect from this one reservoir, the Alkaid reservoir and whether it would be economic. Now there is a lot of speculation out there that our preliminary results, and when I say preliminary, I mean we are still, as Jay alluded to, in the very early cleanup stage of the well, but the speculation that our reservoir is not economic and will never be shown to be economic. And that is dead wrong. And what I'd like to do now is turn it over to Michael and let them address some of these issues and let him comment on some of the speculation given the results that he's seen so far from the well.

Thank you, Bob, and hello from beautiful Alaska. Today, I'm going to discuss a lot of points. I think the question Bob asked about the commerciality is probably on everybody's mind, and I'll certainly address that first. I will also talk a little bit about gas production and elaborate more on what Bob said about -- where we've seen the little gas and where we go from there. There's been questions about the operations, specifically the coiled tubing work, and I'm anxious to give an update not only on what has happened, but on where we'll go from there. And then I want to talk about what we've accomplished this season in derisking our techniques in the assets and then how things look in the future. We now have a lot of data that will define our path forward operationally. And so I look forward to discussing those, and how this is what I'll cover that. Big question everybody has been focused on, of course, is the commerciality of the reservoir. And so to address that, we've taken our look-forward models, the development models that we've used and the development model similar to those of our independent experts and consulting companies such as SLB, taking those models and updated them just with the observation to date from the Alkaid #2 well. As Jay said, we're producing roughly 137 barrels of liquid per day per 1,000 feet of lateral. So taking that metric and applying it to our models. We've revisited that. We've also looked at our cost and our pricing assumptions. So on the cost side, we have seen some cost increase over the last season. To capture that and be conservative, we've increased drilling and completion cost estimates in our look-forward model by approximately 50% to $19.5 million per development well. And then as I said, we've taken the product stream that we've seen today already delivered by the Alkaid #2 well, and we've adjusted our price to tune our model to reflect that in the future moving forward. Pat Galvin will discuss that methodology a little more thoroughly. And then we've tested the sensitivity of it, those are the results that are shown here. And the answer we get, the indication we have is that this is a very commercial development even under what we've just seen so far. And I need to say this very clearly, there's so much reason to believe in upside moving forward. One, the well is not properly cleaned out, and I'll discuss the equipment that was available that we used and the methods that we will apply moving forward. Once we get this well properly cleaned out and cleaned up, there's still significant frac water to get out of the way. Once we go through that process, we can really see what this what we'll do. But even using the flow rates that we've seen thus far, which are very conservative. And there's so much reason for upside, but even using what we've seen thus far, all of our models reflected commercial development, and I'm very, very excited about that. And it models commercially at what we see today. This well has already shown it can deliver over $40,000 a day worth of product, and that's very exciting. So I very much look forward to what we show in the upside. I very much look forward to showing the true potential of this well after we clean it out and clean it up. But so far, it's looking very, very good. Another topic that's been discussed is gas production. The high gas rates that we've seen as well were certainly unexpected. And they weren't in line with what we thought at the Alkaid #1. What seems to have happened, we've gone back and looked at it in light of our production and the peers that we've connected to a gas cap. And what I mean by a gas cap is gas can be present in the reservoir in 2 major conditions. One, gas can be in solution in oil, the same way that carbon dioxide is in solution in a Coca-Cola or a bottle champagne. And when you relieve the pressure that gas bubbles out just as it does when you open your drink. That is certainly present in this reservoir and the oil has gas dissolved in -- but we're seeing more gas production than that, and that indicates that we have connected to a gas cap. But what I mean by gas cap is that free -- free gas in the reservoir is lighter than the oil. And because of gravity and buoyancy will collect at the top of the reservoir. And that's what we would call a gas cap. And then there's a gas and oil contact where the gas that is floated to the top sits above your oil. One thing is very clear. This lateral is landed in oil. And that's clear because oil doesn't move up through gas. Gas has preferential permeability and will move through oil. So our oil production alone is evidence that this lateral is landed in oil. What you see in front of you is a cartoon depiction trying to showcase the concept of the gas cap in the wells. On the left-hand side is the Alkaid #1 well and the yellow ground that you see is a game interpretation of sands and shales. On the right-hand side is the Alkaid #2 with the same rough interpretation and the gray indicating where the horizontal was landed. Once again, all indications are that the horizontal is in oil and the Alkaid #1 produced a much, much lower GOR. So it indicates that it's not connected to a free gas cap as the Alkaid #2 is. But on the Alkaid #2, we scaled up our frac both in rate and in volume and the results of the Alkaid #2 are higher gas production. And so the conclusion across the board is that there is a small gas cap we've connected. It's clearly well above where we landed. It's clearly small in volume relative to the oil reservoir, but there is free gas that's contributing more to this. And we're beginning to understand. That has interesting implications for development. The exciting implication is that when we look at our volume metrics, it's -- it won't be detrimental to our volume metrics. And what I mean by that, we've recognized all along that this reservoir is thicker than we can contact with one web and with fractures. The reservoir is approximately 400, 450, maybe even more feet thick. And a good frac will connect you to about 200 feet of rock vertical. And so the concept that we fracked into gas at the Alkaid #2 isn't detrimental to our development. And there's 2 major reasons. The first is that future development wells are down dipped from the Alkaid #2. So they will immediately move away from the gas just in where the reservoir goes. But second, we have enough reservoir that there's potential for us to move the well placement. We can just move it lower and produce from a lower section of the reservoir. And so that 200 feet that we can contact and we can just contact the lower 200 feet. So it doesn't change our volume metrics or concept of development. But the exciting thing about it is that the fluid that's moving through the rock and the Alkaid #2, if we can move that horizontal down in the reservoir or just move it down and where we place it. that fluid movement that's now gas would be an oil phase instead. And so to put some perspective on that, the Alkaid #2 has flowed about 2.5 million to 3 million cubic feet a day of natural gas. In reservoir conditions, that gas takes up approximately 1,500 barrels of volume. And so if we can move the reservoir -- if we move the well down in the reservoir or if we just through our development, move down dip as anticipated, it's very exciting to think of the possibilities as we move out of contact with that gas and instead the fluid moving through the system is oil. And so our development looks good under current assumptions. But as we optimize, we replace this well and as we better understand the exactly out of this formation, there's a lot of room to really improve not only where we land things, but improve what fluid is moving through the rock. Another implication of this increased gas that I want to talk about is how we handle it its surface. We've recognized all along that there will be gas that we would need to reinject and we intended to use it for power generation. This is a slide I presented before the Alkaid operations took place, Alkaid #2 operations. We recognize all along a need to be able to handle the gas and handle the water, and we recognize how long that there would be some level of both products being reinjected in the formation. And so nothing's changed on that front. We know that we can handle this. We've identified a method of handling gas and water from the get go and see no need for change. But an implication in how that we manage this is what our facilities look like now and what they'll look like moving forward. Alkaid #2 is a proof-of-concept well. It's a pilot project, so to speak, in that it's the first we've done, and there's a lot of things we need to learn. We took this separating system out so that we could properly learn that, so we could properly collect the data. 3 phases go into our production separator, the liquids that fall out of the production separator go to tanks and they're hauled away via truck and sold is oil. But moving the gas -- that much gas through the system carries a lot of liquids with it as well. And the gas is taken from the separator and is used for power generation, gas lift and eventually beneficially injection. With that gas, it carries NGLs and condensate. And I wanted to talk about those, what they are and what the value stream of them is. We look at condensate, the analog I'd like to point to, so people can help people understand what that is, is the Maid of the Mist at Niagara Falls. And if anybody has been to Niagara Falls and rode the Maid of the Mist, the lovely boat ride down below the falls. You don't go into the waterfall, you drive up in the river, near it and get a good look at the Falls. And if you're on the boat, you get absolutely so. And you're so not because you -- the boat has gone into the waterfalls, but because the turbulence of the waterfall, everything that's moving and all the energy creates a system where they're water drop what's in the air, a mist of water in the air, and that's why I call it Maid of the Mist boat. That water is in the air and collects on your clothes and you get thoroughly soaked. But it's no different water than that in which the boat is floating on. And so when we look at that situation, that is a water condensate. And the same concept applies in an oil and gas system on we look at an oil condensate as a liquid that are suspended in the gas. And when you move 2.5 million cubic feet of gas through hydrocarbon in a liquid system and especially through 1.5 miles of vertical in this turbulent system. When you bring it to surface and you have a small test separator, there's a lot of liquids that you carried through the gas past the separation system. And a lot of those liquids, we think NGLs, people often think propane and elsewhere, that's the predominant phase. But in this case, a lot of this NGL and condensate that we're seeing in our gas is much heavier, much higher value, much richer. We see components of C6, C7, C8 which is hexane, hectane and octane. Those are gasoline components. Those are transportation sector fuels. That's some of the most valuable product on the North Slope and will be recognized as such as a quality [ bank ]. For our test separation system, it's hard to know before you've ever brought a well on in this reservoir, what test separation system you need or how to be able to handle those liquids. But in the future, handling those liquids is very simple. Larger settling time, a little bit of cooling, which is very easy in Alaska. And these liquids fall out and you're able to maintain them in a liquid form or capture from the gas as a liquid and sell them in the form that's sold on the North Slope, which is as a condensate as an NGL as a blend through the Trans-Alaska pipeline. So for today, for a test well, for a pilot program for our first opportunity to see what this formation can do, you wouldn't bring those systems out. But they're easy to add on. They're not high dollar addition. We can easily now that we know what we need to handle, we can take and put in the systems -- in the future, we'll put that directly into the Trans-Alaska Pipeline system and sell it as a crude blend, just like every other operator on the slope is doing. I want to talk briefly about water -- we knew all along, there will be a lot of water to handle. We fracked with a lot of water, and we're prepared to reinject it, and our development plans have always accounted for reinjection. But there's been some questions about water cut, and I just want to address that very briefly. The initial water cut after frac, when we put millions of gallons in formation for stimulation, you turn the well back around on the in production and initiate it is 100% water as expected. Over time, as production grows, the reservoir fluids become more prevalent, the water cut decreases, the oil cut increases and you move forward into what a representative production is. In conventional wells, this can happen very quickly in days for this type of horizontal multistage completion, it takes a lot longer. Over time, it's really easy to ascertain what a true producing cut is. You can take the decline curves forecast out, understand how much you frac and very easily and very reliably determine that. We're not there yet. The purpose of this well is to understand production is to understand these decline curves, and we will understand the water production. We will understand the cut with the decline curves. It's a test well and we will get there. Today, water cut is decreasing. Frac is still very heavily influencing our water cut. Oil cut is increasing, and we're very happy about the products we're producing. I said before, this was already producing over 40,000 -- $40,000 worth of product a day. I'm very anxious to see where we go from there to further showcase how we can separate process and handle it and what we can do. I want to touch briefly on that. Pat Galvin will discuss this system more thoroughly, but the point is we are right next to the Trans Alaska system. So the largest underused takeaway capacity for product on the continence sits less than a mile from our location. It's actually so close I couldn't even draw it on this map because the line is so small, it doesn't appear. But right next to us is a blend of NGL condensate and oil that is passing through us as the translate pipeline system. In the future, it's not a test separator that we'll be using. It's true containment separation and refining of these products, the NGLs, the condensate and the oil will be sold as a blend, just like everybody else on the North Slope has done and just like it's passing next to our location.

I just want to interrupt, Michael for just a moment and point out to everybody who is listening to this webinar that the last few slides are pretty much the most important part of the webinar. What Michael has demonstrated is that even given the product streams that we have today, the gas, natural gas and condensate and oil stream that we have today, that we can model that as commercial. We can handle the gas that we're producing. We can handle the water that we're producing. And we know and we know or we believe that by moving our well positions in the Alkaid fields that we can actually change the product stream and things can even get better. I think those are really, really important messages that everybody takes away from this and really focused on that. So with that, I'm going to turn it back over to Michael.

Thank you, Bob. I want to talk about the operations a little bit, specifically the sand, the [indiscernible] work and the upcoming co-work. And so when I look at sand, sand management is a common topic in a common concern in horizontal multistage completions like this. And the truth is when you put 7.5 million pounds in this instance, in the formation, you don't need a high percentage of that to move to restrict flow -- and so what can happen is you do your frac, you place it, you begin to bring this on to production and sand can flow in from various places in these fracs and accumulate the wellbore, and it restricts flow. That was anticipated. We identified and advanced that, that was a possibility and we're prepared to handle it. The other thing that can happen is sand what we call dune - duning can take place. And sand can move into the wellbore and move through the wellbore, but not have the velocity to move upward through the vertical. And because of gravity, it will fall through the liquid and collect in the heel of the well. And so we saw inflection points in early production and understood that there was a restriction that we need to address. When I understood there was a sand issue with the well -- but I'm not sure the exact configuration what it would look like. Again, this is the first well in the formation. So a lot of these learning experiences. We've had no opportunity to get before. And now we're addressing something that we identified as a possibility of volume to go. What is complicated to matter is that we had identified a rig for well servicing prior to the project. And literally days before that rig was to come out on our location. It had a catastrophic mass failure at another operator's location. The mass literally folded a half. That rig is under a pair, and we'll be back operational late spring, but it certainly had implications for our use and for how to address things moving forward. So we lost the ability due to that failure very early of extracting the tubing out of this well. That put us in a spot where to address the sand issue we had to attempt to through tube and clean out. Before I go into that, I did want to say that the next best fit rig for this work the Nordic #2 was being commissioned as we did this through the clean out. So we also understood that we still needed to work over rig in the future, and the Nord 2 is being commissioned. But we took in, we did a through tubing clean out, and this is a depiction of that cleanout. And the things I want to highlight. One, the larger pipe that goes through the horizontal is the casing. Inside the casing in the vertical or near vertical, we put a tubing. And that tubing is used for lift and flow management and has an internal diameter an ID of about 2.5 inches or about inside of a soup can. And it's approximately 8,000 feet or 1.5 miles long. So in order to clean the well, we have to run a coil through that tubing. It's very tight. And as a result, you have to run a skinny coil through it. And in this case, the largest we could feasibly use is an ancient 3 quarter coil. So you're size limited immediately. But there's other restrictions and limitations that are present. When you put an 1.5 inch half coil inside a 2.5-inch IV pipe, there's not a lot of room around that. Yet all of the fluid you circulate has to move through that through that space through that annulus. And as a result, you get very, very, very high velocities, lots of friction, lots of back pressure through that tubing. Below the tubing, the opposite happens, your casing is much bigger. There's lots more room and the fluid slows down a lot. And the complication there is as fluid slows down, it makes it harder for it to carry sand. And so it's a delicate procedure to work through the window, using small pipe, high velocities and restriction in the tubing, low velocities and carrying capacity low below that. But it's a method that can work. It's a method I've done multiple times. And in this case, we had very success -- we found sand where we expected. We definitely confirmed that there was same restriction in the wellbore, and we learned how this wellbore works. We learned how to circulate. We learned what pressures it could support and where we run into limitations. One of the big limitations we learned is how far down the well we could get. Plenty of coil tubing on the pie on the [ reel ], but that doesn't mean you can get it all the way down the lateral. And the visual to help is imagine pushing a garden hose down a pipe. A first is really easy, but if that pipes 3 miles long, eventually the garden hose doesn't keep pushing. It's just undulates and you can't get enough force on it and it won't push the nodes of it any further. And the same thing happens when you have 3 miles of inch and 3/4 coil, you can get so far down the well and eventually undulates and you just -- no matter how hard you push the nodes of it won't go any further. It's hard to know where that will happen because it depends on friction. It depends on restrictions and drag. It depends on buoyancy and fluid compensation. And so it's hard to know in advance where or if you will find that. In the case of the Alkaid #2, we found that a little over 1,000 feet before we got to the toe. And when we found that when we found the coil wouldn't go any further, we were still circulating sand out of the well. So we know that there is sand there. We saw sand through the lateral. We know we've left at least 1,000 feet of sand in there, and we probably left more due to inefficient circulating. So in this case, we had marginal success. We learned a great deal about the well and the condition, circulating the methods, the pressures, the balance, which took great steps and as a result, our production went way up. But the well is not producing through its true potential. We see that. We know it. We still see restriction from sand. And we know that we left stand in the last 1,000 feet. But as of starting tomorrow, the right equipment is commissioned hot and available. And so the Nordic 2 rig will head down the Dalton highway to go service the Alkaid #2 starting the 25 January. And what that [indiscernible] do is, first, to get the tubing out of the way. I'm very excited about that. With that restriction gone, we have the ability to use larger pipe. With larger pipe, it's more rigid, and you can push it further along. We have much more strength to it, and it will easily reach [ TV ]. The next implication was out without a 1.5 miles long restriction, we don't have the back pressure, the drag, the friction and the restrictions that we did before. We now have plenty of room to circulate through. We can now carry things to surface much easier without the difficulties of trying to use that small space. And then lastly, the larger coil allows us to pump faster. You got more room to pump through it, higher capacity, higher capacity means better circulating, better circulating means you're cleaning things far more efficiently and far more effective. These are the right tools for the job. Due to unforeseen circumstances, we weren't able to use the right tools for the job the first time. But starting tomorrow, we will have the right tools. We'll go out here, clean up the well and really showcase the potential of it. Looking at operational risks. I want to look back at the well, look back in the season and understand how far we've come. And Phil spoke of this in the learning curve. This is the first horizontal ever drilled in this formation, and there's been only one vertical prior to that -- so there are a lot of questions in advance of how do you drill it, how do you stay in formation? How -- what are the pressures -- we've overcome a lot of hurdles, and we were able to drill this well where we wanted to first try. I'm very proud of that. On the completion side, there are a lot of risks of can you even accomplish oil slick water work? Will you get the water supply. We did first try. There's a lot of tuning. We've got a lot of ways to optimize our completion, but we've shown that there's a recipe that will work -- and same on the production side. There are a lot of questions in advance. We've overcome a lot of those hurdles. And so I'm very proud of how far we've come. These aren't necessarily groundbreaking in the sense that -- we knew that we felt that it couldn't be done, but we've overcome a lot of hurdles and we've come a long way in operationally derisking this asset. We knew we'd get there. We just didn't know how quick the learning curve or how many wells it would take. I'm very proud of what we've derisked, and we've shown an operational recipe that works. But I think the more important question on everybody's mind is more the risk in the reservoir and how far we've come there. A lot of questions in advance of reservoir presence. Are we even going to find the reservoir, we're predicting when we drill it? Is it continuous? Does it go from point A to point B? Can we map it? A lot of questions on the quality -- can we handle oil quality and surface, can we handle it with process. It was what we saw in Alkaid #1 representative of a larger scale of the formation or other hazards waxes, sulfur, are there gotchas that we need to handle. There future issues that we need to be aware of. And then the big question I have his mind is just deliverability. And the main question of will fluid move through this rock. For Alaska, it's tighter rock than has been produced before -- through -- in comparison to elsewhere like the Permian Basin, it's much more permeable. But the big question of just how it can perform and can fluid move through this reservoir was a big goal of this well approved. And so now we've produced the well know we drilled it and we brought it online, and I want to look back at these just to highlight exactly the successes we've had in this. And first is the reservoir presence. The pilot of this well found the reservoir exactly where we predicted. And so -- I mean, within feet. And so that's a big step for us because it really validates that we can see and map this reservoir. And we talk about continuity in between as well as 4 miles apart. But when we drilled this horizontal, the horizontal stayed in reservoir the entirety of the time, and we were sampling it. We were measuring it through logging and the quality of the reservoir was present the entirety of the lateral. So that really validates our model, our system, our view of the reservoir and our ability to map it and predict it, found it where we wanted and we stayed in it the whole time. So that's a great success. And it really proves our geologic view and our path forward. When we look at oil quality, questions of processing and what it means for the future. We are making pipeline quality crude on location. That's an amazing win. It doesn't take advanced processing. It takes -- it takes the proper heat, pressure and controls. We identified that in advance. We're producing pipeline quality crude now, and we can only get better at that moving forward. And so that was another big question. We took a small test of it in the Alkaid #1. And when we scale that up and look at a bigger version like the Alkaid #2, will the quality reflect. And on the oil quality side, the answer is absolutely. It's a light sweet crude. It produces hydrocarbons in the transportation fuel sector. And what I mean by that is it's got lots of gasoline and diesel. It's a very high-quality product. What we were -- what did surpass our expectations is the gas production rate. That high gas was unexpected. We will have to adjust to handle that properly out of the Alkaid #2, and we will adjust how we work our development to stay further away from the gas and make sure that the predominant phase flowing through our reservoir is in the oil. And then the last question of the hazards. Waxes are seen on the North Slope. Sulfur, not very much, but there is -- it is great to be past that risk and to prove that we don't have any sulfur, no material sulfur and to prove that we're not having a waxing problem. And thus far, we've seen no wax problem. So we see no [ gotchas ] on either an oil quality side or on handling side. The path forward screenless very excited to be at that point. But once again, the big question is deliverability, will fluid move through this rock -- and will it be commercial. And based on all our observations, just that thus far, and the answer is yes, it models as a commercial development. But I can't say this enough. There's so much reason for upside. There's so much possibility for us to move where we land -- change our completion checked nets, refine our processing at surface. There's so many efficiency games ahead, and it's great to now begin to have the data to know where that path lies. I'm very excited about it. In full conclusion, I mean the point I can't stress enough is that everything we see supports the case that this will be commercial at current rates and current product value streams and we have significant room for improvement. We've only got about 40% of our frac fluid out of the way, and we still need to clean up this well. And so people ask will future wells act like this? And the answer is I certainly believe in hopes of -- because everything we've seen from this is that lots and lots of hydrocarbons moved through this rock. I mean just for the same clean out that begins tomorrow, I'm anxious to really show what this [indiscernible] can do, and I'm really, really excited about our path forward. And with that, I'll pass it to Pat Galvin to discuss the commercial side.

Thank you, Michael. Great to be here with you folks today. Again, my name is Pat Galvin, I'm the Chief Commercial Officer and General Counsel for Pantheon up here in Alaska. And I'm going to talk about our NGLs, how we get them to market and what kind of value we can expect to receive for them. The main questions are these 3: can we transport our NGLs to market. Quick answer, yes, and I'll explain how. Second, how are NGLs priced on the North Slope? And because NGLs have long been a part of the North Slope product stream, there's a very robust and sophisticated method in which those are priced, and I'll explain that as well. And then finally, based on that method and what we're seeing today in terms of the production mix of oil condensate and NGLs from Alkaid #2, what do we estimate the value of that stream to be on that Alaska North Slope methodology? And right now, what we're looking at is about 80% to 90% of the Alaska North Slope crude price based upon the current production mix. all of which we expect to actually improve and increase in value. So focusing on that first question, how are NGLs transport to the market from the North Slope? Quick answer is through the TAPS pipeline, like all the rest of the crude. Historically, NGLs have really always been part of the mix of product that has gone through the Trans Alaska Pipeline. Here, you see a chart in the last 20 years, you can see the component there in red that represents the NGL portion of that production. So when we think about what they call ANS crude, Alaskan North Slope crude, it really has always been a mix of oil, condensate and NGL that make up what we commonly refer to as North Slope crude. As I said recently, the percentage that NGLs make up of that throughput is increasing. For example, at Prudhoe Bay, it's currently about 22% NGLs are 22% of the production at the Prudhoe Bay field. We're talking about over 40,000 barrels a day of NGLs that are mixed with the oil to go down the Trans Alaska Pipeline from Prudhoe Bay crude obey alone. By comparison, the Point Thomson field is 100% condensate. And again, that's mixed in. So each of these fields are contributing a different combination of oil, condensate and NGL into the Trans Alaska Pipeline system. The state just lumps it all together when -- they report on Alaska production, they generally just combine oil and NGL into their calculation. Here is a typical chart that's put out by the state, this one by the Alaska Oil and Gas Conservation Commission that shows the different production from each of the fields. And as you see at the top, we've got oil and NGL, and they don't even mention that condensate is mixed in with the oil portion as one stream that is tracked by the state as the production level. So we know we can get the NGLs to market. The next question is what kind of value are we going to get for those -- on the North Slope, because the NGLs have been part of the mix from the beginning, they have a system in order to properly compensate the producers based upon the value of the stream they're contributing to the system -- even though everyone is getting the same stream at the bottom. So when you think about the streams coming into the Trans Alaska Pipeline system at Pump Station 1, you're looking at different pipes that feed into the Trans Alaska Pipeline, each of them with their own different mix of oil, NGLs, condensates from the different fields. Prudhoe Bay has a dedicated line that comes in to pump station 1 directly as does the Lisburne field with a direct line. The [ Compart ] pipeline is bringing the mix that's coming from as far west as the Alpine, Ooguruk, and the Nikaitchuq has a feed in the [indiscernible] point line feeds and the part production, all mixed together and arrive at Pump Station 1 as a singular blend. On the east side, the North Star pipeline is bringing a mix from not only North Star, Point Mac, Endicott and Badami, but also that condensate that's coming from Point Thomson. All of that's blended together in that pipeline when it arrives at Pump Station 1. All these fields with all these different combinations of oil condensate and NGLs, then mix at Pump Station 1 become a single blend that gets transported down the pipeline. And that doesn't even represent the final stream because along the pipeline route, there are 2 refineries that are taking that common stream out of the pipeline, refining it and pushing back the remnants that they're not using and putting those back into the pipeline to continue on the path down to the marine terminal. So as we get down to the marine terminal at Valdez, it's a very different mix than what started at Pump Station 1, and that was a very different mix than what each of the producers put into their system from their field. So how do they compensate those producers for the difference between the product stream that they put into the system versus the collective stream that they're getting now. They have created what they call the TAPS quality bank. This is operated by a third party that evaluates each of those input streams to determine the relative makeup of it in terms of the different component parts and then what the value is for those component parts and what value to assign to each of those inputted streams. And they do that through a distillation method, look at the boiling point of each of the component parts to determine what percentage of that particular stream is made up of what percentage of each of these component parts. And then those component parts are given a dollar value based upon what the refineries will compensate for each of those components. So that allows a value to be assigned to each of the input streams based upon the relative value of the aggregate components. So each field gets a value, those are compared to each other and then compared to the value of the stream that comes out at the bottom of TAPS. Each producer then is given either a credit or a debit depending upon whether the stream that they contributed is more or less valuable than the full stream that came out and went to market as ANS crude. Most of this is -- completely opaque to the market. It's highly confidential, the valuation system, the quality bank adjustments. However, we have an insight because it's under our oil sale contract, we get access to this data. And we're able to then do an estimate of what our current production that we're seeing at Alkaid #2 would generate in terms of the assigned value of those component parts through the quality bank system. So we can get an estimate of what our current production mix would be compared to the quality bank adjustment. And what we see right now is that we're looking at about 80% to 90% or higher of the ANS, the Alaska North Slope crude price. And just note that the ANS crude price is currently selling at a premium to WTI. We also know that -- as we move forward in this process, we're only at the preliminary results of the flowback. We have a cleanup process to go. We're going to get more data that will indicate components of our NGL mix that we currently can't measure, and these are likely to be the higher-value components. So we see a lot of potential for uplift in our value stream, both from Alkaid #2. And then as Michael indicated, when we get into a development and production phase, the placement of our wells will likely result in a different mix of NGLs and oil. Right now, this is based upon a stream that is predominantly NGLs, which are collectively lower value. versus one that we would expect later to have probably a greater percentage of oil, which will lift us up at least to Alaska North Slope crude price, perhaps even getting a premium above it. So the one thing we can say with confidence is that the production that we're seeing from Alkaid #2 has obviously significant value, as Michael said, $40,000 a day worth from its current production, and we see that as likely increasing as we move through this development process. With that, I'll turn it over to Dr. Ed Duncan for his presentation.

Thank you, Pat. Welcome folks to my section of the webinar. I appreciate your time. I look forward to presenting some regional data that helps us establish the position that we're in and helps us understand the Alkaid #2 results in the context of our broader portfolio. The slide on the screen that you see, I took this picture July of 2022, while on well site at Alkaid #2. We talk a lot about location and proximity to infrastructure. Well, this is pretty graphic delta highway. The corner of my truck, I'm driving is right there in the lower right hand, Alkaid #2 rig is right in front of you, the Alkaid #1 location, if the mask goes on location there would be just slightly to the left of the 3 tanks on the left of the rig that you see. It would be out on the horizon about 4 miles away, very, very close to the road, turned around 180 degrees and took a picture, you'd see the Trans Alaska Pipeline about 200, 300 meters away from our outstanding. So infrastructure is all around us, and that is pretty much unique on the North Slope for the exploration companies and now moving towards production companies that you've been in about and hear you about over the last years or so. Next slide, Jerry. Many of these points have been made by Michael and Pat and others, so I don't want to labor over things that you've heard at least once or twice before. But things on here that are important for us to remember, not just us as a technical team but us as a group of interested parties and investors. Beyond the analysis of the oil and gas samples of Alkaid #2, we understand the source rocks responsible for the oil and gas sampled and analyzed immediately adjacent to the Alkaid accumulation, -- the database that we have for -- for understanding the Alkaid accumulation is vast. We actually have rock samples of the source rocks from Alkaid #1 and [ MIRAI 1 ] that we drilled in 2012. These are the source rocks that generated the light oil and gas that we're testing. They generate oil and gas these source rocks generate oil and gas from the onset of generation and expulsion -- the Alkaid oil quality and richness of the gas that we are seeing are not unexpected. They're in line with expectations. As Michael illustrated and explained very clearly in his presentation, the flow test gas volumes are tied to free gas intersected by the completion in frac. With exsolution of gas out of the oil, contributing to the gas rate flow, all perfectly explainable. There's nothing shocking here. The possibility of a volumetrically insignificant gas cap in the very highest point of the trap is also explained. Note that Alkaid, the Alkaid structures, a well-defined structural track with a high point within the footprint of the accumulation. That's unique in our portfolio. Our other major discoveries, Talitha and Theta West are stratigraphic traps with the lateral [ un dip ] trap edge defined by reservoir zero edges. In the case of the massive Theta West discovery, for example, any possible gas cap in that accumulation would like significantly up dip of our current lease position. Let's go to the next slide, please. I think an important message to relay to our investor base and other interested parties is that we do the work and have done the work. We continue to sample and analyze our oils and gases as we drill as we complete and test. The picture in front of you, or vials of oil collected during flow tests of the various projects as they unfolded. Alkaid #1 and Alkaid #2 oils on the right-hand side, Talitha basin floor, Talitha Zone 3, 2 and Theta West oils in front of us. No other oil company on the North Slope of Alaska can match the oil resource volumes that we have discovered and proven over the last few years. The oil quality of our discoveries is spectacular. You can see from the API numbers, the 37.6% to 37.1%, 36.2% labeled on the vials. It's all very high quality, high API oil. That means it has very low viscosity. It flows well. Now importantly, if we go to the next slide, please. Importantly, our oils are genetically related. They're all very similar, not by accident. They're all pretty similar because they're generally [indiscernible] sourced from exactly the same source rock across the region with variations in oil quality and chemistry with variations in thermal [indiscernible] that's the amount of heat that source rock was exposed to during burial. We have such a vast area of projects. There is differences in depth of burial of the source rock. But all of the source rocks, all of the oils are related to the same source rock suite. And that is a very important fact for us as we move forward because what we learned in Alkaid #2 how we decide to ultimately complete and produce these reservoirs in this oil and gas, we can take that knowledge, that learning to translate it quickly through the portfolio because we understand the chemistry of the oils and the gases that we are encountering when we drill our wells. That's a huge point for us. Technology transfer is so incredibly valuable. Next slide, please, Jeff. Hopefully, supplying some reassurance that you understand that we've actually invested the time and effort to understand the controlling systems that we're exploited. Not every company does this. Our confidence in our assessment of Alkaid and our other oil discoveries is not built on the back of aspirational hopes, wishes and guesses, but multiple successful wealth penetrations and oil discoveries, high-quality 3D and more than a decade of building an understanding of multiple petroleum systems across North Alaska. That historical effort that we've put in, and we utilize every day, has informed us and empowered us as we build out our portfolio towards the drilling activity that we've all witnessed over the last few years. The successes we have, they're world class at scale, enabled by the trust, our investor base has had in us to deliver are now in hand. We are on the cusp of a great transition from exploration to production. That's the target of every exploration-led company on the planet, getting to large-scale production. We are on the cusp of that. I have seen absolutely nothing in the results to date that suggests anything other than a positive outcome for you, our investors in the state of Alaska. What have we learned? A lot of this has been discussed already. But certainly, we understand that the long-term testing is critical to how we move forward to full field development at allocate and beyond. Talitha and Theta West projects are going to benefit greatly from what we're learning from Alkaid. The other thing that's important for us to realize is that we've proven we can identify light oil from the accumulations in our 3D seismic data. And that allows us -- we're 4 for 4. And that allows us to expand the portfolio if and when we decide that that's something that we want to do. Importantly, -- the procedures that we have followed, not just geological, geophysical procedures, but the testing, completion, drilling, completion and testing procedures that we have are rooted in strong analogs to plays in the Lower 48 that we've all heard about. Many of us know about. Successful Lower 48 plays like the Permian Basin, Spraberry Bone Springs or the Eagle Ford in South Texas. The analogy to our play is not in the age of the rock. It's not in the mineralogy of the reservoirs. It's in the fact that these are thick oil-bearing zones that have laterally extensive thin-bedded reservoir zones similar to our reservoirs, albeit as Michael pointed out, much lower permeabilities than our Alaska reservoirs. The technology developed in these locations, long laterals, multistage fracs have delivered billions of barrels of oil in trillions of cubic feet of gas that would otherwise have been stranding. The gift of those technologies developed in other basins over the last 10 to 15 years is that we can transfer those learnings, that technology to our plays and apply them in a similar way. Deploying these proven technologies to the North Slope is not some misguided guess or hope. It's intelligent technology transfer. Today, as Bob Rosenthal pointed out, SLB also casually known, I suppose, Schlumberger, have built static and dynamic models portfolio-wide across Alkaid, Talitha, and Theta West. Some 13 million individual [ cells ] in the current model is being updated with the results of Alkaid #2. The data from Alkaid #1 will be translated through the 3-dimensional model, reservoir model that SLB will build, and that will inform us even further in how we approach drilling and completing and producing our other assets. We thank you all for attending, and I look forward to meeting you all again soon. Best of luck to all of you. And of course, happy new year. Thank you.

So what's the way forward? Thanks, Ed, because you pointed out that we are actively engaged with SLB to upgrade our dynamic models, static and dynamic models across all our reservoirs. That's taking again the information from Alkaid #2 and all that new data that's coming in and update the models. So what's the output of that? So we're going to translate 20 billion barrels of oil in place into a field development. We're also going to engage a confident person, a content person Corporation, to put out IRs, which are the independent expert reports. We're going to prioritize Theta West and Alkaid. Theta West because we haven't put out an IER on Theta West yet, but we will. And then secondly, Alkaid with because, of course, with all new results we want to do is ultimately put out a reserve report on Alkaid. SLB has agreed to set up virtual data room that they will run and will present to potential [ farminees ], potential partners and to the competent persons. That data room, the key to that is they're going to be showing all of this work that they've been doing on the static and dynamic model on all the reservoirs. Of course, we've gone to them because they're the biggest. They're probably the best in the world at putting together these models, and they have done a really good job.

Bob? I'd like to add to this all points well made. But in my visit in Houston with the Schlumberger team, I met with the full reservoir evaluation team as well as others in the Schlumberger sphere of technical expertise in Houston discussing our project. And I thought it was extraordinary during the discussion, they're senior reservoir engineering adviser made it abundantly clear. Straight tubing because, look, if we see something that is toxic, something that is bad news, something that you need to know about now. We're not holding that back from you. We're going to tell you on the spot. As soon as we know, you're going to hear it. Now at the same time, that's when SLB suggested that they actually step in and help manage the forward-looking process for the IRs, the competent person reports as well as farm outs and partnership reviews. That's -- they volunteered to do that. That's not something I said, "Hey, will you do this? They volunteered to do that is extraordinary. This company has the highest technical integrity of any company that I've worked with. And I think it's fantastic that they are stepping forward to assist us because I believe as they have stated, they see this as a positive project.

Thanks for that. I appreciate that. That's -- those are great points. that we would be actively going out looking for potential partners or [indiscernible]. We are such a better position now than we've ever been before. This is a fantastic product, A, that they have put out; and B, we are now in the middle of testing our first production oil, and we're going to have a long-term production test. So we're in a really, really good position now to do finding a farminee or a potential partner. So what's next after Alkaid. I think what we'd like to do next is go up and test yes, the of margin they'll take at the Alkaid pad, do something similar that we're doing at Alkaid, at the Alkaid reservoir, which is try to put on a long-term production test or at least go in and do maybe a short lateral and a longer-term test than you normally can do during the winter. We also want to do a test of the southern block of the Alkaid field, and that is called the factor block. And again, we want to do that along the highway, put a pad there and put on a long-term production test on that. And one of the things we'd also like to do is an up dip well to our last Theta West well. So a lot there for possibly in the future. I think with that, I'll turn it over to Jay, and maybe let him say a few words.

Well, thank you, Bob, and I want to thank all of the presenters that presented here today. And the only thing I'll say is that the information that you have seen in today's webinar is the reason why we, as a management team, remain so confident about the allocate project and all of our projects across our portfolio. And now on to the Q&A session.

Thank you, Jay. Look, I -- given the recent share price fall, it's no surprise, we've got an enormous amount of questions. I have them here spanning 9 pages. I'll do my best to combine them, and I'll try and combine them by group. And what I will do is pass them out to the people, I think, are the most appropriate to answer them. I shout out to Mr. [ indiscernible], as has become a tradition for our company. He has done a wonderful job in curating investor questions across the board. And I'll launch into it now. I'll start with questions regarding Alkaid #2 and then we'll progress into questions about corporate funding, Investor Relations, and then we'll move forward towards the conclusion. So Alkaid #2, there's a bunch of very small technical questions. Some of them may seem quite simple to people on our team, but we need to understand again that a lot of our investors, of course, don't have the technical expertise that we do. So this is to you, Michael. I've got a couple of questions here or group together. And this was the question about the frac. And again, because of the share price fall, fairly unfairly a narrative has formed that perhaps we didn't do as good a job as we may have or maybe we didn't understand what was going on. And some of these questions relate to that. And I think from the quality of what we've just seen in the webinar so far, many of these would have been answered. So I'm going to highlight the ones that we haven't covered. And Michael, a couple of specific questions, which I'll group together, what is on frac sand. Did we use the correct type of frac sand, particle size, shape and strength. A question on the frac fluid data, how many barrels of frac fluid were injected into the well? Was it more or less than 200,000 barrels. And then the third question, I'll pass across to Bob actually, and this is on VAS, -- did the AHS [indiscernible] team comment as a complete [ VAS ] cuttings on Alkaid #2? And can you talk about those, please? So Michael, over to you if I may.

Thank you, Justin. Regarding the frac and the completion, your first question was the right proppant use. The answer is as far as we tell absolutely. The biggest thing we talk about proppant is size and quality. And the bigger size allows better permeability. The counterpoint is bigger sand is harder to carry. And so you try to choose your proppant based on the best conductivity you can properly put in the reservoir. And we chose more course proppant that is conventionally used in the Lower 48, and we did so because we recognized our reservoir has more permeability. So the course our proppant would be better suited. The challenges can be place that course proppant is easy. And the answer is now in hindsight, yes, we were successful in placing it. We've seen no indication in the proppant crush. The sand that we've recovered from the well is intact and matches the size we put there. So we see no strength issues. We see no indication of deterioration. We've successfully placed more course proppant than that is conventionally used and very happy about that because we have a more permeable proppant pack. Regarding the water that was used to put it there, we used approximately 165,000 barrels of water to place 7.5 million pounds of sand. So now that's less than 200,000. In the future, I would hope we could even cut that back in place and more efficiently using less water. And so I look forward to that. But so far, I'm very happy that we accurately and reliably placed a course and permeable proppant in the reservoir.

That's fantastic. Thanks, Michael. Bob, the question on the VAS work. Would you me commenting on it, please?

Well, the first -- what I think we should do is have like a little webinar from Mike Smith and his team on their work, but I would simply put it is they sampled the vertical well, the pilot hole and through the hole horizontal. And I think they saw a superb kind of oil analysis throughout the hole horizontal. So I think that's a quick summary. And what I do is I will promise that they will give a show and tell of all their work in the next few weeks.

Thanks Bob. Just on that and of interest to all of our shareholders, will naturally be having another webinar towards the end of February for our AGM. So perhaps, Bob, that's something we can talk about maybe including Mike, in that webinar to provide that insight at that point in time.

That's great.

Yes. Okay. Look, Michael, another quick question back to you. There's a bunch of different questions just regarding the concept of cleanup. What stage of cleanup we at? And how do we measure that? I think our ANS is referred to being at the 40% of cleanup stage. Can you just explain to somebody with very little knowledge just what that 40% means. Does that mean that we're constraining our flow to 40% of maximum? Or does it mean something different?

What that 40% number refers to is the volume of water we produced in comparison to the volume of water we put in formation? So in this case, the frac was 165,000 barrels -- if we say we're at 40% recovery, that means that the volume produced is equal to 40% of that or roughly 65,000 barrels. That's a difficult number to use. It's often used because you don't have an easy one. But the catch is some of the water that was produced came not from the frac, but out of formation. And so understanding what the mix of water is, is difficult to do it best. With time and decline curves, it gets very easy, and we will get there. But to date, what we know is that the water we've got out of the well is roughly 40% of the volume that we've put there. And so we know there's a lot of volume we placed there that is still in the flow path and is still moving through the rock where formation fluid, which is gas oil, water, will take it to place in the future. So that's what cleanup refers to.

Understood. So it wouldn't be incorrect, therefore, to say that we're at up to 40% of the cleanup phase rather than 40% for the reason you just mentioned?

That's a more accurate way to describe it. It certainly conveys that there's still a lot of frac water that was placed there that is moving through the reservoir instead of a well.

Yes, which, of course, gives us potential for improvement in flow as the well cleans up further.

Very anxious to see.

Yes, Jay, a question for you, if I may. We've had a number of discussions on this. And this is the concept of gas reinjection. There's a narrative which is formed from some shareholders concerned about the volume of gas that we've seen and how we might deal with that. Will that be a problem? Or can we reinject it. If we can reinject it. Is there a limit on how much you can reinject. Jay, would you mind giving some color on that, please?

Yes. Well, in our full field development, we have 45 development wells and 11 injection wells. And we will be able to reinject 100% of the natural gas that we produce and don't use on the surface. And that will be easily reinjectable, and we'll have plenty of horsepower to do that. We have plenty of gas to run that horsepower. And it's not an issue for reinjection of the gas. And we might -- we've considered also reinjecting the CO2 that we produce on the surface. And those all will enhance ultimately the ultimate recovery from the reservoir.

Great, Jay. Another question, Jay. -- if you could explain again, this is clearly from somebody that doesn't perhaps have the understanding we have. But I have seen the question several times, so if you could explain it, please? And the question is, did we consider focusing a percentage of the lateral, for example, like a laboratory with some without a frac, some with the frac, some of the frac fluids. I said to get them into different -- of the 500 to 1,000 foot sections. Is it possible to test each of those 5,000 feet sections separately. Could you comment on that, Jay?

We didn't consider it to try and do that would be very difficult, very expensive, very time-consuming. And likely, you wouldn't learn very much that we don't learn from doing it the way we did it.

Understood. Thank you, Jay. Look, Michael, back to you. It's another question concerning a workover rig. And the question is the operation that you're going to do, I know you touched upon it, but what risks do you see with that clean-up operation? And do you intend to have the rig standby on location, just in case it's needed again?

So any time you get in well, there are risks. Removing the tubing should be fairly straightforward. In the past, we've seen some minor hiccups of difficulty releasing a packer, for example. But they're fairly reliably overcome, and we don't see any visible risk of catastrophic or of severely detrimental failure in that process. In a cleanout, we've already showed we can get in and out of this well with much inferior tools. Now we have the right tools. I feel we have the right information. And so I'm very encouraged by what will happen moving forward. We now have the right horsepower -- and so it's never without risk, but we will keep the rig on location afterwards during and afterwards, not because of risk necessarily, but because the rig will move down the highway afterwards to drill the Energy [ 88 ] well. And so we will have access to the equipment on location because we will store it there for our neighbors.

Great. And Bob, just on that point, when we do the clear out and then put the well back into production -- what is more -- what can we do to try and minimize the chance of more sand coming back in and causing another blockage? Is there any technique that you would use when you start testing to try and, I don't know, flush that sand, flush the sand out or something?

Absolutely. The -- we intend to do that especially during a clean out. It's a little difficult. We'll manage our fluid and we will try to maintain our circulation that sand can move, will move. When we go to bring the well back online, we'll do so under very strict flow control, very strict choke management. We'll bring it on slowly and methodically to make sure it comes on nice.

And Michael, could you explain the situation when you commence flow testing, just to enable shareholders to picture what maybe occurring on location? Are you sitting in a room by yourself or with one of your colleagues -- or do you have consultants from the flow testing firms. What's the situation on location when it comes to making decisions or perhaps if we see something that we haven't seen before and then to put our thinking cap on?

Well, the -- it's always manned. The equipment is manned. And so for this well early, we used a test spread [ Expro ], it's commonly referred to as flowback in the Lower 48. And what happens is there's people managing a [indiscernible] typically with every well we brought on. I'd like to sit in that -- in the control center there for separation, and we make our decisions in real time. And on that note, I mean hour in there just because it's going be 24/7. In this case, it won't be much different. We'll be using our own separating system it's on location. It will be manned 24/7. We will be watching it to bring it online very slowly. You open a choke, you allow slow movement to come in and want to stabilize, you make your decisions and go. We have a lot of indication that this will go smooth. We've brought this well on twice now, and we've learned a lot. Very excited to bring it on the third time. And yes, we'll have the right people in place to open it slowly and make the right decisions.

So that's great. Look, Jay, a couple of questions for you. One is about the financial performance of Alkaid. I think we touched upon what the hydrocarbons could generate in terms of revenues when in production. But what about daily cash burn as opposed to where we're drilling a well and there's a high cash burn, what happens when we're actually in the production phase. Is there a lot of equipment or a lot of moving parts? Is there a lot of cash burn on a daily basis?

Actually, there's -- I won't say very little, but it's minimized because you don't have a lot of personnel on site. We could run our facilities with very few people. We get real-time data on the computer. So once the well is on stream and leveled out, it's really kind of minimal cost going forward. Now obviously, in full field development, we'll have a few more personnel on site, but still, you'll be able to monitor everything remotely and see what's going on. So costs go way down once you're through that drilling and heavily personnel intensive capital in terms of part of the stream.

Just stay there. Look, there's another -- a couple of questions that come in on a similar note, and that was that in our update end of December, we spoke about production averaging 500 barrels of liquids a day over 30 days. And for the mathematicians out there, that gives us 15,000 barrels of liquids, yet we only mentioned that we've sold 7,000 barrels. What happened to the other 8,000 barrels?

Okay. So as Michael explained early on, our facilities right now do not capture the NGLs and the condensate that are actually going out with the gas stream. The only thing we're capturing is the oil that is separated out in that 3-phase separation. And so that is what we have been able to sell the approximate 200 barrels a day of the oil that's been separated out. But in the future, as Michael said, when we are separating everything under pressure and we have some refrigeration, we will capture all of those liquids and keep them under pressure. And as Michael said, deliver them directly to TAPS.

Understood. So the obvious question there is -- and I know Michael touched upon this I think, Michael, you mentioned there weren't significant numbers, but could you give us a feel or a range of what the cost would be of that additional equipment that we would need to put into our facilities in order to capture those other liquids?

Well, Michael will be better positioned to give an estimate. But when I asked one of our facilities guys, what it would cost, he said, well, you had asked me a year ago, I would have said $750,000. So I'm sure it's more expensive than that now, but it's not huge dollars.

It's not tens of millions, and that point.

Well said, Jay, it certainly is not tens of millions. And I think your order of magnitude is absolutely correct.

Bob, a question for you, if I may. Alkaid #2, of course, we guided the market towards 150 barrels of oil per 1,000 foot of lateral, and we produced oil as well as NGLs and condensate and gas. This -- if this was unexpected, why didn't we guide the market towards that previously?

Well, I think we've tried to answer that in detail in the webinar. And the amount of gas we saw at Alkaid #2 [ lower ] than expected. The content, thus the high -- the richness of the gas, which means content of NGLs and condensate unexpected, but it was the amount of gas we were producing. So first off, is we think we have [Technical Difficulty] to that. Then we've tapped into a small gas cap. And we know that if we do the wellbore around or we drill the horizontal slightly down dip or work slightly deeper. We will not be in contact that gas cap at Alkaid. Now when we're talking about going to say West and what's called short margin delay, they'll take, but focus on Theta West. We've got a handle there that at oil that we're seeing, it was light oil. Again, it's going to have dissolved gas in it, and we will have some production of NGLs and condensate in that, but it's not going to be a high proportion that we're seeing at okay, unless we drill a well, way up dip of where we're at structure that maybe it's not going to be on the acreage we currently have. So what we have now is because of the results we've seen at Alkaid is a better way of predicting what those mixtures are going to be when we drill at Theta West or in [indiscernible] I hope that answers the question.

Yes, Bob, that's great.

May I take an effort at that as well, please?

Sure.

The couple of points I would look to is one, moving our well down in the formation will change that. And that's not a novel concept any more than if your pump is getting some air and it moved the intake deeper in the water. And so that concept alone that we have the steps to adjust is important. But also when we look at the concept of evaluating this and looking back at the well, the right way to do it, the right way to report this to the market is through reservoir engineering decline curve forecasting and applying the appropriate product pricing mix. And that's all underway, and we will do that. And that will be the real scorecard with which this well is measured. Now it's too early to do that and because of circumstances, we are forced to give an interim report. But the true reporting on the market, the true reserves will be through an independent expert report, and that's underway.

Michael, really, really great answer. And you've just triggered something in my mind. And that is that in all of our ANSs, we always say that a definitive assessment of the well cannot be made until flow testing operations have been completed. And of course, as we've just discussed, we're only up to a maximum of 40% of the way through the cleanup phase. So great feedback. Thank you, Michael.

Sorry, and it's important because it adds you probably have other questions involved this next part Michael alluded to, we always plan to have [indiscernible] on Alkaid once we began testing the well and we get to the final and we get to the final kind of information that we collect from that well. So it was always in our plan to do that.

Great. And ANR being an independent expert report.

Correct.

Yes. Look, Bob, to stay there, just on this concept, given this different mix of hydrocarbons, does that change -- is there anything because of what we've seen in Alkaid that causes us to reevaluate our resource assessments for our Theta West and Talitha projects.

No. I think what we're going to get is a better handle on what I would call the dynamic model, which is how are you going to develop these fields. But the resource, I don't see changing the oil in place, but what the facilities are going to look like and what you're going to need to do this and where are the best places to drill your initial wells, I think we're going to get we're getting more information all the time from Alkaid, and that's going to influence us more into the full development of those projects.

I've got a few more questions here on Alkaid. But if I'm being honest, I think we've covered most of them off throughout the course of the presentation and without Q&A. If we miss anything, I apologize, but there's a lot of other stuff I want to get through. Can we circle back at the end if need be or investors can e-mail the in them will do our best to answer them subsequently. But I think we've really apart very specific questions. Did we turn it well on too far? Or actually, why don't we answer that now, Michael? Did we turn the well on too fast or too slow from all the data recovered in the last decade, while was management surprised by the volume of frac sand returning into the well. I know we touched upon that, Michael, but if you could just perhaps finish that one off and then we'll move on to the next section.

No, we certainly recognize that bringing it on slowly is important and to the best of our ability to look equipment there, we've done so. Once again, the sand wasn't necessarily unexpected, what was unexpected was the failure of our tools that we had lined up in order to address it. And so every well every horizontal well I've ever worked on prior to this project is how to clean up. And so this isn't an exception. And the efforts to bring it on slow are certainly identified. We will bring it on slow on the next go, and we'll continue to operate this well as other people operate their wells of similar completion in [indiscernible].

Great. Look, guys, we'll move on to the next section here. A couple of questions regarding the Schlumberger or SLB as we now refer to them, the SLB report. Bob, the first question for you. And the question is, what is the rationale for not releasing the complete SLB report to the market [indiscernible].

Well first of all, it's 190 slides, and it contains, as I've said, it contains like all the information and all the data we've collected over the last sort of 10 years, which represents [ $300 million ] box, just sort of dumping it out there and saying to whom it may concern, here it is. I'm not sure that would be our investors, our shareholders would say that was a kind of a [indiscernible].

Yes. Bob, if I give some context, this report was never intended to be published. I mean that's a fair statement, right? So we've [indiscernible].

Yes. It's [ weak ] and again, we asked Schlumberger to put together a summary of their key results, and they've done it. So what somebody looking at Slide 150 in trying to analyze it. And what does that mean? What are they going to do? They're going to get 3D sort of visualization and take off and put it out themselves.

Yes. Let me just interject quickly because the key is it's a working model -- and as you said, never intended as something for the public.

This is our working -- this is our working model that is showing us how fluid is flowing through all our reservoirs. And this model is where we're using it is in our data. It's going to be in our data room. It's going to be used by the competent person is going to be used by people who are looking to partner with us, and it's going to be used by farm and ease. And so yes, that's what it's there for.

And Bob, as a working model, I mean, many of us can't visualize what exactly that means. But does that mean that a group coming into the data room to consider a potential farm into our project. Is it easier -- is it a useful tool for them to be able to analyze or to understand what we potentially have?

Totally. Because it's the summary of all our work. It's what everybody wants to know. In other words, when I go to x location and I drill a horizontal well and I do X number of fracs on it, how do I expect that well to perform. If I drill a well 200 feet away, am I -- you're going to be looking at the -- how that well is performing. And then you're going to ask the question is, is the well next door influencing it in some fashion or another. My point is it's a summary of all our data, all a summary, 3D log data, sidewall cores, whole cores, everything we have is put in there. And it's there in such a way if people want to manipulate it, i.e., change parameters and things of that, they can see what the outcome is. That's why we put this together. That's why we went to Schlumberger. They're the best in the best in the world, and this is what their output.

Bob, just continuing on that theme. We spoke about this being Phase 1 of that project, and they're now commencing on Phase 2. Can you explain what Phase 2 will entail and if there will be a Phase 3 or Phase 4?

Well, Phase 2 is to take in general, they have the static model in which they've talked about 17 billion barrels of oil in place and then moving that now with all the new data we have, we've got a well that's flowing. We have -- we begin to analyze that, taking all that new data that we have and then going out across our portfolio, ultimately showing what the development across our portfolio is going to look like. That's the dynamic model. But that's evergreen. And what I mean by Evergreen, that will be ongoing as long sort of drilling wells. We will be working with Schlumberger, again, if it's this same group who are excellent and do really fantastic, we'll be working with them for a very, very, very long time. So Phase 2 has not an end date, it just keeps going.

Thanks, Bob. And if -- as you stated earlier, we intend to get one or more independent expert reports completed on our various projects. Is this SLB model, something that will be useful to an IER coming in to do that work?

Absolutely. And that's why -- again, why we did it. And it's not -- this is again post our winter program of 2022, we had physically gone out and tested multiple reservoirs and flowed hydrocarbons to the surface. We knew what we needed to get was this model. Once -- and I believe I've said it at least in some webinar or some interview, that one of the purposes of this is to have this as a tool that you can put in front of people so they can assess the project. And that assessment is going to be done by the competent person or again, partner or [indiscernible], but this is the tool they're going to want to look at. And the really great part about it is that the guys at SLB, who've done the work have said, well, they'll present it.

I remember Ed speaking, just a little earlier with this presentation saying that when he met them in -- it was Houston, he said, they even said to him that they would be blunt if they saw anything they didn't like any of our assessments that we -- that they thought were questionable, they would highlight them. Did we find anything in there? Is there anything that we should be concerned about?

No. I mean, again, we're -- these are top-notch professionals. It's the largest service company on the planet. And I would expect them to do it, and I would expect us, if they did, to take it on board in terms of our understanding of the project. Yes. So no, they haven't come up with anything. They didn't -- but they've been extremely helpful working with them to understand what's going on in the reservoir at Alkaid #2.

I think it's always an important discipline to have something like this because they challenge you. They'll -- I mean it removes the risk of confirmation bias or communal [indiscernible] of the cool aid or whatever. It's always good to have external people coming in and challenging our thinking to help us arrive at the best possible analysis. So no, that's great. Bob, on that, in the conclusion of their report, they commented that they felt that Theta West and Talitha may be gassier than Alkaid. Of course, Alkaid we've encountered a large volume of gas. I think we've mentioned here that it may be because we've intercepted or tapped into a -- or fracked into a gas cap. But can you give me some comments. Do you agree or disagree with that interpretation?

Well, I don't disagree. I think that would be in context of depth of burial or what they see in terms of the pressure regimes. Ed, I might throw it over to you.

Yes, Bob, let me comment on that. The variation -- we see the reflection of changes in thermal maturity of the source rock in Talitha and Theta west, in particular, the lower basin floor plan, I think, is probably the best example to use for the discussion that the GRZ,-HRZ,-Huge source rocks, which are responsible for most of the hydrocarbons that we've seen in our project are more deeply buried. So they're under higher thermal stress to the south in the Talitha area than they are certainly in the Alkaid area. And that -- that will generate -- we know these source rocks generate light oil and gas basically from onset of generation and the higher thermal stress and the more deeply buried areas or on Talitha will like better rate and even lighter oil that will be saturated as we would expect it to be with lighting with the gas generated. We don't see evidence -- frankly, we don't see evidence of a gas cap or free gas owned in Talitha and Theta West, and we wouldn't expect to, given the structural configuration of the trap. So the there's really nothing that we see in the geochemistry regionally. And we've sampled heavily. This is not something we haven't studied that we're going to see much more gas in that area.

Yes. I would just state that if what we're going to be doing is, in the future, saying, let's say, at Talitha, at Theta West, a horizontal well at Theta West is going to look like x at such and such location. And if we bring it on properly and we -- and we're pretty confident we're not going to have a gas cap sort of around the Theta West #1 well. We are not going to see the mon that we see in now Alkaid #1. That's just almost most to give in.

Exactly -- let me just that's exactly why the SLB dynamic model that currently has the 13 million cells is so important because it will give those answers.

Yes, I think. Agree. All fantastic. But just moving into now a more corporate section funding, farm-outs corporate. There's a bunch of questions concerning our cash position, whether or not we need to do a fundraising. The answer is [indiscernible] We have no current plans to be doing a fundraising at this point in time. We reported $16 million of cash on hand at the end of -- as of the 30 December, was fully funded for Alkaid #2. And in fact, we've got enough working capital to take us through in fact, until 2024. As Bob just mentioned, we currently operate opening the data room. We have SLB working on this with us and they're going to help in that process of managing parties or potential parties coming in to consider an investment into our project. We're also going to be getting a free look at the SLB, our neighbors immediately to the south are spudding a well for the SLB next month. It's in a deeper, more down-dip location, but nevertheless, the information gained will be of extreme value to us. Look, the nature of our business is capital intensive, and there's no surprise to that. But we also create immense value through drilling and analyzing data, which manifests into this value creation process. So our challenge is to leverage that value creation to attract partners or other funding. It's the way that the business model works. Globally, we all know there's a structural shortage of new large oil projects coming on stream or in the horizon. Our job is to generate enough data to allow parties coming in to recognize the potential of our project and come in and make an investment or at some point, ultimately, potentially buy us provided the price is right. Another question here is concerns what methods we have for raising funding and it's all the traditional channels, equity debt, quasi or farm out. As I stated a minute ago, we're not looking to raise any money at this point in time. That's not what we're doing. We certainly want to see [indiscernible] and then go through the farm-out route as our preferred option at this point in time. Questions on dilution. And again, I've got many questions concerning this concept. The question is are we worried about dilution in future fundraising given the lower share price? The answer is, look, yes, of course, we're concerned about the lower share price. But look at our track record in 16 years so this company has formed, we've never issued stock at deeper than a 10% discount. We've never once attached a free option, a free warrant, any of those small things that are so prevalent in small-cap land. We get dilution, we've managed it, I believe, incredibly well to date. Here we are with 100% of all of these projects, which we, as a company, estimate to have 22 billion barrels of oil in place. SLB, of course, estimated that to be 17.8 billion barrels of oil in place. These are incredibly large numbers and having 100% of each of these projects gives us so much flexibility. We can slice and dice a deal in any way it suits us. We could enter a transaction with a company to earn a right for one project or multiproject across our portfolio. There's any way we can cut it and we're open-minded. -- whichever route we take, there is an element of dilution, whether we bring in a farm-in partner or whether we raise equity or whether we raise debt. In some way, shape or form, there is an element of dilution. It's always been the way. It's the same way for every company, and it's something that we shouldn't be worried about. The next question here concerns farm-out partners. And the question specifically is, is the farming part or the party that was that came very close to entering a transaction with us in late 2021, still interested. Our answer is we just can't talk anything specific about any potential farm-in partners. The stock exchange rules and we just can't get into those discussions. The next question, Jay, I think I might pass this one over to you as the CEO. And the question is, if we get a successful flow test at Alkaid, do you think Pantheon will remain in a strong position to raise capital or agree with advantageous transaction in light of the significant share price fall that we've recently seen. Jay?

Well, I think the successful flow test will obviously help the share price, and that helps everything. It makes it easier to do either a farm out, bring in a partner or raise CapEx or capital me for our additional programs. So our share price helps everything.

Yes. Actually, Jay, you just mentioned a comment that with a higher share price, everything is better. It strikes me as unusual. We've just had an hour and a bit of a webinar here talking about how these results at Alkaid, in fact, is something that we should be pleased about and give real reason for optimism on our project. Yet we've seen our stock price drop by near on 2/3 over the last 4 or 5 months. Phillip, in your experience, particularly in context of Alaska and other parts of the U.S., what do you make of these results? Is it bad news? Or is it good news? Or is it a bump in the road? I mean how do you see it, Phillip?

Well, Justin, it's definitely not bad news. Bad news comes in the form of drilling a dry hole where you encounter no hydrocarbons whatsoever. The next real test of whether or not you've got a problem or not is when you put a well on test to test the production capability of the well. And obviously, we've succeeded there, and we still don't have the full lateral contributing at this point. So it would be very hard to say it's disappointing. I mean it could be the way that we are an estate that make people feel that way, but I think after people have heard how NGLs play a role in the production of TAPS that could change a lot of mines. I mean I do -- would like to reference that when I was up at Prudhoe Bay 1991, we're producing over 1 million barrels a day and 50,000 barrels of NGL. So it's always been part of the integrated stream on the Trans-Alaska Pipeline. In addition to that, we produced 6 billion cubic feet per day. So a lot of what people see, I can understand why they might view it in a negative context, but in my opinion, it's all pointing in a very positive direction.

Michael, you mentioned to be a number of weeks ago, we're chatting about things. It's the first well in the program in other fields you've worked in that how does the first well compared to, I don't know, the third or fourth well, as you -- iterative nature, you start to learn and optimize. Is it typical to see an improvement?

Absolutely. Could see the improvement. Yes, these early steps we're taking at first is hard even though which direction to go before your first well, but now we have a clear path of let's just move down debt, let's change of frac design a little bit. Those immediate steps will have great results, but there's still a lot of tuning, absolutely in the past, every step we see improvement in production, decrease in cost. That's not just me, that's been industry-wide. So I'm very excited about the next steps ahead.

Look, thank you, Michael. Gentlemen, time is cracking on, so I'm going to move through these questions a little bit swifter. I'm moving into the section now of sort of corporate listing and so on communications. But the first question, a little bit jarring, but it's about Board and management. In view of the fall in share price, the entry of the short sellers and a number of operational challenges -- does the Board think we need to boost confidence by securing additional expertise or make changes to the composition of the Board and management team. And I think I can have a crack at that. But the answer is absolutely. We've got an enormous project, and we're always looking to optimize it. We're not proud to admit if there's things we can learn or do better. We're always trying to learn and to do better. And if we think that we can add talent to improve our chance of execution and success, we will obviously do that. One thing we're proud of, that we wrote about, I think the Chairman statement in the annual report is that we've had percent staff retention rate. In an oil and gas market, we saw very high oil and gas prices with a lot of movement of staff. It's something we're very, very proud of. So the answer is absolutely, where we think it adds value, we will look. If you look at our G&A for last year, our team has already increased as we've been selectively hiring and it's something we'll continue to do. And as much as the discussion with SLB shows that we'll also use high level, the best level consultant firms where we see them as adding value to our project analytics as well. Next question, listing venue improvement. Would we consider moving Pantheon into another listing to try and attract more investors. The answer is yes, we would. It's something that we always look at. Late last year, we upgraded to the QX, the highest level of the OTC. We're seeing good volumes in that, and it's certainly been a positive for the U.S. investors. And look, we're always considering it. Would we consider a U.S. listing or dual listing. The answer is yes, we would, particularly as the project advances, and that's something that we work on at the moment. Next question, to me, timing of recent RNSs. Why did the Board of Directors released its results and the operational update so late in December. Look, unfortunately, we had very little choice. 2 things driven by the annual report. The annual report was it was for the financial year ended 30 of June, the data side of it must be a true -- reflected true and accurate reflection of the position. And therefore, it was incumbent upon us to give an update on the well operations at that point in time. So the 2 were always going to be linked. Why did the annual report so late in the year? The answer is we changed auditors. Our previous auditors who we had for the previous 15 years were publicly sanctioned in July of 2022. We found it for nothing to do with Pantheon at all on another audit. But we at Pantheon found ourselves looking for another a new auditor in the summer of 2022. Summer holidays a very difficult time also at a very difficult time to get auditors. They're bursting at the seams. They're very, very stretched. We signed with our new auditors, PKF on the 5 of October 2022 and -- it was always going to be a late -- very late December sign-off for that reason. When a new auditing firm takes over an audit for the first year, there's a lot of extra work that they do in order to come up to speed and to be able to sign off with proper knowledge that they're confident in what in their opinion that they express. The next question concerns the proficiency of our public relations. The question is, have we considered hiring a PR firm to help write us our news releases, press releases and so on. And the answer is we already have one, and they are involved in writing these things. We also have a very, very strong team included in our team is the ex-head of oil and gas sales at Merrill Lynch, Southeast Asia. They understand from the sell side, oil and gas very, very well. And we collectively are involved in trying to produce the best RNS that we can. Could we write the RNS better? Yes, we could. I mean, clearly -- and I think one of the things that we reflect upon in this slide with regards to Alkaid is this confusion and misunderstanding that occurred on the release of production of oil and other hydrocarbons versus our guidance towards pure oil. That's something that we'll reflect on and make sure that we get better in the future. Things like we're doing at the moment, our webinars have been very successful historically for Pantheon. We give an enormous amount of data and granularity. We typically would do this after the Alkaid well was complete. We're doing this now for, obviously, for different reasons, but normally we'll do it after the completion of this well or any other well for that matter. As I stated earlier on, we will be having one towards the end of February. We will report the exact date in due course, which will form part of our AGM. And of course, we can address hitting issues that we missed in this particular case -- in this particular webinar as part of that webinar. The next question concerns a recent article, which applied the dollar value per acre that Pantheon recently were successful in bidding for in the November statewide lease options to derive the valuation of Pantheon of about $6 million or $7 million. Jay, do you have a comment on that valuation methodology?

Well, Justin, it's really a pretty silly methodology because Hillcorp bought some acreage adjacent to Prudhoe Bay. And if you use that methodology, then Prudhoe Bay is worth about the same, about $6 million.

And of course, we know that Prudhoe is the largest oil field in North America. Gentlemen, with that intact, I think we're pretty much covered. I think we've covered everything off. Thank you very much indeed for your time today. Jay, did you want to as CEO have any final comments just reflecting on what we're seeing today?

I want to thank everybody that presented. It's been long. There's a lot of information, but I think what we've attempted to communicate to everybody that's watching and listening to this webinar is just how much data we've collected that everything we see today points to a commercial project at Alkaid and commercial projects across our portfolio, and we're very proud of that.

Thank you, Jay. Thank you, Phillip, Ed, Michael, Bob and Pat, really appreciated. Thank you so much. I'm sure our shareholders will be very much appreciative and good night to everybody. Thank you very much.

Have a good day, guys. Yes.