Pantheon Resources Plc (PANR) Earnings Call Transcript & Summary

I'm Jay Cheatham. I'm the CEO of Pantheon Resources. And to those of you around the world and the U.K. and Europe, good evening. For those in Asia, it's either late, late at night or early, early in the morning. Thank you for being on it. And a shout out to everyone in the U.S., but especially those of you on the North Slope that are viewing it. We know a lot of the people that are working with us up there are viewing it. You know who you are. You're the guys that make this all happen. And so thank you and a big shout out to all of those. And those down in Anchorage that support that effort up on the North Slope, thank you for all the work you do. It's incredible. We'll have over 300 people working on our projects this winter. So presenting today, I'll give a short introduction. Justin Hondris will be on, he is our Chief Financial Officer; Bob Rosenthal, our Technical Director. And the star of the show is Michael Duncan, our Vice President of Operations and Engineering. Coming to you from the comms room, the nerve center at our Talitha site on the North Slope, about 25 miles south of Deadhorse. A couple of shout outs. We've got Roger Young on, and I know Roger Young has a big following. He is not presenting today, but will be available for the Q&A. And a special shout-out to a friend of mine who is a photographer who lives on the East Coast and got tired of seeing me not with the proper lighting when I do these webinars. So he sent me this really hot, high-end light that I now am using. So [ Gordon ], thank you for that. And I've got one more prop I want to show. So those of you up on the North Slope, this is the flag that flew over the Nordic Calista last winter. And Michael gave it to me when I was up there this past summer, and we drove up the Dalton Highway, and we hunted and we fished. And when we finished, Michael pulled it out of his truck, and we folded it up, and I assure you it has a place of pride in my office. I'm going to turn off my camera because you don't need to see me as I give you the introduction. So you guys that have been on this before have seen this many, many times. This is the North Slope of Alaska and we talk about location, location, location. So the location is almost ideal. It's where the oil is, Prudhoe Bay, largest oilfield in North America. Kuparuk, either second or third, depending on how you measure them is the second or third largest oilfield in North America. The Trans Alaska Pipeline that was built because of the discovery of Prudhoe Bay and at one point in time was carrying 2 million barrels of oil per day, now carrying about 500,000 or a little less. The Dalton Highway, which is the feeder road that runs from Fairbanks to Deadhorse, 480-something miles. And most of the equipment that goes up to the North Slope comes on that highway. So location, location, location. So when Prudhoe Bay was discovered, the guy [indiscernible] said there's 10 billion barrels of oil in place and you will recover 3 billion barrels. You can see now it's 33 billion barrels of oil in place and the recovery will be over 16 billion barrels. Simply stated, good, big oil fields getting bigger and better over time. Something similar happened with Kuparuk. It's not -- it hasn't gone from 3 billion to 16 billion, but it's gotten larger. And the Alpine field that was discovered by our friends at eSeis, Roger Young is on the call today from eSeis, it was originally going to be 450 million or 500 million barrel field, and we'll now recover over a 1 billion barrels. In gray, you can see the outline of our 153,000 acres. And we are underneath or very close to both the Trans Alaska Pipeline and the Dalton Highway. Now before I get into a little more, today you're going to hear about what we've discovered, what we plan to do. So Bob Rosenthal will talk about that, and then Michael will give you the full rundown on our development program. So what's happened recently on North Slope, where Horseshoe and Pikka is a discovery to our west, some of it in the NPRA, some of it in some environmentally sensitive areas and some of it in the Arctic ocean at offshore. When Oil Search, and they've now sold out to Santos, but when Oil search entered some 4.5 years ago, they paid $3.10 per contingent barrel for the Horseshoe/Pikka interest. I'll talk a little bit more about that later. And you can see Willow where ConocoPhillips is, and they're having some issues with their environmental impact statement, and they're having to redo part of that. They're in the NPRA, that's National Petroleum Reserve Alaska. That's federal land. And over to our East is ANWR, that's the Alaskan Wildlife Refuge that's also federal land. Of note, you can see on our map and they're also active this winter is 88 Energy with their Merlin well, and that's about 13 miles south of where our map ends on this overview, and of course, quite a bit further west. So at the closest, we're over 30 miles away from NPRA and, at the furthest, we're over 50 miles away from ANWR. So location, location, location. Alaska. We're on state lands. We do not have any significant environmental issues. It's a stable environment. We have one royalty owner, the State of Alaska. Makes everything so much easier when you get to deal with one royalty owner and one stakeholder. We're near the export, as we said, the Trans Alaska Pipeline. Our average royalty is about 15%. It's an under-explored area as I think we have proven out over the last several years. Our 150,000 acres, we have 100% working interest. And to that, we added about 60,000 acres in the January 2021 lease sale and all of that in our Theta West project. We have announced that we have 17 billion barrels of oil in place with about 2.2 billion barrels resource recoverable. Those are management estimates. But we anticipate that we will be doing some more with independent experts later this year and next. At our units at Alkaid and Talitha, we have 67,000 acres. We have permanent tenure over those 2 units as long as we continue with the work program that we've negotiated with the State of Alaska. And we have done the majority of that work. So we have 67,000 acres there, over 80,000 acres outside of our units, and those have 8- and 9-year tenure. So along the Dalton Highway, where our Alkaid and Talitha units are, we believe that we have about 200 million barrels that is recoverable from drilling pads along the highway. And that means we can do year-round drilling from gravel pads along the Dalton Highway. It reduces our infrastructure costs greatly and allows us to be [ onstream ] more readily than potentially others in the area. So we're not saddled with the long-distance infrastructure that others would be saddled with. Our market cap today is somewhere around $800 million. And as I mentioned, when Oil Search entered, they paid $3.10 per contingent resource barrel. On an equivalent basis to our contingent resources, we're about $0.40 per contingent resource barrel with our market cap. And we know Oil Search has spent a huge amount of additional funds before they sold. So how do fields grow in size? Well, you get bolt-ons like Kuparuk where you have Tarn. You could increase your recovery factors. Our recovery factors are in the low teens, about 13% overall. If we just go to a normal recovery factor of, say, 25%, we will have doubled that 2.2 billion barrels to 4.4 billion barrels. So we have huge upside, I believe, in our area without any bolt-on fields. And 2021 year was a year of extraordinary achievement for us. Everyone else is going to talk about those achievements. But just to simply go through a few of them, we acquired the remainder of the Talitha unit that we didn't have in early January. We raised $96 million in December. We spudded the Theta West well last Friday. And just a quick overview on our management. We have very, very, very deep experience, both in Alaska and worldwide. And just to go from kind of looking at what's happening in Alaska, what's happening in the macro environment. So this is a Brent futures price curve. And our ANS sells at close to Brent. And you can see, a year ago, we were down around $40 a barrel, and we were in that range when we raised money a year ago. And now we're over $80 a barrel. So -- and it's increased over fourfold from its low back in April of 2020. And the CEO of Schlumberger, Olivier Le Peuch, said oil demand is expected to exceed pre-pandemic levels before the end of the year and further strengthen in 2023. And I agree with that. I think we're in for -- we're going to have some tailwinds in terms of oil price. I think there are many headwinds in terms of available capital for the resource industry. But certainly, I think that we'll have tailwinds on oil price. This is simply a -- shows decline curves for various production in the U.S. over time from when it came on stream. And you can see more recently, the U.S. has exhibited extremely high decline rates, especially with the unconventional -- hyperbolic declines with the unconventional. So there's a high level of drilling needed to maintain current production levels. Justin?

Well, thanks, Jay. Look, thank you very much for the introduction. It's Justin Hondris here. I'm FD of Pantheon. Today's webinar is achieving 2 things: one is a general update of the story for investors; and the second is it's tagging on to what would have been our AGM. We had the formal part this morning. And now this will be combined as part of our presentation. What I'd like to do is talk briefly about the team. Jay touched upon it a second ago. The team is super important because it's not only good assets, but it needs a strong management team to deliver success. And we have got a depth of experience on this team. Phillip, our Chairman, when Prudhoe Bay, the largest oilfield in North America, just north of us, as you saw in the previous slide, that was a BP-ARCO joint venture, Phillip ran the ARCO part, a huge amount of relevant Alaskan experience. Jay, most of you know already, 40-plus years experience in the market, in the oil and gas industry, ARCO as well as in private equity and a few other bits and pieces. Bob Rosenthal, a geologist, you know him as well. He'll be speaking shortly. I come from a financial background from banking. It's important to have a balance on a Board, diversified skill set. Pat Galvin, super important to us. He was previously the Alaskan Commissioner of Revenue. But importantly, he was a former Petroleum Land Manager for the Alaskan Department of Natural Resources or the DNR, as we like to call it. He was a partner in a law firm, a huge amount of experience relevant in Alaska. Jeremy Brest, he's a Non-Exec Director, not known to as many of you, but really important to us. He played a very important role supporting us in the recent convertible bond debt transaction that we did. We've got a gentleman called Mario Traviati. He was the former Head of Equity for Merrill Lynch in Southeast Asia, again, bringing in that market-facing experience to the Board. Michael Duncan, who you'll meet later on the call, VP of Operations. He's the main man today. You'll be hearing from him and I'll let him go on. Ed Duncan and Jerry Nichols, very, very important pillars of our geological and geophysical team. And eSeis, of course, Roger Young. Roger is a fan favorite amongst our shareholders. You'll hear from him in the Q&A section at the end. I keep reminding shareholders of this, Jay mentioned that he has been credited as being one of the key architects in the discovery of that Alpine field, the third largest field in Alaska. A couple of years ago, probably 2 years ago or a little bit less, his company was a third-party consultant to us and he forfeited $3 million worth of revenue in exchange for a very small royalty before we drilled up Talitha well last year. So it shows his belief in the story. Quickly moving on. What I would say to you about this team is that this amount of depth of experience brings a great in-depth knowledge of our asset base. I think we have 3 of the 4 founders of Great Bear Petroleum on that worksheet in front of you as part of our team. And of course, the team here at Pantheon have been together for a long time, too. That delivers us a deep experience, both geologically, but also in terms of relationships. And as Jay mentioned earlier on, it's enabled us to be in a position today where we have 100% of each of these assets with potential for 17 billion barrels of oil in place. It's a remarkable achievement. And I think even internally ourselves never envisaged that we'll be in this position today. So we're very, very grateful to be where we are. Just a quickie, it's a slide that I use often when I'm meeting with new people. I recognize a lot will know this already, but it's kind of a 3-point thesis here. Why the Alaska North Slope? I think Jay touched upon that. For us, it's a great area. There's been a huge amount of capital investment over the last 15 years in the unconventional shales in the Lower 48 and Alaska North Slope perhaps suffered from a bit of underinvestment and under-exploration. It's now shining in the Sun as far as we're concerned, and it's presenting a wonderful opportunity for us. A fantastic royalty structure, as Jay mentioned, averaging about 15%. By contrast, in Texas, it can be as much as 25%. Why Pantheon? And this is important. We touched upon that a second ago with the team. We've got a huge amount of experience. This is not a new project. It's been 12 years and $300 million investment into these assets that we have today. And we're now at the point here, we're now about to drill and test these wells that will reveal what the true potential of this asset is. So it's not -- it's very, very important. For many investors, it comes across as a new story, but it's not. This was a private company for a long time before Pantheon acquired it a few years ago. And it really has -- we really are at that exciting time right now. As mentioned, an experienced team. We've discovered 17 billion barrels of resource in place. We're on the doorstep of infrastructure, which is critical in Alaska. Jay touched upon that before. It allows us much more rapid development time horizons. It all moves into higher NPVs. And there's no known environmental or social impediments on our acreage. And the final point, of course, is the investment catalyst. Well, why would you be looking at this? And the answer is that there's a potential here. We're targeting to prove up potentially 1 billion barrels or more of oil on these 3 huge projects, Alkaid, Theta West and Talitha. It will be this winter/summer. I mean Alkaid realistically will be in the spring or early summer. It's a near-term commercialization opportunity. Jay mentioned the metrics. Oil Search paid $3.10 -- they've paid $3.10 in a $45 oil world. We're -- sorry, a bit higher than that, but we're in a much higher probably -- a much higher regime right now, implying $0.40 per barrel of oil comparison, plenty of leverage there. And of course, if we have some success, plenty more to come. Jay touched upon our achievements. I think it's important. We've got $96 million in the bank. That gives us a really important asset, and that is portfolio diversification. We have 3 wells with multiple independent targets. Alkaid was drilled previously. We flow-tested that successfully. We're drilling in what we would call an appraisal/development well shortly. Talitha. It's not a wildcat well. That was drilled last year. We flowed -- excuse me, we've -- apologies, we've had logs in that well. We've got data. We had AHS, which was a large feature of the previous webinar, over 3,700 feet of oil column confirmed through their samples. We're now testing that in the coming weeks. Theta West, of course, was spudded over the week, made on Friday. Michael will talk more about that and the Alkaid Well. Our budgets are revealed there. They're pretty straightforward. What I would say is Theta West may be a little bit more than that depending on the extent of which we do testing. One thing I wanted to make sure because I think it's a point of a bit of misunderstanding is that we're drilling vertical wells here, certainly in the first 2. And those wells are designed not to maximize flow rates. They're designed to prove the movability of the oil and to determine the quality of the oil. The production wells will be drilled horizontally going forward in the future. And of course, there's a -- the flow rates from those wells will be significantly higher. With that, I'll pass over to Bob Rosenthal, our Technical Director, to run you through the high-level overview of our project. Over to you, Bob.

Actually, I think I'll take this. Yes. Thanks, Justin. As you guys can see, we're doing this live. So our project overview, I mentioned there is 17 billion barrels of oil in place and 2.2 billion recoverable. We had a lot of people sending questions saying give us the detail of this, and this is exactly that. So our Alkaid Shallow and our Alkaid Deep, about 3.5 billion barrels of oil in place, 480 million barrels of resource. And if you follow the color codes, we've got the color codes throughout the presentation. 2 zones there, 5 independent zones in Talitha. We plugged off the Kuparuk. That was a little bit troublesome for us last year, but pretty soon, Michael will be testing the Lower Basin Floor Fan and then go up to 2 zones in the Slope Fan System and then the Shelf Margin Deltaic, which was the original primary target of the Talitha-A well, 1.4 billion barrels of oil in place, 340 million barrels resource there at Talitha. Theta West, the big kahuna, 12 billion barrels of oil in place, 1.4 billion barrels of resource. And before we go on, we were just -- we were chatting a little bit, and Bob was saying, it's 17 miles this structure, 17 miles. So it's huge. It's really big. So just a little bit on Alkaid, the Alkaid Shallow, which is the upper zone, wraps around from the Shelf Margin Deltaic and the Alkaid Deep. And just to show the impact of the oil price, and this is our current conceptual development model, this was for the deep. It was developed by Lee Keeling. In the shallow, we've used something very similar. A year ago if we had been talking about it at $40 oil, it wouldn't have been that exciting, $175 million of NPV. But look at it today, I didn't check prices this morning, but let's just say they're in -- it's $85 on Brent. It was $88 on the closed Friday, somewhere between $4.5 billion and $5 billion -- over $5 billion of NPV, over $10 a barrel in the shallow -- excuse me, in the Alkaid Deep is from directly from the Lee Keeling. A year ago at $40 million -- $68 million; today, over $1 billion of NPV. So those developments that are in our 2 units combined could have $6 billion of net present value to us at today's prices, simply astounding. Now just briefly, what have we learned from the Talitha well? And you guys that have listened to Roger Young in the past, you've seen this. We've talked about it. But it was such a great well Michael drilled, an incredible well, with the help of a lot of people, obviously. And we've got incredible data. But this was our pre-drill estimate of that SMD-B zone. Once we had the data from the Talitha-A well and we could tie it in with all of the other wells in the region, this was the new interpretation, net to Pantheon, 2.6 billion barrels of oil in place, 400 million barrels recoverable, with a good portion of all of that developable from the Dalton Highway. Location, location, location. So here's the log of the Alkaid #1 well. The -- you can see that K10 is the top seal. That's the regional top seal. If you've listened to Ed Duncan in the past, he's talked about that a lot. That's our top seal. And that -- above that, we took some samples in the Talitha-A well, no oil. But every sample below that K10 top seal had oil in it in the Talitha-A well. That's where over 400 samples that were done by AHS. And you can just see green is good, guys. Green is the oil, just how thick that oil column is an Alkaid. We perforated a very small interval way down there in that Alkaid deep, zone 6 feet, and it flowed slightly over 100 barrels of oil per day average. And that -- those are the zones that we would develop from the Dalton Highway. And our summer well, spring/summer well will target that Alkaid Deep from a position in the northern part of our Alkaid unit drilled horizontally to the Southwest, and it will target that lower zone. And we will drill it deeper to go all the way through this zone because when this well was terminated early because of a weather event that we're still in the zone. So with that, I'll turn it over to Bob to talk about Talitha.

Hello. Bob Rosenthal, and I'm the Director of Technology for Pantheon. I think we've -- I've met a lot of people who are on this phone call before. And I can tell you, I have not gotten used to Zoom calls because if you've seen me in the past, my arms are waving at all times. So I can tell you that, that's what's going on right now. So look -- before I step into this, I want to make one comment on some of the thoughts that we were talking about previously. The program that we are doing this winter, which is testing Talitha, and we'll get into that in a second, drilling Theta West and going in and drilling the Alkaid development or production well, that is a huge program. That's a massive program. It's -- Jay and everybody has alluded to, we're looking at 17 billion barrels oil in place. We're looking at 2.2 billion barrels of recoverable. Each one of those programs have separate objectives. But at Alkaid, we're looking to move from resource to reserves. That's a major step forward for us as a company. We're looking at Alkaid to get our first production on, a massive step forward for our company. We're looking to prove up at Theta West, our Theta West well, almost 12 billion barrels of oil in place and 1.4 billion barrels of recoverable and test multiple zones here at Talitha. This is probably one of the largest, most impactful programs anywhere in the world. If there's something bigger than this happening, for any company right at the moment, I don't know it. So with that, I think I'll move into a bit more detail of what happened at Talitha and why are we doing what we're doing this winter. So if you remember for the people who have seen a lot of our presentations, at Talitha, we had multiple zone -- we proved up multiple zones with hydrocarbons in it. We've shown that we probably have well over 1 billion barrels of oil potential. The risk profile on our project because of the Talitha well has been significantly de-risked. And every zone, every zone that we predicted that would have oil in it has oil in it, is now behind pipe, and we will be testing multiple zones this winter. I'll go over some of the AHS work in a few minutes in a little bit more detail, but it is an independent validation that we have a significant oil column through this well. So this is just a picture kind of reminding everybody of the relationship between the Talitha well and Theta West. So here, down in this -- so we had oil here at the Kuparuk. We had oil in this zone, which is the Basin Floor Fan. We had a little oil. We had down here in what we call the Upper Basin Floor Fan, we weren't even expecting to encounter this Upper Basin Floor Fan at this location. And then we had oil throughout this whole section through the Slope System and the Shelf Margin Deltaic, 3,700 feet of hydrocarbon column at this well. Oil in all our targets. When we look at the location of Theta West versus Talitha, we are 8.5 miles to the west of Talitha and we're 1,500 feet up-dip. So what did we find in Talitha? We had hydrocarbons in the Kuparuk zone. We had over 600 feet of reservoir section, or the thickness of the Basin Floor Fan was over 600 feet. We had 50% net to gross in the Basin Floor Fan, all of it oil-bearing, all that light oil. At the Slope Fan, we had 2 zones in the Slope System, both oil-bearing with light oil. And in the Shelf Margin Deltaic, we had multiple zones with oil in it. And that -- this zone right here is the B, right there is the B, which we will be testing this winter. Every one of these zones from Shelf Margin Deltaic, Basin Floor Fan, Kuparuk, we had mid-30s to low 40 API oil, light oil throughout this whole section. I think this is an important slide. Again, this is work done by AHS, which is out of Baker Hughes. And this was a volatile analysis that we talk about all the time. We had a special kind of little webinar that -- where we discussed it, but it's good to review this because it was independent work done by the AHS team. They went out, they collected samples while we were drilling, sealed samples at the well. And this little area right here are the sealed samples. These red dash lines that were collected every 20 -- 10 to 20 feet. And below this marker here, which is the K10, we had 416 samples taken and every single one of them recovered light oil, every single one of them. And this work was done completely independent of anything we were doing. On here as well, and I can't -- I'm not going to go through what all these different curves were, but AHS highlighted what they considered the zones, which were the most prospective, and each one of them wind up with the zones that we had predicted either pre-drill were going to be hydrocarbon-bearing or we found through later log analysis that also had hydrocarbons. We had several zones in here that were not predicted as pre-drill having hydrocarbons in it, and post-drill, we found hydrocarbons. So incredibly significant. 3,700 feet is a huge section of hydrocarbons. So moving over to Theta West. As Jay alluded to before, the distance between the Talitha well to the up-dip portion of Theta West is over 17 miles. Talitha was drilled in an extreme down-dip location. We discovered oil in this distal Talitha well and in the Pipeline State well in the Theta West fan. Our Theta West location is 1,500 feet shallower. And because of that shallower depth of burial, we are going to have a superior reservoir quality. So that's a -- this is the outline. Let me do this again. So of course, this is the outline of -- never mind, right, undo. Sorry, folks. The point -- so here's the outline of where Theta West is. It's about 85,000 acres. In there is 12 billion barrels of oil in place and 1.4 billion barrels recovery. And in there, we're only using 11% to 20% recovery factor in that. And the 20% recovery factor is actually in the most shallow part of the Theta West fan, which we call the upper theta west fan. And this is work done by the team at eSeis. That is -- that map there is a seismic attribute map that we use to describe the outline of the lower part of the Theta West fan. And what's incredibly interesting about this is we've got probably 85% to 90% of that on our acreage. And as Jay alluded, in the January lease sale of 2021 after we spudded the well, we picked up about 60,000 acres of that 85,000 acres. We spudded the well, but we had not got the seismic data. So here is Talitha and right in there is the Theta West fan, which had over 600 feet at Theta West proper, right there, we're expecting over 1,300 feet in the Lower Basin Floor Fan with better reservoir of oil-bearing. And we're going to intersect right there, the upper portion of the Theta West fan, which was oil-bearing. In the Talitha well, we're not testing it because the sands were very, very thin there, but we expect well over 100 to 200 feet of sand in that Upper Basin Floor Fan at Theta West. And I'll turn it over to Michael.

Thanks, Bob. Hello from the Arctic. Glad to be up here as always. Right now, I'm sitting at the Talitha location, about 30 miles south of the Arctic Ocean. And so I want to start just giving a lay of the land, and there's a bunch of questions that are always asked. The first question always asked up here is about the weather. And we right now are in the middle of a big heat wave. It is right now about 10 degrees Fahrenheit or 10 degrees below Celsius. This is a welcome change for us because over the past month, we've been dealing with about 40 below temperatures, and that's about 40 below Fahrenheit and 40 below Celsius. So turn on my camera real briefly because the next question that's always asked is what do you wear in that weather. Hello for mission control. What we typically do is we look like firemen out here. So these are insulated bibs. These are my Great Bear logo bibs. It's like wearing a muddy quilt. In a weather like this, we typically wear a sweatshirt outside. When it gets to 40 below, we'll be in huge coats -- or huge coats and look like firemen out there. The fire-resistant variants look -- it's almost analogous to what you see firemen wearing. Liners on everything. Here's my hard hat liner. I didn't know it at the time, but when you buy a tan hard hat liner and you're walking a cross location, you look like you have flowing locks of blonde hair. So it's an interesting bonus, but a pro tip there. So we're bandwidth-limited. I'm going to turn my camera back off, on satellite communications. And so I'll try to be conservative with that. The next question we're always asked up here is about the daylight hours. So January 4 today was a week ago today that we first saw the Sun. So that technically ended a couple of months of night time up here. You see it in the picture here, and everybody always asks, is that Sunrise or is that Sunset? And the answer I give is, yes, that's both Sunrise and Sunset because the sun peaks up over the horizon and disappears. But that's changing very quickly. Every day, we gained about 20 minutes of daylight. Right now, we did about 2.5 hours of daylight, and that's up from 0 hours of daylight a week ago. At 20 minutes a day of gain, a week from now, we'll have 2 more hours of Sunlight, and we'll catch up with the rest of the world here in about 6 weeks. So mid-March, of course, is the equinox, and we'll have 12 hours of Sunlight on that day. Things will continue to move in a hurry, and before long in April, it'll be Sunlight all the time. The pictures you see here are of location this year. We're very excited to have simultaneous operations going. What you see to the left is the Talitha-A location. This is the equipment that will be used to test the well over the coming weeks. So on the left-hand side of the picture, you'll see the testing equipment. People call that flow back elsewhere. You see the tanks and the separation equipment. On the right-hand side, you'll see wireline and frac equipment that will be used over the coming weeks for the test. The picture on the right you saw earlier, this was taken a few days ago. This is the Theta West well. And I'm very excited to have the Nordic 3 out there. Again, that rig is becoming very dear to my heart. And so we welcome that out on the Theta West location. To talk briefly about personnel out here, fortunate to be surrounded by some of the best on the planet. Leading the drilling on the Theta West, we have 2 directional drillers with amazing reputation here in Alaska and also amazing experience, over 50 years of experience between 2 of them. On the Talitha-A location, we have 2 of the best completion engineers on the planet, completion leads on the planet, guys that have worked all up and now in multiple continents with Arctic experience, including Canada and Siberia. So we're very fortunate to have that team up here. Today, we have 80 people on the project in between the 2 locations. And of course, we're out on ice. We do that to protect the tundra. We get the operating window from about January to about mid-April. And of course, when we leave location, the ice [Technical Difficulty].

So it looks like we lost Michael. Hopefully, he can come back in. Hello? I assume I'm on.

You're on, Jay. We've -- they're having comms problems there.

Yes. Right. Okay. So I'll try and fill in for Michael, but I won't be a very good fill in, I promise you. So here is the plan for the flowback, stimulation and flowback of the Basin Floor Fan. So we will perforate in 3 locales, 3 fracture stimulation stages and then we'll -- it will be co-mingled and flowed back, and we will be testing the Basin Floor Fan as one zone. Hopefully, let me just say -- no, I was getting a text. I was hoping that was Michael saying he was coming back in, but it wasn't to be. So this is part of that 600-foot section that Bob mentioned, and we will be reporting on this as we go forward in due time. So you saw that the flowback gear, the frac gear and all is out on location. So that work will be going on imminently. We will then move up the whole to the Slope Fan system where we will independently perforate and frac and test the 2 zones that Bob mentioned. And these were kind of bonus zones as we were drilling the Talitha A well. We had an inkling that they might be there, but they showed up very well on the logs and in the AHS work. So we're going to go in and perforate them and fracture, stimulate and co-mingle that production as well, 2 zones. The primary zone of interest and the primary zone of interest when we drilled Talitha A is the Shelf Margin Deltaic. At Shelf Margin Deltaic B, that's nice well-developed sand that you see in that upper portion of that log. So we will perforate. We will do one single fracture stimulation, about 150,000 pounds of sand total. That is a relatively small fracture stimulation, but we're not opening up a lot of the zone. We're opening up only a small portion of the zone. And as we've repeated over and over, we are trying to prove movability of the oil. We want to get data on the actual reservoir characteristics. That's what we're looking for more than flow rate. So vertical wells will give us that data. Ultimately, when we are developing any of these reservoirs, we will drill horizontal, long horizontals with multistage fractures. Is Michael back on? Yes, Michael, you're back on?

Hello, Jay.

Sorry, mate. I took over for you. Do you want to give them a quick overview...

Yes, please. I was talking for a little bit -- so did you get any...

Go ahead, mate.

Jay? Can you guys hear me?

Yes, you're on, Michael. Take over.

Should I start back introduction and location?

Yes, Michael, start from where you are...

So looking at the Basin Floor Fan, we intend to communicate with formation through 3 different stimulation stages. This is a 600-foot interval that we're trying to interact with. And it's most predominantly in the green on the right showing the [indiscernible] that we're after. And so what we'll do is we'll be in a fracture stimulation on the bottom zone indicated by the red triangle. We'll come up from that. We'll set a plug and we'll move up and repeat the process. And then we'll do that a third time to try to open up 600 feet of reservoir. Once the stimulation is done, we'll drill out all 3 plugs and co-mingle production of the 3 stages and test this in one flow test. We do not intend to test the upper Basin Floor Fan on Talitha well because the more appropriate test locations [indiscernible] Theta West. So the next 2 zones we'll be testing are the Slope Fans shown here. We'll once again perforate and communicate with the reservoirs through fracture stimulation and the red intervals here indicates where we plan to place such stimulations. The intent of this one isn't necessarily to maximize vertical contact because we believe that the same packages will be communicated to appropriately through fracture. So the intent of this one is to make sure we have good connection to each formation, to make sure we begin to interact with them. We understand how fluid moves in both directions, both through stimulation and through production. Third interval -- the third test, fourth interval Zone 4, of course, is the Shelf Margin Deltaic. And in this case, we intend to hit the sweet spot of the formation as shown here once again by the red triangle. This has hit the meat of it and see what it does. So we're very excited for this one because it's a -- it will be a nice production test and we're looking for good flow rates and an appropriate fracture for it. I wanted to speak a little bit about how fractures work and what they really look like. When you say you're breaking rock, it's easy to envision a pane of glass breaking where things bust. When you're 1.5 miles to 2 miles below ground, rock is surprisingly squishy. And so it doesn't break in the sense that is easy to envision. What happens more so is it splits -- it -- like a tear, we call it a bi-winged fracture because it reaches out in both directions. You establish a dominant fracture split that reaches out. And so they look like wings, going to both sides and they are vertical and they're thin. So on the left-hand side here, what you see is the result of a [indiscernible] frac model that we are for stimulation, we're putting on the base of Floor Fan. And as shown in this, we expect about 200 feet of vertical conductivity from the frac. We think it will reach out -- as the split grows, we believe it will grow 200 feet from top to bottom. Each wing, we believe will reach out about 200 feet. And so that fracture, that split, that wing that opens up, ends up about 200 feet from top to bottom, and this one will be about 200 feet in distance and about 1/4 of an inch thick. And so we feel that, that split. We feel that it's not truly a void because it's got fluid in it but the fluid has sand. And so we feel that split with a sand, a proppant, and that proppant keeps the split open and allows the medium for fluid to flow back through. So the picture on the right is to depict how that will be applied to this well. In the Basin Floor Fan with 600 feet of [indiscernible] contact, we'll pump 3 of these to make sure we have good connection from the top to bottom. As we move up hole the sand reservoirs are thinner. And so we'll split a frac, we'll pump a smaller amount in each one because we don't expect the vertical height growth. So we need less stimulation in the sand [indiscernible] there. In the Shelf Margin Deltaic, we have 100 feet of nice pay that we're targeting. And so we expect one frac should be able to contact the reservoir to the extent from top to bottom and we're looking forward to a good design to get stimulation on that one. And as I said before, that's a wonderful flow test opportunity. With the question of how we're going to treat this also comes the question of what are the expectations? What are we looking to accomplish? What are we going to use this benchmark for success? So looking at the Basin Floor Fan, as Bob discussed, we're very excited about the Theta West drill because it's much more updip and we expect better reservoir quality. So in this location on the Talitha well when we look to interact with the Basin Floor Fan, the benchmark we're looking for is high-quality movable oil. We expect an API range between 35 and 42 API oil. We've produced that from the Alkaid well and expect it to be a beautiful light, sweet crude. The viscosity of it is probably going to be less than water. And so it's a very thin oil, which makes for amazing mobility. So right now in the Basin Floor Fan, the goal is really does the oil move and how good is it? A similar benchmark for success will be used in the slope system. These reservoirs will be the first we've interacted with them. We expect oil quality to be the same, it's the same source and reasonably similar depth. So a nice light sweet crude is anticipated. But in the case of the subsystem, we're going to learn a lot about the reservoirs we interact with it. So once again, we're using movable oil as the benchmark, but we look to learn a lot about these sands as we complete them. Further step hole and the last to be stimulated and tested in this well is the Shelf Margin Deltaic. This one, we have some analogs to go with. On a [ poor perm regime ], it's similar to the Alkaid #1, which we have tested in the past. As such, we're looking for flow rate in this well. If we stimulate this properly and the operations side goes as planned, we're looking for a flow rate between 50 and 80 barrels of oil a day of IP from this vertical completion and a single-stage stimulation. So very much looking forward to the [ floating rate ] on that zone. If there's one point that I'd like to get across today, this is it. We come out here on the Tundra in the winter. We have to do this on ice to protect the Tundra. And we get a small season. We have 3 months before we have to be completely out of here. In those 3 months, we drilled a vertical well to evaluate the rock and we have time to stimulate it and flow test it. But in this vertical well, we have room for one fracture stimulation, the Shelf Margin Deltaic. And we're hoping for a flow rate from that single stage stimulation of 50 to 80 barrels of oil per day. Put in a development scenario, we'll be developing from gravel pads that [indiscernible] melt out from [indiscernible] and we'll have time and availability to do the well that we would appropriately placed for the formation. In this case, we plant 10,000 foot or approximately 2-mile horizontals. That's a very common place in Alaska. A 2-mile horizontal is not viewed as a long lateral here. It's a very reasonable lateral in the place all the time, but in that 10,000 foot of a development horizontal, there's room for 30 to 40 of these completion stages. And so that's the real excitement I have for this project, the real excitement of the upside of features. In the Talitha A, we pump one stimulation to one stage and we're looking for 50 to 80 barrels of oil a day from that, but then in development, we're going to multiply that by 30 or 40 and we're going to look for amazing reservoir contact. And so the scalability of this is very, very exciting. When we look at our development model, we're using very conservative numbers, but we're expecting 1,350 barrels of oil a day from this 2-mile horizontal. And that gives the amazingly robust economics that Jay spoke to earlier. So the scalability of this project is really what I want to convey today. We're out here on ice. We've got limited time. We've got a vertical well in one stimulation. But for development, the upside of this is truly extraordinary. There's not just scalability in the Talitha of going from vertical to horizontal, going from 1 frac stage to 40. There's also an amazing aerial extent. And so when we look at the size of this prize, we're talking 400 wells just in the Shelf Margin Deltaic. And so that's truly the purpose why we're out here is what is 1 fracture stage do. And then we'll look to see what this can do and we'll multiply it by 40. This has spoken of a little earlier, but when we look at it, what would be considered a step-out well, we're going [ 10.5 ] miles over to really get into the -- a nice section of the Basin Floor Fan. This is a cartoon meant to depict the shallower, thicker and better reservoir, and we're very excited to test the Basin Floor Fan in the Theta West well. Here, I show more fracs, I show 4 fractured stimulations. Once we've got a proper log and we can do our full design, we'll know what that real number is, but the concept of it's up dip, it's thicker and it's better reservoir. It's very exciting. All the concepts that we learn on Talitha will be applied to the Theta West well. So going back to the concept of what does one stage mean and what does the future look like? I want to look at the Alkaid well, for an example. So in 2019, we tested the Alkaid well from a single frac stage and it flowed 108 barrels of oil, and it was that beautiful light, sweet crude. [ 35 API oil ] was tested there. For development on the Alkaid, we'll use these horizontal multistage. And once again, that will be 30 to 40 stages. We look to place stages 250 feet apart or 4 stimulation stages in 1,000 feet of horizontals. So this summer when we come out, we'll be working on a gravel pad, we will not be time constrained. We'll be able to drill a horizontal multistage well that we seek. This will be our first horizontal well in the Alkaid. And so drilling parameters will dictate how long the horizontal will be for that one. We want to make sure we place one appropriately. We want to make sure we do it reliably. And then we'll stimulate it and flow test it to show what this concept can be. So using that as a benchmark, we seek to get 100 to 150 barrels of oil a day for each 1,000 foot of horizontal. And I hope to really showcase that scalability. If a single frac stage on the Alkaid flowed 100 barrels of oil per day, 108 technically, we seek to get 100 to 150 out of 1,000-foot of horizontal and that would really provide robust economics. And what that means depending on the lateral length for the Alkaid. If we're able to place a 30,000-foot horizontal for our first one, we'd seek 300 to 450 barrels of oil a day production from that horizontal. If we complete 5,000 feet or approximately a mile of horizontal, we'd seek 500 to 750 barrels of oil a day production from that. And then as we get closer to our true development length of the 8,000 or 10,000 foot, in this case, we show the numbers for 8,000. But if we place an 8,000-foot horizontal and properly stimulate it, we would look for 800 to 1,200 barrels of oil a day production from that horizontal well. And so it's very exciting to be able to look at this and say that in the Alkaid , one zone produced 108 barrels of oil a day, one fractured stimulation. In this summer, we're going to have a wonderful opportunity to work off of a gravel pad to not be seasonally limited to have the time we need to reach out with the development style horizontal and completed multistage fractures. And so it's going to be a wonderful project this summer. We're very much looking forward to the flow rates from this, but the excitement is -- it's overwhelming. It's -- very excited for the opportunity to show how one stage of production translates when you multiply it by 40. When we look at development, there's another opportunity we seek to advance here in Alaska. We look to take what's currently happening in Alaska and move it one step further. It's a unique situation here because we have oil takeaway capacity, but we have no natural gas takeaway capacity in Alaska. So what is done right now in development is the natural gas is brought to surface with the oil, and it's used for power generation. And there's always been excess gas through this cycle here in the North Slope in the order of [ trillion cubic feet ] You have this amazing source of natural gas. This is amazing for the purposes of development, an exhaustible source of energy of natural gas. And here on the North Slope, that's burn to create electricity. And then the excess natural gas is put right back in the formation. We intend to go one step further. We intend to duplicate the common methods of the North Slope where natural gas has brought to surface. It's used for power generation and then we can run a lot of our facilities on electricity. But the step for that we seek to take is we look to take the exhaust from that natural gas power generation and combine it back with the excess natural gas and put it right back in the formation. It's just one step further, but it's an elegant solution towards carbon capture -- towards carbon mitigation. The material, the hydrocarbons that come out of the ground will be used for power generation, but the carbon will be put right back in formation. And so it's really exciting to go one step further to look at the future development and apply this concept, and we're able to do it because of the opportunities in Alaska because of the unique situation of abundant energy and no natural gas takeaway and because we're starting today with the new facility. So whereas others would have to retrofit these capabilities, we're starting from design one. And so this is the concept we seek to prove up in development. We're very excited for the potential of emission-free energy source for our operations. So with that, I will pass it back.

Thank you, Michael. So now we'll go into the Q&A. So Justin, I think you're kind of leading the Q&A.

So thank you, Jay. Look, while we're on the topic of -- thank you. So there's a very important guest I need to think and it's Mr. [indiscernible], who again has excelled himself in producing what seems to 3,000 questions elegantly curated. So I've tried to group these into a relevant topic, sort of into a couple of groups, key risks, farm-out discussions, exit strategy, independent valuation, some specific questions on the individual wells. Question of whether we would contemplate a foreign listing perhaps in the U.S. and also upside potential to the kind of key categories. And what I might do is launch straight into it without further ado, and kick off with the sort of general discussion, I guess, on what we see as being the biggest risks to our program going forward and indeed to the company going forward. Bob, you're probably the man to be answering this one initially?

Well, I think for -- if we look at the technical side, again, what we're trying to prove is reservoir deliverability. I think Michael has elegantly showed how we can scale up and take all the information. But I think that's our critical risk is how do these reservoirs perform. And of course, in terms of commerciality, it's -- I think Jay showed a wonderful slide of how that's affected by oil price as well. So we're looking -- I think we've proven everything we can, and it's now reservoir performance and then applying the technology for getting the oil in the ground and showing we can do that in a commercial way.

And Bob, just on that point, we do have a large amount of retail investors who don't have the specialist oil and gas knowledge that perhaps things that we might take for granted. There is a real fixation on the absolute flow rate numbers from our testing, certainly from the investor's point of view. Michael did a great job of just explaining that a few moments ago in terms of. Can you just give a bit more color on that, the concept here of getting data from a vertical well test and modeling into that, what it might mean into a horizontal well?

Sure. I mean, I think, again, Michael showed that really well. What we're trying to do -- remember, we opened up a 6-foot zone at Alkaid, with 100 feet of -- sorry, about 100 barrels a day of production. We then move to the next step of taking all that data. And that's just not taking the flow rate. What we -- what Michael also alluded to is we're getting information at when we're injecting into the well, about the reservoir quality, the effective permeabilities and things like that. We can take that data and then model how a horizontal well would perform. So we're collecting that data in real time, let's say, at Talitha when we're testing there and we can then use that data to go to Theta West and test Theta West, update our model for how we tested Theta West, get our results and then go in and model the next step, which is how a horizontal well performs. But to move from resource to reserve, to move from resource to reserve, you do have to show that you can put on your horizontal well and how that well will perform. So you actually have to show it, which is what we're doing this spring, summer at Alkaid. We're in a unique position to do that. We keep going over this. We're in a unique position to do that. We can actually move from resource to reserve because we can actually drill the horizontal well. And even if we get, let's say, 3,000 feet of horizontal [ or fourth out ] we can actually scale that up and engineering firms will move your resource to reserves. No one else can do that. So people to the west of us who are talking about building a huge infrastructure out in the NPR, Willows and all that kind of stuff, they have to build the infrastructure, have to put that well on long-term production and then you'll move all that. We can do that this summer.

And Bob, I guess, just leading on from that, on this concept of risk. I guess the fact that we've already found the oil in Alkaid, the well has flow-tested previously Alkaid #1 has flow tested. In the case of Talitha, we have the AHS Baker Hughes samples the whole way through. We have logs in that will. We are not going to a wild cap. We have drilled that well already and logged it. It moves us significantly further forward in that probability of success.

Correct.

And the final point, Bob... Sorry, Bob.

You said the final point. What was...

Sorry. I'm sorry, moving on. in this concept of risk, not only is the geological risk, but there's also investment risk. One [ lessens ] the other in this case, but people on this call are equity investors and they're assessing the risk of an investment in Pantheon Resources, whether it's undervalued or overvalued as the case may be. And one of the things that we've brought to bear in our recent fundraising is we've driven that risk down by raising sufficient funding to give us this sort of portfolio diversification. We have Alkaid well funded, we have a Theta West well funded, we have Talitha well funded. With these multiple independent zones across those 3 wells, how does that play for you as a technical director?

It's massive where we were on sort of November 30 versus December 30, you're a world apart the. To have a -- nothing has changed geologically between November 30 and December 30. But our risk profile in terms of execution has just been enhanced significantly because we can actually go out and do the work at Talitha, Theta West and at Alkaid all in one season, right? It's not -- you're not testing Talitha this winter and saying I'm going to drill Theta West next winter. You're in real-time testing Talitha, drilling Theta West, taking the information you have at Talitha and applying it to the Theta West. And as I said, we're having the money to go out and prove that you can drill your horizontal well and put it on long-term production and move from resource to reserve. And you're doing this from we tested the well in 2019, and we'll have our first production in 2022. There are huge companies to the west of us. There's ConocoPhillips. There's the Repsol and Oil Search. We know it's been bought out by Santos. But if you go out to the NPR, we will be on our first production well this year. And again, having the funds to do that significantly and having to the ability to do multiple things in one year significantly reduces the risk for the project.

Reduced, obviously, the impacts of volatility too. Look, that's great. I'm about to ask Jay question here on the next topic being that of the farmout. By way of introduction, we've spoken a lot about farm-outs over the last year. We were actively in discussions with a number of parties particularly one, and I think the whole Board would be fair in saying that perhaps in November, we thought that that's the way we may have been going. We were very, very late stages. And ultimately, often, we've been running a dual strategy and opted to go with the other strategy of the financing that we did. But can we just discuss that farm-out? I mean, firstly, is it something we'd be open to again in the future, if a farm-out came along, would be open to that? And the second question linked to it, Jay, is -- would the terms have changed from what we would have been discussing beforehand? Jay?

Well, I'm going to answer the second part of that first. And we've had -- we're still in discussion with the management group that we were in discussion with back in November. And just recently, we've had continuing discussions and firmly believe had we wanted to, we could have signed a heads of terms with with the terms similar to the ones we had been discussing in November before the financing people change the terms right at the end. So yes, we are still considering a farm-out. Those terms are on the table, but we have chosen to see what we have. We're all very confident of what we have. And obviously, with success farm-out turns for us would improve. Now we will continue to look at a farm-out going forward for several reasons. One, I can bring in some technical personnel that will help our team. That's very good. Two, as Michael said, that the belief of development is plus or minus 400 wells. And if we are not bought out in the future and we choose to -- and we must be prepared to go forward and develop these, it's going to take a huge amount of capital, a huge amount of capital and a farm in -- farm-out would help us do that. And thirdly, one of the things we were looking at on the original farm-out is they were planning to go to publicly list and that would give us an option of potentially merging with a company that was mirrored us regardless of what the percentages were and we could merge in and answer one of the other questions and end up with a listing on one of the other international exchanges. Yes, we'd be excited about...

Yes. Can I ask something to that, Justin?

Of course.

Yes. I think this is a question that bounces around farm out what's next, how are you going to move forward? And I think kind of my view on this is step one is we're drilling these wells. We've got to collect all the data. We have to analyze all this -- analyze the data as it's coming in, which will take some time to do that. In other words, it's just not, hey, you drill a well and okay, you start your farm-out or you sell your asset or something like that. You have -- there's a lot of work involved with it. And I think Jay alluded to it, if you're going to get a new or a good farm-out deal or execute something where somebody comes in and maybe buys the asset or something like that, we have to be prepared to execute the work program ourselves, whether the work program is drill these wells and test them or be prepared to even develop the field. We have to have all that work done so we can have people who are going to come in and maybe look at us or come in and do a farm-out, they have a data set that is complete and totally analyzed to make their assessment because a farm-out now is going to look different than a farm-out last year, totally, totally different once we've drilled these wells. So I just want to make that really clear that it's important that we are prepared to execute ourselves.

Look, Bob, thank you for that. And I think two things to talk about with this farm-out. One is, Jay mentioned that we were discussing in November, we're having discussion just for the avoidance of doubt, this particular group that Jay was referring to, we've been in discussions since I would think June or July with that group all the way through, in fact, to just before our recent fundraising. So that's point one. Point two, the size and scale. They were very, very significant numbers. We were talking about a structured farm-in, where they would earn an initial stake and then spend additional funds to move to a larger stake and then as a 3-phase to move to a larger stake, again, still minority stake relative to Pantheon, but the numbers were very, very significant indeed and larger than our market cap of the company is today, the entire market cap. The other thing I wanted to mention was that with the farm-out, many of our shareholders feel confident by brand name. I've had many conversations with people thinking that perhaps we had one of the majors as a partner. That would be a great vote of confidence. Well, it may be, but it's like a marriage. We've got to think of this about the long-term future with that other partner. So and for that, you need to have a partner that has similar aspirations, I guess, as yourself. So signing up with a major if we had success, for example, in the Theta West well, we'd face a very, very nervous period where they most likely be trying to squeeze us out of this play by proposing a very active drilling program that we couldn't keep up with to dilute us out. And similarly, we don't want to be exposed to a company where they may -- we may be exposed to portfolio risk within that company's portfolio. They've got environmental issues somewhere else or with all the ESG things that are going on, they decide to pull back, and we find ourselves on mothballs with nothing happening because we've got a joint venture partner that can't fund its way. So it's very important to find the right partner that has a similar aspiration for this product for these projects. We wanted a partner that wanted to move at the pace that we wanted to move at, which is fast. So it's more than just the financial terms. The financial terms were very, very attractive. But it's the devil is in the detail, and there's lots and lots of finer detail below those in terms that need to be coordinated and agreed and things like committees, decisions, all of those kinds of things.

Just one other quick thing. With a major, the [indiscernible] control 51%. So you would immediately look era with major.

Exactly.

Great point. Thank you. Yes, great point. Look, a bunch of questions on independent verification validation. Would we get third-party engineering reports some larger brand name firms? And if so, when would that occur? Jay, do you want to comment on that?

Well, Bob, you can do it as well, but I'll turn it over to you, Bob. You've been the main man working with the...

First of all, yes, I think what we're -- like I said, first of all, we've got to collect the data, and we have to do the analysis ourselves. You don't walk in for an independent expert report where you haven't done the work yourself. So we've got to collect that data and do that work, which first pass done probably this summer, Alkaid. The Alkaid, obviously, we're going to be testing. It's going to be a long-term production test. That's what they're looking for at Alkaid. So that's going to take time. So start this year, finish in 2023. Definitely going to do it on each reservoir, but it's going to take time.

Thank you, Bob. Look, the question for our special guest Roger in the background, if he's still there. Roger has featured in our previous webinars and to any of those listeners who haven't dialed into any of those, I thoroughly recommend it. They are quite detailed, but they're very, very important to getting a grip on the fundamental story here. Roger, the founder of eSeis and of course, a key architect in the discovery of this Alpine field, the third largest field in Alaska. Roger, last time you spoke about -- a question was posed to you, in fact, in the Q&A section, and the question that was asked was has the project evolved since the Talitha A discovery in that sort of 6 months or longer period between those 2 events. And you gave us -- your answer, I think, was something on the lines of it keeps on getting better and better and good projects get better. Roger, do you have any more -- have you done any more work? Or is there anything more that you could add to that or perhaps your feeling remains the same. Is there any feedback you have at all?

Well, boy, that does keep on getting better, of course. It's exploring for oil and gas is like exploring for treasure using science as your tool. And as you continue on, you continue learning more little bits and pieces of how to put this puzzle together. And in some projects, those little bits and pieces are negative and they don't make the project better and ultimately make kill a project. But in this particular project, the bits and pieces as they come together, just make it make it even better. And like Jay said, the good ones get better, and that is what continues to happen on this one as all the little pieces of information have come in over the months. So the trend is still continuing that way, and it's -- it keeps me up at night because it's just so exciting.

Roger, thanks for the feedback. As always, Bob, a quick specific question moving on to the projects. The first, not by all that we're drilling them, but the first is on Alkaid, obviously, very important to us in an $87 oil world. I think Jay mentioned earlier on in the presentation that when we did a fundraising back in 2020, we were in a $43 oil world. And we didn't really speak about Alkaid much because the NPVs were just quite unremarkable. But today, they're quite the opposite of that, they're phenomenally large. Bob, you touched upon it before, but I'd like you to just embellish it a little bit more if you can. And that was that back when that well was drilled, the well drilling was terminated early under the direction of the DNR because there'd been a flooding of the highway, in fact. What does that mean? Because you said there's no oil water contact. Can you explain what that means and why you think perhaps what I'm leading is that there's potential additional upside deeper down in the Alkaid field.

Well, I move back to a slide that's up. I'm not sure if everybody can see it. I think that's a there's-- which was Slide 13. So I move back to that slide.

We can see it, Bob.

And if you look at the -- and here you go with my tools and everybody can have a good chuckle where we TD the well right there. we were in oil. So all of this is oil. And we TD the well right there in oil. And we've got another 400 or 500 feet section below the base there, which we haven't tested, which when we drill our well at Alkaid, the horizontal well, we're going to drill a vertical well and try to drill and log the section below the base here. So going down another 400 feet we hope to and get log through that. So there's huge potential still below that. So we can -- the scale can increase from that. But One of the big changes over the months, and Roger's alluded to it, things get better is, again, hooking up this SMD section all the way over to Talitha. And that's -- we now have that in the well at Alkaid field. And this is all oil bearing through here. It's just that the reservoir has a lower net-to-gross through that zone through there. So there's kind of -- there's real potential for the scale of the Alkaid project to go up significantly below the Alkaid anomaly and associated with the SMD [indiscernible].

Well, I've got a question -- I've got a couple of questions coming in live. You might hear my phone pinging, but [indiscernible] answer those first, I've got one for you and second, Michael. The first is on getting back to the concept of a farm-out, people are interested in what type of structure we were looking at and what sort of commercial terms. Look, obviously, very rapidly, we can't talk commercial terms. And obviously, we chose not to go the farm-out route in the end. So to some extent, the discussion is [ moved ]. However, what I would say is that structurally, we're working on a structure where the party would earn a very small percentage working interest, and that would have the opportunity by spending significantly larger investments to gross that up over 3 stages to what would have been a 10-digit investment in our company for quite a modest percentage. So that's the type of structure we're working on. Those terms are no longer relevant. Arguably, the terms have gone up. There's lot of macro discussion. It's not for us to predict oil prices, but there's a lot of macro discussion at the moment about this underinvestment in upstream oil and gas, possibly leading to supply shortages. So as long as we have a stronger oil price, we think that will be supportive for us. But I just want to quickly divert to Michael, if I may, Michael because I know you've got some things to do on location. You've got ahead, I think, from Talitha over to Theta West shortly. Question from a few investors in different -- sort of expressed in different ways has been how does testing work sequentially? And I think this concept of testing from deepest to shallowest. Could you explain how that works and why we would seek to test for the deepest to shallowest?

Sure. That's a great one. And to give a scale, of course, we're testing from 1.5 miles to 2 miles. And the problem is if you go in with shaped charges with explosives and you fire an explosive on an electric cable once it's 2 miles deep or whatever is the depth you want and it punches holes in the case in the pipe. And of course, the problem is if you start at the top and shoot a hole in the top, then when you go to work to the bottom, you've got holes in your pipe above you. So that's why you always start at the bottom as you go in and you shoot holes at the top. And then when you're done, you plug that interval and now you have clean pipe from top to the plug. And then you can go up with clean pipe. So start from the bottom to the top, so that you always have good clean pipe connecting the surface to your formation

That's great. Thanks, Michael. Look, another topic is this 1 of exit strategy. We as a company have been quite open in saying that we're happy to prove this up and sell on to a larger group. We've also often referred to as being kind of like a private equity story that happens to be listed in the public markets. We're not afraid to prove this up, provided the valuation is right. We will consider offers and potentially sell it to a larger group that can fund this thing forward and make a rate of return. But as I think the management team have also indicated we're prepared to drill this in the meantime, if that doesn't present itself as an option or if in fact, the terms aren't right. Jay, you've got decades of experience in the sector. Is there any comments you'd like to talk about in terms of this M&A concept and what we're seeing as a macro theme at the moment in terms of the other E&P companies in some instances shying away from committing to new projects?

Well, I think I think kind of -- a little bit of it goes back to my opening in terms of location. So I think when people would look at us initially, they might say, "Oh, Alaska, I mean goodness gracious. Look at all the problems ConocoPhillips has had at Willow. But if they take a closer inspection and they say, "We're on state lands, we're not in terribly environmentally sensitive areas. We're pretty far away for most of the native hunting areas and those sorts of things, and that doesn't mean we're completely environmental free, but we don't have any significant issues, I think we passed that hurdle. I think with Michael -- what Michael showed about being carbon neutral and wanting to do that and doing that from the very beginning is very positive. And I think that gives us 2 thumbs up with a lot of companies. Now obviously, there are huge headwinds for resource companies overall throughout the world. When you think about energy transitions and what has happened in the past, big energy transitions have taken place over about 100 years. And those happened because there was a more efficient way of providing energy. Now people are asking us to go to a more -- a hugely less efficient way of providing energy from the most efficient source we know of today, which is crude oil to ones that are much less efficient, wind and solar photovoltaics and do that over a few tens of years. It's going to be -- that would be very difficult. And I think those are going to give us tailwinds in terms of crude oil price. So I think we are going to look assuming success, the way we think we have success give us a huge tailwind for that. But as Bob said, we have to be ready to develop them on our own. We've got to be prepared to do that if someone doesn't offer a price that we think is reasonable.

Would that segue usefully into the next -- sorry, go ahead.

So I was going to say, look, I've been involved on both sides of buying properties and selling them. And the best way -- the only way that happens in terms of somebody coming in and buying is you have to show you can execute. You just have to have that. You have to have the data. You have to have it all together if you want to get a proper valuation, which means you have to show you can execute and develop this. So that's -- to me, that's always the bottom line.

Okay. Look, just Bob, just hang there and Jay, this segues into a really important point. And that is, if we enjoy even moderate success this winter, what does drilling look like in 2023? How do we fund it? How active will we be? Those kinds of things? Because as you mentioned, we want to keep moving ahead at pace. We've got some good sort of contacts in place once we certainly, our debt provider has indicated a desire to be able to invest further should we have this I think it will open up the equity markets further for us? Coming into production will open up a much larger community of institutional support. And of course, then there's this concept of perhaps considering a listing in the U.S. market. So just I guess to begin with, if we can just -- a few things to digest there, but what does it really looks like next year, Bob?

Well, I think we're -- first of all, we don't plan to not be drilling next year. So our plan is to be drilling next winter. Of course, drilling at Theta-West Well, appraisal well, drilling an Alkaid, another Alkaid well and possibly drilling a long-term production test in the Shelf Margin Deltaic. So another busy season. At the same time, if we have success at Alkaid, we want to put together a development plan for Alkaid. So again, very active.

And Bob, I'm not sure we actually answered the question before. We may have bounced off topic, but an expert report. So if we enjoyed a lot of success this season and we finish our internal work, engage an expert report, would that help process of either funding bringing in farming partners? But all would you just [indiscernible] more rapid drilling?

I think for farming partners, that's an excellent question. If you're at a large -- if you're talking to a medium-sized company to large-scale companies, they -- and I've been involved with both and obviously, very small companies, we took independent expert report and put them on the shelf and never looked at them. We did our own evaluation, which was why it was important to have your own -- the person who is selling have their own work done because that's what their -- that's what you come in and assess and you actually come in and do your own evaluation. For small people, for funds or something like that, the independent expert's report is obviously going to be hugely important. So -- but again, we have to have that work -- have our own work done and that independent expert's report can't be in our hands until 2023. Sorry, was there a part 2 to that, Justin? Sorry, was there a part 2 to that question?

I don't know, have we lost Justin? Justin. Oh, there you are. coming back on.

Sorry. Operator, [indiscernible], I apologize if I happened to be on mute. Look, there is a part 2 that comes out of this question of funding. And just before I pass over, Bob, one of the questions linked to that is would we consider a U.S. listing and access pools of capital over there? And the answer is yes, we would. We're observing another few companies that are taking on OTC listing, that's something we're looking at as well. We'll observe those closely, so we can't make any commitments. We'll make -- we'll watch them very closely and make a decision if we think it makes sense and it's the right thing to do for our company. Again, just very rapidly, having just been through the fundraising process and my background, I'm very experienced with all those kinds of things, the institutional community is kind of bifurcated at the moment and for preproduction companies versus companies in production. And so bringing Alkaid into production and proving that production capability opens up a much larger universe of institutions. We have a series of meetings with one of the largest institutional investors in the world, household brand name. And [indiscernible] closely and -- but we need to be in that position of being in production. So really important number of months ahead of us. Look, a specific question for Michael, if I may. And Michael, it's just a general question about how does it work with crews? You've got 2 different locations. You've got Theta West, you've got Talitha at the moment. You mentioned, I think, earlier on, there's about 80 crew at any point in time. Do they rotate off? Where do they sleep? How does all that work?

That's a great question. For each job here on the project, there's 4 people that fill that role. There's a day person, there's a night person. And then after 2 weeks, we'll rotate out and bring in the new day person and new night person. So most people run rotations of 2 on and 2 off. So each job has 4 people to fill it. As far as lodging, for the most part, we set up a [indiscernible] out here. We have the Talitha location, we have a small camp with about 11 beds. On the Tetha West location is our main camp. And so there, we bring in full catering, great food, actually last night was spectacular dinner. So we eat well, but it's a small camp. And if you think about a single-wide or double-wide, these are [indiscernible] or there's 20 units that fit together, so we do have lodging here. For some services, we do commute [indiscernible], we're fortunate with our location that it's only an hour drive or 1.5 hours drive from town, but for critical personnel and equipment, everybody lives on location.

That's great. Thanks, Michael. Thank you very much for that. Look, just we're getting towards the end of the question, a couple of specific ones, if I may. There's question has come up on the Kuparuk. Jay, you touched upon it. We had some issues and there were some challenges in the Kuparuk last time. Do you want to touch upon what should I think you'll [indiscernible] on there Bob on thinking of the Kuparuk the moment. Why are we not doing the Kuparuk testing in Talitha? And why have we decided to make it the focus of a future well?

Well, I think it's

Go ahead, go ahead, Bob.

What I was going to say is we know we had problems in the Kuparuk. We know there was -- we think we understand what they are to try to address them in this well in this wellbore would be very difficult. We've got -- as Michael has shown, we've got 4 other zones to test this winter. And to try to address it in this well would be -- we would have to drop 1 or 2 of the other zones in terms of testing. And it's just -- it's a decision I think, which -- I think it was a very simple decision that we just plug this zone and get up and test these other zones and focus on the Kuparuk in another well.

Jay, you -- sorry, Bob, you mentioned to me actually a really valid point, which I think certainly resonated with me. And that was that the Talitha was located with the Shelf Margin Deltaic, the SMD being the primary target. Because we test from deepest to shallowest and SMD is the shallowest. It's the last -- the most important horizon will be the last horizon that we test. And a week lost staffing around deeper down is a week lost on that cannibalized out of that testing regime. So that's obviously very, very important.

Totally. And again, it is -- it's always difficult when you have a problem in a well to sort it out in the wellbore and go back and sort it out in the wellbore. It just takes -- it takes time to be done, but it takes time to do it. We've got 2 billion barrels of oil sitting above us to be tested. That's a huge amount of oil to be tested and get information about and not to compromise that this winter would be a management failure.

Well, 1 -- just 1 real quick point, Bob, and Justin that, had we chosen to test the Kuparuk? Remember, it was an overpressured formation. So that changes your entire fluid regime that you have to have in the hole. And that -- as I said, it's time and it's money. And you may not get the result anyway. So it was just a really simple decision to say, we're not doing it here. We'll do it elsewhere. We think we know what the issues are, and we'll address them in a separate well to drill for the Kuparuk at a better location.

Yes. Well, Jay, thank you, guys. Look, I'm conscious with 1 hour 45 minutes in. I think in previous webinars, we've done a bit of a roundtable at the end for anybody to have any passing comments or if any of the team think we've missed anything in particular, I think it's probably time to move to that phase right now. If there's any other questions, I'm going to hope we've addressed most of them. I hope people do understand that there's certain things we just can't answer there, some very, very specific questions to do with one of our major shareholders that have been selling. We're not at liberty to discuss what their strategy is. Although we would note in brackets that most of that stock appears to have gone. But also some questions specifically on testing data would be looking for precise flow rates, recovery factors and those kinds of things. I think we've given some good shape on that. Jay, did you have is -- actually, why don't I finish up with you, Jay, is the MD. Bob, before I pass on to Michael, and I think I'll bring on Roger as well. Could you have any comments, Bob, that you wanted to reflect on to the team -- to the audience before we go?

It's the [indiscernible], which is a massive program. What we're trying to achieve this winter and into the summer is huge. We're a tiny company with 100% of these projects. We're looking at world-class resource in reserve potential. And because we have 100%, all our options are still open to us. So it's where we were in November of 30th, and today, it's just -- it's a different world, totally, totally different world.

Yes. Thanks, Bob. I think I'll kick over to Michael now and Michael's got to head off and do something on location. So Michael, did you have any final comments that you wanted to pass on to the audience before we release you for your duties?

Just gratitude. It's good to be part of this on both sides. It's good to be in this audience with this crowd but also this is really a wonderful opportunity and the personnel location of top notch. We're really out here with some of the best operators on the planet, some of the best leaders, some of the best workers. And so a real thanks to everybody for making this come together. And it's a wonderful privilege to be up here with such great people on such a cool project.

Justin, did you want me to...

Justin?

Sorry, Jay. Look, Michael, thank you so much, actually for your time. I know you're incredibly busy out there. We've really, really enjoyed having the access to you live from location. And I must say, I've heard some great feedback from shareholders on some of the photographs and the little videos that have been coming from location. So we keep them coming. We've really enjoyed them. But thank you very, very much indeed. Quickly moving to Roger, and then I'm going to pass back to you, Jay. Roger, you've been very quiet -- apologies for that. You're probably the #1 of the fan favorites. But is there any anything that we've missed today or anything that you wanted to reflect to the audience about how the project is shaping up for you?

It's all going according to plan. I don't have anything additional to say than I feel privileged to be part of the team. It's a tremendous opportunity. So thank you to everybody.

Great. Thank you, Roger, for your involvement. You've added a huge amount, and we're very grateful to have you as part of the team. Before I pass on to Jay to have the final words. I'm going to talk about a concept called invisibility. And a question that often comes back to me is why our market cap is so low. And if you do have this much potential wise is not being reflected in our share price. And I think it's worth just pausing for a moment. We've mentioned a few things and there's a bit of a mosaic that needs to come together here. But a couple of years ago, we had an acreage position that was far less powerful than it is today. We had the 3D seismic. We had probably 10 years of work on this asset, but we didn't have the acreage position tied up and we didn't have all the data. And we've progressively been able to do that. Only Jay mentioned, I think it was 13 or 14 months ago, we picked up the final piece of the acreage in Talitha West, which is of incredible importance to putting this play together. And earlier in 2021, I think we closed it in March of 2021. We picked up the remaining 11% of Talitha to bring us to 100% of all of these projects. But to do that, we had to remain reasonably invisible. We couldn't give too much away to the market because, of course, we'd be giving data in a way to competitors in those lease sales. So we now have the acreage position that we need. We don't need any more. We've got, frankly, more than we can handle. It's enormous. And we're very, very grateful. So it had to remain invisible. But we don't want any more. So we're coming into this program. We're being measured. We've been a little bit British about the whole thing [indiscernible] understated. But when we get the data, if we're fortunate enough to the data to come in as we hope, then we could be very much on the front foot in telling that message and trying to deliver value into the share price because we are very concerned about being bid for. And so having a solid, stable, strong shareholder base is incredibly important to us because we don't want to be vulnerable to an industry who may understand the valuation better than the equity market. So that's the end for me. Thank you, everybody. Jay, I'd like to pass over to you to give your final words before we can sign off. And thank you, everybody.

So just kind of -- sorry, I don't know why my microphone went off. Just a quick -- real quick file mirroring what everyone else said, I mean it's really a pleasure to work with this team. And when you think about it, we got here with 9, basically 9 employees and a handful of consultants and any size. We have done enormous things with a really small team, and everybody knows everyone else. And we pull together, and that's why it works. And that's why we have 100%. We've raised $96 million. We're going to hopefully drill 2 production wells this year, have them on stream. It gets us where we need to be in terms of production for institutions to invest in us. We've opened up a market that we didn't think was there in terms of the debt market for us. So if we do have to execute, as Bob says, and we choose to do that, we can raise the capital necessary. So -- and I don't know Michael would love to do that. We all grew up thinking, "God, there's nothing more fun than having multiple rigs, turn it with the drill pipe turning to the right, it was always fun". It's always exciting. So yes, that's all I would say.

Jay, thank you so much. Look, I apologize, one very last quick thing that's come up. And that is how news flow will be delivered? And the rules state that material process that news must be delivered without delay. So that means we will be delivering it as it comes, good or bad. There's no benefit in trying to hide bad news or good news -- none of that. It will come as it comes, we'll deliver it to the market as clean and as clearly as we can. We'll do more of these webinars. I think they've been quite effective for us and the audience to understand our project. Whenever a window opens up, please understand we're going to be incredibly busy in the next few months with drilling, and it gets tricky if we're in price-sensitive areas to be doing webinars. So well, the next opportunity we can to do one, when we've got something to talk about, we'll be doing that. So with that, I think we'll sign off for the evening. Thank you, everybody. A copy of this recording will be made available. Hopefully, sometime tomorrow, often they do the sound editing and those kinds of things to make sure that the production quality is okay, but as soon as it can be released, it will be. So thank you, ladies and gentlemen, for your time. It's been greatly appreciated and fingers crossed. Thanks, everybody.