Pantheon Resources Plc (PANR) Earnings Call Transcript & Summary

Hello, everyone, and welcome to the Pantheon Resources webinar where we are going to review our drilling and testing operations from the winter 2022 season and develop our plans for the future. Thank you for joining. And since we have a worldwide audience, for those of you in the U.K., I know it's afternoon. If you're joining us live in Asia, thank you for being up so late at night. And it's midmorning, midday in the Americas. And before I get into any real specifics, I'd just like to say, because of the current geopolitical climate, there's never been a better time to have ownership of a huge resource base to exploit that is onshore in the United States on state lands and adjacent to underutilized infrastructure. And because of the geopolitical climate -- and I know this is transitory -- but Alaska North Slope crude is now trading above Brent. It normally trades about on par with Brent. But currently, because of what's happening in the world, it's trading above Brent. I'm going to turn my camera off because you don't need to see me, and it will make things a lot easier as we go through our presentation. Today, on our presentation, we have Justin Hondris, our Finance Director; Bob Rosenthal, our Technical Director; and our usual set of crowd pleasers: Ed Duncan, one of our geologic consultants; Roger Young, our partner from eSeis, and Roger is going to sound a little bit off today because he's recovering from COVID, so we've cut back his speaking part a little bit. I hope you're not too disappointed; Mike Smith from AHS, who will go through this volatiles analysis. And Mike just continues to improve what he's doing and what they're able to do with the volatiles analysis; Jerry Nichols, one of our geophysical consultants, he will give us a resource update. But the bulk of the presentation today will come from Michael Duncan, our VP of Operations and Engineering, who's going to go through the winter drilling season and our future plans in some detail. So Justin, could we go to -- so this is the disclaimer. So please, everyone, read it. It's important. Next slide, please, Justin. This is a map of the North Slope of Alaska. For those of you who have attended our webinars in the past, it's almost identical. However, there is one major change, and that is the upgrade of our Theta West Lower Basin Floor Fan to 17.8 billion barrels of oil in place. Now back to the map. Prudhoe Bay, what's set up all of this that's happened on the North Slope, discovered in the late '60s. The original [indiscernible] estimate was for 10 billion barrels of oil in place. Now it's 33 billion. The 3 billion barrels original recoverable has gone over 16 billion. The other major fields going to the west, Kuparuk, 14 billion barrels of oil in place. Further west, going over to Alpine, the field discovered by our friends at eSeis, over 1 billion barrels of recoverable oil. Also on the map, the outline of Willow, a ConocoPhillips discovery, where they have said they will make an investment decision at the end of this year. And then first oil will be several years after that after spending billions of dollars. Recently in the news, Santos at Horseshoe and Pikka is in a dispute with ConocoPhillips over the usage of the ConocoPhillips Kuparuk roads and facilities. We have the luxury of being 100% on state land adjacent to the Trans Alaska Pipeline and the Dalton Highway. And we have discovered over 20 billion barrels of oil in place. We believe this is all economic now. We will develop it from east to west from along the Dalton Highway to the west. This development will require literally thousands of wells to fully develop. And because we will become more efficient over time, we are going to have extraordinary success or whomever owns this resource will have extraordinary success. Now this is our team. Phil Gobe, our Chairman, ran Prudhoe Bay for ARCO back in the day. I'm not going to go through everyone. But as I went through and I added up the number of years of experience in North Alaska, it is literally hundreds of years of experience all up and down this team. So deep experience and with a broad breadth of abilities. Next slide, please, Justin. So why Alaska? Well, I've kind of set the stage for that. It's big oil, really big oil. The biggest oilfield in North America. Kuparuk is either the second or third largest oilfield in North America. Now we have on our 153,000 acres over 20 billion barrels of oil in place. At a very modest 10% recovery factor, that's over 2 billion barrels. That is big oil by anyone's standards. It's underexplored. It has great state support. The state depends on oil revenues from North Alaska for a huge percentage of their revenues. And we're next to, as I mentioned, the underutilized infrastructure. Why Pantheon? I mentioned our experience, but we're also a long-term local operator in the area with 153,000 contiguous acres, 2 units granted by the state, and the location, location, location that we have hammered on in the past. Michael will embellish that and develop this theme. We have no known environmental or native impediments on our lands. We've invested over $335 million to date, and we have invested that money very judiciously. As I mentioned, we have over 2 billion barrels recoverable, and we own 100% of it. What can be better than that? Next slide, please, Justin. Winter of 2022. I'm not going to go through the bullet points in detail, but we confirm the flowability of light sweet crude and 3 accumulations. We drilled a 10.5 miles step out in doing that. We believe all of these accumulations are commercial. Michael will take you through that. And it gives a generation of development opportunities in a unique and highly favorable location. Now what are our future plans? Quite simply, we're going to drill the Alkaid #2 well this summer and put it on a long-term production test, truck the oil up to Prudhoe Bay or pump station 1 and put it in the pipeline. We're going to further investigate 2 additional zones in the shelf margin that we'll take, which sits above our primary zone of interest at Alkaid #2. And the deeper Alkaid zone that was not penetrated in the original Alkaid #1 well in 2015, 2016. And in 2023, we plan a 2-rig program. Michael will develop that in more detail. If we're successful, we have a generation of development opportunities. What could be better? Now I'm going to pass it on to Bob Rosenthal, and he will take you through with his technical team our technical assessment.

Thank you, Jay. What I'd like to do is remind everybody what we were trying to accomplish this winter with our drilling and testing that we undertook. So the first part is we wanted to test the Lower Basin Floor Fan, the slope system and the Shelf Margin Deltaic in Talitha. Lower Basin Floor Fan is part of the huge state of West Complex, which we're going to be giving you a resource upgrade about. The slope system and the Shelf Margin Deltaic are part of -- if you can watch some of our other webinars -- is part of what we call the Super Trap. The second part of the season was to drill the Theta West #1 well, which is, again, 10.5 miles up dip from Talitha. It's 1,500 feet structurally up dip, and we were expecting to see a significantly thicker section there. All of these objectives were met by the end of the season. We successfully tested light oil in the Lower Basin Floor Fan at Talitha and Theta West, light oil in the Slope System. And though we didn't have a flow test, we did obtain light oil out of the Shelf Margin Deltaic. But importantly, I want everybody to understand what the results mean. And what we can take from this is that we have made several significant new light oil discoveries. Importantly, we have a major upgrade in our confidence that these are huge accumulations, and they represent probably collectively the highest resource density, that's barrels of oil per unit area discovered on the North Slope and perhaps all of North America since Prudhoe Bay, which is about 50 years ago. Our technical team is now going to try to take you through all that and give you the background to that statement. So I'd like to introduce you to Ed Duncan. He's going to take you through some of the reservoir story here.

Next slide, Jerry, please. Ladies and gentlemen, thank you for your attention and your interest in the project. It's a real pleasure for me to present to you again. We're going to take a few minutes to talk about reservoir in the various projects, specifically focusing, though, on the Theta West Lower Fan section, where we've had tremendous success. The slide in front of you has an awful lot of information on it. Probably none more important than the taxis in green between Talitha A, which we drilled last year, and Theta West, which we drilled earlier this year. We have confirmed a multi-cycle reservoir continuity in the Lower Basin Floor Fan. You can see the Talitha-A log motif and the Theta West log motif with the cycle boundaries that I've interpreted clearly illustrated. This is a significant development for us, 17 kilometers west, 10.5 miles west step out. That's not a normal scale step out in an appraisal project, but this is an enormous fan complex that we have drilled and proven. We have a significant increase in reservoir quality from Talitha-A to Theta West. Why is that? Well, it has to do with Dmax, shallower maximum depth of burial for the reservoir complex at Theta West. And we'll talk a little bit more about Dmax later in this presentation. But the important thing is we've seen a significant improvement in reservoir character at Theta West relative to Talitha. Now Talitha is commercially developed, Theta West just that much more so. And it's 50% thicker at Theta West than at Talitha. The most spectacular thing out of this, we have a continuous oil accumulation over this vast area. Every single one of the cycles is charged with light oil. They're continuous across the area. We have 3D to illustrate that unequivocally. Also important, as we're sitting immediately above the HRZ-source rock, as you can see on the slide, the HRZ is a light oil source rock at peak maturity in this area. It's a spectacular confluence of reservoir, trap geometry and source rock. It rarely gets any better than this. Next slide, please. A little bit on what Theta West lower slope basin floor fan -- lower -- excuse me, Lower Basin Floor Fan is. We have a good working analogue in the base at The Tarn Field, slightly older stratigraphically, about 28 miles to the northwest of the Theta West well, but it's a great depositional process analogue. The model that you see in front of you is a proven field. This is about a 200 million barrel oil field, several tens of wells through it. So we have great calibration on the Facies architecture, the building blocks of the fan system itself. That model is going to be applicable to the Lower Basin Floor Fan at Theta West with one exception. Tarn is about 60 square kilometers. The Theta West Lower Fan is at least 600 square kilometers. So more than 10x increase in [indiscernible]. And the Theta West Fan is much, much thicker than the Tarn reservoir analogue. Nevertheless, from a process perspective, it's a good analogue. Importantly, we know from Tarn the channels are the best reservoirs, the interchannel and basin plan areas are the less good reservoirs. All of that are active, all of it making a contribution, but there is a hierarchy in the reservoir characterization. Next slide, please. Here's an attribute extraction. Our good friends and partners at eSeis have done some extraordinary reprocessing and attribute work all calibrated with our wells. It's an important thing. Attributes calibrated to our wells. We've drilled 3 tests based on attribute response: Alkaid, Talitha and Theta West. This is a proven calibrated attribute for lithology and poor fluid. We've done it 3 times. We're 3 for 3, all right? The important thing about this map, more than just about anything, is that we can see light oil charge reservoirs. This is not an assertion. It's tested and proven. The gap in the bottom of the map, where there's no 3D, initially was not owned by Pantheon. Since 2019, we have been progressively infilling and aggressively pursuing Theta West leasehold. We've seen this fan. We've chased this fan. We captured this fan. Now we've tested it twice. We have proven it to be a continuous accumulation over an absolutely enormous area. Next slide, please. Earlier in the presentation, I mentioned the concept or the condition, the Dmax or maximum depth burial. And Dmax or maximum depth of burial has an effect on reservoir and source rock maturity. What the map on the screen illustrates, uplift in erosion. Basins like the -- deep of North Alaska where our business is being prosecuted, are known to have very widely varying but significant uplift in erosion post deposition. So the current depth of burial, the current depth of reservoirs in the basin does not reflect their original burial. Do that, you take the current depth and add the uplift and erosion that you see in the contours here, these are in feet, and that gives you Dmax, the depth of burial for the reservoir at its maximum. That has an effect. Compaction has an effect on porosity and permeability. Depth of burial also has an effect on source rock maturity. It is incredibly important that you understand, that one understands that if you're going to work this type of basin, you understand the role of Dmax in reservoir effectiveness and source rock maturity. If you don't understand that, you're very likely to make very poor technical decisions that will result in disappointing business outcomes. Let's take a look at the yellow overalls on the map. On the West is the Willow Complex. Jay introduced that at the very beginning on the west, the Willow complex. There we go. Thanks, Jerry. Willow Complex is a Conoco-operated discovery. Very exciting for Conoco. Far to the west of existing infrastructure and a very complicated development scenario. Conoco will make a decision, a final investment decision later this year, we are told. And we'll see how that turns out. Santos operates the 2 intermediate ovals, Pikka on the north and Horseshoe on the south. Those, as Jay has pointed out, are subject to a contest of source with Conoco about access to infrastructure. The yellow oval that's shaded in contains Alkaid, Talitha and Theta West, the 3 core discoveries and new fields that we have in our portfolio and are in the process of appraising and beginning to develop. And Bob made the statement really clearly. But inside that yellow oval is the highest resource density since Prudhoe Bay, anywhere in Alaska certainly and very likely in North America. It's important to know that we understand why are these fields -- why are these fields exist where they exist. To the west, we have Nanushuk reservoirs relatively shallow in present day depth and consistent of uplift erosion to Alkaid our northernmost discovery. But they're shallower. So the effective compaction and Dmax on reservoir is less there than in our projects. The same with Pikka and Horseshoe. But Dmax and reservoir degradation increases very quickly dramatically to the south of our project. We understand this. We've incorporated that into our valuation, and we have a suite of reservoirs in Alkaid, Talitha and Theta West that can be developed commercially. Next slide, please. This is an interesting plot because it does lean back on some legacy work going back to 2006 state geologists [indiscernible] published a similar work on Dmax and the role of maximum death of burial on porosity and permeability. The data on the slide, the colored dots, are all from Tarn, and they illustrate the important role behind Dmax of facies channels versus Crev Splays and Levee verus Basin Plain. With the general association of sand grain size being associated with the deposition facies. Channels have coarser-grain sandstones. Basin have the finer grain sandstones and a corresponding increase in porosity and permeability with facies associated with grain size. One of the things that we have found, we've done the work is the Albion section, which is Willow and Pikka and Horseshoe, is mineralogically and textually very similar to the companion sandstones that we have in equivalent facies in our project. The Shelf Margin Deltaic play that we have in Talitha, for example, and a long highway area, is the same play type as the Nanushuk play type at Willow, Pikka and Horseshoe. It's a low stand Shelf Margin Deltaic play. And interestingly, very similar from a textural perspective and mineralogical perspective. So we understand that the interplay between grain size. We understand the interplay between grain-size facies and the interplay between grain-size facies and depth of burial as far as understanding how reservoirs can be predicted -- effective reservoir can be predicted. The histogram in the background of the slide, it's a porosity clock, calculated porosity clock from lower Theta West fan at the Theta West well. This is really, really extraordinary. The increase in porosity between Talitha and Theta West will be discussed shortly by Roger Young, but what is incredible about the distribution is we see a clear presence of the facies architecture, the fan complex itself, relatively lower porosity in the thinner-bedded basin plan and interchannel lower bank facies. The core of the fan has a strong porosity average P50 porosity value of around 11%. And the channelized portion of the fan has very, very good porosities of 18% and a bit beyond actually. So from a reservoir effectiveness perspective the Theta West well has done a number of things. It's proven continuity between Talitha and Theta West across this enormous fan system, but it's also illustrated tremendous improvement in reservoir quality. As we go up depth, Theta West, it's 1,500 feet structurally shallower, but it's 2,000 feet lower Dmax. So that effect has resulted in what we have found to be a very, very thick section of effective reservoir in the fan complex there. I'm going to shut down on that right now and pass you over to Roger Young, who will put the icing on the cake as far as reservoir is concerned. Roger?

Thanks, Ed. Let's look at the logs. Here is Talitha, like you've seen before. This is the result of the log analysis, the shales are green, the fans are yellow, and then there's some heavy minerals here on the edge. But the most important part of this log is the oil in the green in this track here. When you compare that to Theta West on here, the first thing you notice is the reservoir is kind of whole lot more green. It's obviously thicker. But look at the quality of the rock, look how much more oil there is on the right on Theta West than there is Talitha. If we were to histogram both of these, you see that difference even more so. The porosities in Talitha, shown here in the blue as well as in the purple and the common area between the 2, show the distribution of processes throughout Talitha. The pink plus the purple, the common area, is Theta West. Now what is so cool is we essentially traded the Talitha porosities for the Theta West porosities. So what does that do to our overall volume of oil? Well, because the thickness increase and because of the porosity increase, we have over 2x the volume of oil in Theta West than we did in Talitha. The Dmax really did show itself here. It worked wonderfully. So we're very excited about this. Mike Smith is up next.

Okay. So I'm Mike Smith. I'm going to speak about our volatiles analysis on Theta West. We call this technique rock volatile stratigraphy, and our company is advanced hydrocarbon stratigraphy. I'd like to say how proud and humbled we are to be part of this incredible team. As I'm one of the new guys on the block, I'm going to talk about my bio a little bit here. So I've been analyzing volatiles and cuttings for over 40 years back in the 1980s. I invented the First Mass spectrometry systems to analyze individual fluid inclusions with Colin Barker, a very famous geochemist. I went on to Amoco Research also in the 1980s and early '90s and invented a technique called Fluid Inclusion Stratigraphy, which is used throughout the industry still today and was recently purchased by Schlumberger. And at Amoco because of this invention, I was awarded this prestigious and secret Amoco President Award. I left Amoco, I resigned Amoco and founded AHS and invented a new improved way of looking at Fluid Inclusion Volatiles. And we sold that actually in 1999 to XOM. And that's still in used around the world by XOM, and we can solve with them as needed from time to time. After this, I kind of pivoted away from fluid inclusions and we restarted AHS back up, and we invented something we call rock volatile stratigraphy or volatiles analysis services. And that is in 2009 after [indiscernible] compete with XOM expired. And that is really about present day fluid. So what we try to do is now say something about what the fluids are at the time of well was drilled. Fluid inclusion is a great information, but it's about the past. It could be the recent past or it could be 1 billion years ago, but it's about the past and really to kind of get to an X marks the spot sort of analysis, we really wanted to shift -- it's looking at non-{iUHnclusion fluids and cuttings, so looking at things in tight pores and microcracks, and using very gentle extraction and analytical techniques that we invented to get at that. Here some of my patents. I have to add a few more recent ones, but you can see we've been at this for quite a while, and they're almost everything that's out there in the world today that analyzes volatile and cuttings. It's Schlumberger or XOM or in our lab is a machine that I've built an invented designed and built and programmed. Again, the technique we're doing now, the rock volatile stratigraphy, is about the present-day oil and gas. A little bit about how we do our work. We're very focused on providing unbiased results. And to do this, we ask our clients and [indiscernible] to provide any information about the oils that we analyze until we're done with the analysis and have presented our results. So we don't get any information as to what Pantheon is seeing with other technologies until we're done with our data, and we've actually presented it to them. And then after that, we all work together to make the best final product we can. But this study we're going to show you now has been completely blind and independent of Pantheon by us. So just to say you know that. This is the only figure I'm going to show is this figure and what this is, is our hydrocarbon lot of the Pantheon Theta West 1 well, and all these columns are showing different oil compounds that we analyze. We analyzed somewhere around 40 compounds. So this is about 1/3 of what we do analyze. And what -- it's a very striking graphic, I think. And what we have is the first 8 columns are showing paraffins, which are saturated hydrocarbons that are not cyclic. And the next 3 columns are showing up here showing naphthenes, which are cyclic hydrocarbons that are also saturated. And then we have some aromatics here, which are unsaturated hydrocarbons. Here, we've just added up all our gas and oil here in these columns estimate volumes. But over here, we're showing just the samples that either contain oil and green or don't contain oil in white. And what is remarkable about this is that we have 1,460 feet of cuttings, and every single cutting sample contains oil. Now this really speaks to what Ed and Roger were talking about, about the size of the resource and the great HRZ source rock and the great reservoirs and everything, that we are in an area where there is so much oil that every single sample of rock below 7,090 feet in this well has significant oil saturation. So we're looking at just an enormous pool of oil here. And that's pretty incredible in itself. But what is also remarkable is that the upper 400 feet of samples here contain no oil. There's nothing. And we have an ultimate seal to oil right here at 7,090 feet. So from the HRZ up into here, every sample has oil. The whole basin floor fan all contains oil, every single sample. And then bang, we have no oil up here. In science, this is what we call a square wave when we go from something where there's nothing to something where every sample has the same attribute. So here, no oil above 7,090. And then every sample below 7,090 now. Ed and Roger did a great job on talking about the wonderful reservoir and source rock and great porosities and thermal maturity of the source -- HRZ source rock, the great trap geometry. What I want to emphasize here is this is an incredible seal. Nothing is getting passed this seal. Not a drop of oil is moving past the seal that we can detect. We have the best cuttings, volatiles technology in the world, and we see no oil up here. And every sample down here has oil in it. So we have 2 great stories here. We have -- we're showing that there's a large amount of oil, so much oil that every sample has oil in it. And from these data, we're also showing that the oils of good quality, it averages about 38 API in our calculations from lease cuttings data. And we are not showing everything that we have, but we also -- our data shows that there is much good reservoir. We have an abundance of good reservoir quality, again, as Roger and Ed pointed out. And then we have good seals. We have this ultimate seal, but then we also have other seals throughout the data set. So this is really a great petroleum system. So just to summarize, we really want to point out these 2 conclusions. We have a world-class petroleum system that's been tested here at Theta West and at Talitha-A. And Theta West we're seeing almost 1,500 feet of oil saturation. So we have 1,460 feet of cuttings, all of which have oil in them in the basin floor fan complex. And so it was a good quality, high 30s API gravity. There's a lot of it. Every sample has oil in it. We have good reservoirs, and we have good seals on our data. I want to thank you for letting me share this with you. I believe Jerry Nichols is up next.

All right. Thanks, Mike. I want to upgrade or update our resource estimates now. You've seen the geology and the volatiles analysis. Let's now move on to the numbers. And before I do that, I really want to emphasize one thing here, and that is this. These are proven reservoirs all of these reservoirs in terms of log analysis and volatiles all of them are all saturated from top to base. And more importantly, all of them have tested and shown the existence of movable oil. So these are not prospects. These are proven reservoirs. So let's start with the Shelf Margin Deltaic. There's really nothing new to report there. This was not a target in Theta West #1. So we had the same number we carried post Talitha. That's a Monte-Carlo estimate. Moving down into the slope fan system. This one, we, in the past, post Talitha, we did not attempt to estimate an oil in place figure. Now with -- in light of the successful tests at Talitha, we undertook a scoping deterministic model. We wanted to get a ballpark figure, estimate recognizing sands and the shale matrix. And that number turns out to be about 2.2 billion barrels in place. Moving onto the Lower Basin Floor Fan in yellow. That -- for that zone, that's the largest zone, largest reservoir in our acreage. We have 3 penetrations, all oil saturated and successfully tested in 2 wells. And our prognosis here was accurate in terms of depth, thickness and also reservoir character. So that gave us much more confidence in the reservoir extent and quality. And because of that, we saw the need to develop a deterministic model. We did that. We incorporated the porosity or saturation net to growth ratios in the iso packs based on data at Talitha, Theta West and seismic. So that resulted in an expanded reservoir extent and improved reservoir quality. When we integrated all these maps together, we come up with 17.8 billion barrels in place. That's net in our acreage. At Alkaid, that's unchanged. That's 0.9 billion barrels, and that's a drive from the independent expert report. So altogether, these sum up to 23.5 billion barrels in place in our acreage. So that's a tremendous result. So that's all I have to say on resource assessment. We're going to now move on to Michael Duncan and how he's going to talk about development.

Before we introduce Michael, I'd like to make a couple of points here. One is what you're looking at are resource assessments based on having tested movable hydrocarbons from these zones. So again, I want to emphasize that we have significantly more confidence in these numbers than we did before this season. So the increase that you're seeing in the Lower Basin Floor Fan is based on the new data, but that new data is -- so we see this about 60% increase in the Lower Basin Floor Fan, but that new data gives us much more confidence that this number is correct. And I suspect when we drill more wells that, that number will get larger too. The other thing is -- before I get [indiscernible] just point out just a couple of things. And Michael will be emphasizing this through his whole presentation. Again, and Jay has brought this out in the introduction, all these discoveries, all these new oil discoveries are going to be evolving through time with appraisal and development. Each one of these projects benefits from the immediate access to the pipeline and road infrastructure. The impact of this proximity really can't be overstated. It drives so much drives commerciality of our new developments that we're planning to talk about. And I think Michael will be presenting to you like a very, very thorough detail of each one of these ideas. And I hope you keep that in mind while he's discussing this.

Thanks for the introduction. Great to be here as always. I think the last time I was on a webinar, I was up on the north of Alaska. And so it's with real mixed emotions that I'm not there today. I was being up there and operations are wonderful when they're happening, but I'd say it is nice when operations are finished for the season, and we can go outside and join the weather without wearing what's best described as a space suit. So glad we had good operations this season. Glad to be taking a quick break from the North Slope and anxious to get back at it. And so over the next little bit, I'll be discussing the operations of Talitha A and Theta West and then look ahead to what our plans are moving forward. To give an operations summary of the winter operation, I mean, obviously, the big conclusion, the big takeaway is we now have proven oil with amazing oil quality and 4 reservoirs. It's just really substantial results and to have the oil flowing to have this proven has been a wonderful season, true highlight of this season. In particular, the Talitha A, we tested 3 intervals, as Jay spoke to earlier, in the Lower Basin Floor Fan we got a good result, amazing-quality oil, good mobility. It stabilized on around 42 barrels of oil per day. Moving up all to the slope fan system in the Talitha-A, we had a very good result, a surprisingly good result. It was oil quality on par with the Lower Basin Floor Fan, but a rate that kind of exceeded our expectations. And I'll discuss that a little more in the next few slides. In the Shelf Margin Deltaic, right now, it's a bit of a to-be-determined. We had some obstruction flow that I'll talk about. We're working to truly understand that. But at the moment, it's quite an inconclusive flow test, but it did recover good quality oil. And so it's a true to be determined on the Shelf Margin Deltaic. I'll visit about the Theta West in a little more detail later, but of course, the takeaways how do we successfully drilled the TD. We cased the well. And in the cementing process for the well, we had tool misalignments configured that created a bit of an operations problem that we'll go into. We were able to overcome that. Very proud to say we were able to overcome that and continue with our testing. We tested the Lower Basin Floor Fan. Oil identical to the Talitha that flowed at a good rate, 57 barrels a day stable. So good, mobile high-quality oil. And so looking at each of those, of course, Basin Floor Fan is just -- it's an enormous reservoir and that's the exciting conclusion that we step out 10.5 miles and get the same oil and good mobility. It's really an enormous win both literally and figuratively. In the slope fan system, it's very exciting. This was not a main target for us, but the deliverability and the oil quality is very exciting and really warrants a lot of effort to move forward with. So that was -- that was a pleasant surprise for the positive and a lot more to look forward to there. The Shelf Margin Deltaic, of course, the true takeaways that we need to figure this out, and we will. There's a lot of opportunity to do so. We are going to discuss that in further detail in this presentation, but we will figure it out, we'll make sure we test that formation properly as there was good quality oil in it. Looking ahead, later in this presentation, I'll discuss our path forward. We definitely have more appraisal work to do on Theta West. As large as that is, it's really exciting to think about the future step outs and where we go from there. Obviously, in the Shelf Margin Deltaic, we will figure it out, and we'll get a good test. In the Slope Fan System, that wasn't a big priority before, but it's certainly climbing the ranks, and it's really very noteworthy now, and there's a lot more to appraise and test on that one. And then the one in the immediate future is that the Alkaid is ready to drill and produce. And I can't stress that enough, long-term production from the Alkaid. This is a true to step forward, and we very much look forward to that. And then to conclude the presentation, I'll talk about the big development, what it looks like in the long term. For the Alkaid, the Shelf Margin Deltaic and others, just a development concept for this acreage. It's a very exciting opportunity. So to dive into the Theta West Lower Basin Floor Fan, this is a graphic discussed earlier. Ed, Roger and Jerry spoke of it very well. I'll bring it up just as a reminder of the step-out in the size of this reservoir. It's truly an enormous northeast piece of rock. These are our first interactions with it, the Talitha and Theta West. So this slide might look familiar. It's essentially the same slide that was presented in January when we spoke of how we intended to complete this formation. Takeaways from the slide, of course, in the middle is the lithology interpretation that Roger spoke to, yellow being sand, green being clay. And the red triangles you see in the middle represent the stimulation stages and how we both intended to and did interact with this formation. This is the first time I had said that we'd ever interact with it. And so you go into it rather cautiously you don't know how to frac, you don't know what it will do. And so these frac of stages were placed reliably. We took a conservative approach. We used gels to carry proppant. We used more conservative proppant loading for the gels than you might under other circumstances. Rate was around 40 barrels a day. So there's -- it was a very tried and true conservative stimulation that we placed in this. Successfully completed it and turned it back around, and the results were wonderful. 42 barrels of oil per day is where we're calling it. Early on, peak rates were higher than that. We saw over 100 barrels at day spot rates, but it didn't want to call that a stable production. And so the 42 barrels of oil per day represents really a reasonable stable production from this formation. The other big success story, of course, from this is the oil quality. 36 to 39 API oil was measured on location. We're doing lots of testing on it because it's absolutely light sweet crude, absolutely in line with the geologic model. And it's a complete confirmation of the view of the hydrocarbon system as Ed spoke to. And as Ed and Bob forecasted all along, this oil is exactly in the right window. And it couldn't be a better product, and we absolutely proved the mobility through this well. So this is a very successful outcome for us. We moved up the hole from the Basin Floor Fan to the slope system. And this was meant to be a quick check. The slope system was never intended to be a primary or even a secondary target for this well. But during drilling course, we saw these lobes and know they're worth investigating. Once again, we're on ice roads in the middle of a winter season, and so time and resources are quite limited. And as such, we meant this to be a quick check look at this formation. Hey, there's something there. Let's see real quick what it acts like. And so this slide once again was presented in January. We interacted with it in 2 intervals as represented by the red triangles. But we only do this at 1 fracture stage. And we tried a fun and clever way to do it. You -- in order to -- in an effort to try properly stimulate 2 sands with 1 frac, we split a fracture stimulation stage in half. So you pump half of it, you stop. Theoretically, the formation closes on that fracture stage, and the sand is then placed becomes an impediment for future fracking. And when you start back up, that resistance causes a fracture to go in a new area. In that case, it would be the second lobe. So it's intended method of killing 2 birds with 1 stone, and we made that attempt to treat both with 1 fracture stage. We successfully pumped, but when we started up after the first shutdown, we didn't see any changes. So the fracture resumed right back where it was. To us, that doesn't indicate new intervals open and thus indicates that we only frac half of this. Maybe we did hit both, maybe we didn't. At the moment, we don't really know, but our indications are that we likely just hit 1 of them. Either way, as a quick check in between other zones, we're really, really encouraged with the results. The oil is identical to that in the basin floor fan. It's same light, sweet crude, highly mobile. And in this case, we saw a rate that came on really good, 45 barrels of oil a day for a quick check, what's in this formation, that really exceeded expectations. So pleasantly surprised by the flow rate, really happy with the oil, further confirmation of our hydrocarbon system and our concept. And so this was a great moment where a spot check of the sand really came through. This is a big success. We got down with that, we cemented the zone and we want to move up hole to the Shelf Margin Deltaic. And I present this slide for a couple of reasons. One, just as a reminder of the Shelf Margin Deltaic, what it looks like. I've seen this presented by others on this webinar. So not only the reminder of the system itself, but also our past history with it. this formation has been cut in 5 different wells, and it shows up great in each of them. The Talitha, though, is our first time to interact with it. So we've seen in lots. It looks good in lots of places, but this is absolutely our first go at it. So on this slide, this is our first go. We had the concept that we would just tackle this main sand, as shown with the red triangle on it. Single fracture stimulation stages just -- let's just hit it in the middle and see what it does. And so we went out, had the well prepared, perforated, ready to go, and we begin a fracture stimulation on it. And the job, unfortunately, had to be shut down part way through it. So we didn't even get proppant loaded in the well at that time and had to shut the job down. With that shutdown, it's operationally complex because we have to freeze protect the entirety of the equipment. And so we freeze protect all the equipment, shut down for the day, crews leave, personnel comes back the next morning. And we have to undo all the freeze protection. So we have to clear all of diesel and freeze protective lines. We need to warm up and re-pressure test. So it's a long process. And it took us about 20 hours between downtime crew resting, freeze protecting, unfreeze protecting, warming up and pumping to get back into it. So we got back in with the main fracture stimulation, it was the next day, and we successfully pumped a frac. That known frac, everybody is looking to watch with me. We're looking at the weather. We're trying to assess what's going on, and there was a storm that came in. And so with our access to talent and our supply chain getting cut off and just with general weather and safety precautions, the decision was made not to open the well until after the storm passed through. Storm passed through, we have to dig out from locations, we take every equipment. We move snow. We take shovels and get all the corners. And then we're able to get back at it. And so that process took about 3 days. So from the time we first started pumping to the time when we were able to turn the well, it was about a 5-day shut-in period. That certainly wasn't planned or desired. It was just a path that went that way for weather reasons. We turn a well on, we get it flowing. We get some frac fluid back quickly as is expected. And then flow rates tapered off to almost manageable [indiscernible] really quick. And we sat there kind of scratching our heads wondering what was going on. There's clearly some obstruction flow. We have reactive plays that's had for a while. We've seen evidence of a motion in the well, but something -- and we've yet to fully determine what it is, but be it be a chemical, be it an emulsion system, be it a reactive clay that we sat too long or didn't properly inhibit. The counterpoint, though, is that, albeit in small amounts, we did see the same light sweet crude. In this flow, we measured on a few samples between 34 and 38 API sweet oil. I mean it was once again a beautiful product, but it just was the time when there was a minimal inflow into the well. And so to add a little color to what that means to help crystallize what we're seeing, this is the chart from the flow back. And what you're looking at, at the top, the dotted line is the amount of fluid that was pumped during the fracture stimulation, a little over 2,600 barrels. The blue dots represent the cumulative flow recovered during our test period. And so you see it coming on and some energy from the stimulation still causing contribution at first. And then you show it going -- and then you can see it going asymptotic and eventually getting to where inflow is too small to measure. And so we're not even getting our frac fluid back in this. It was a very -- it's still a head scratch for me. We need to understand that we have the possibilities. We're investigating. We're taking the time to investigate it. But we'll absolutely get this figured out, we'll understand what is going on. At the moment, it's a very inconclusive test when it comes to rates, but it did show even in that small amount of inflow, there was a light sweet crude to it. So it's a big to be determined moving forward.

I would just like to add, if I could, is that we're coming back there next season and probably going to do a sidetrack and that's -- I think that's one of our way forwards here. And what happened? We just -- we don't know. There's an impediment to flow. We didn't even get what percentage of our frac fluid back. So I think Michael has worked out probably the best thing to do is just go in and do a sidetrack and have a very clean borehole.

So this slide is meant to be a summary of the well, and this is a duplicate of -- essential duplicate of a slide presented in January. The slide presented in January was meant to present and discuss our expectations. And I use that to reflect on the season and in light of our expectations before any of the testing was done. And so starting from the bottom moving up as you always do in completions. The basin floor fan, we were seeking good oil quality, and we predicted between 35 and 42 API oil. Absolute check mark on that. The oil quality is wonderful. That's the first big success, but also the mobility. I mean, we're absolutely able to make this flow, make it flow steady. It's a big checkmark against expectations for basin floor fan, absolute success of the season. Yes, in the Slope Fan System, an equal check mark, of course, and that one we just predicted light sweet oil. And same prediction as the lower basin floor, we predicted 35 to 42 API gravity. Once again, it came in at 36 to 39 API. So absolute check mark there, that completely validated hydrocarbon model. But in the slope fan, we needed a little more because it was this small -- relatively small sand lobe. And we need to see some signs of good permeability and flow rate, and that absolutely came through. So good deliverability, good mobility, great oil, a really big check mark for goal achieved in these open systems. As discussed in the Shelf Margin Deltaic, really be to be determined. And that when we are looking for a flow rate, and we forecasted it 50 to 80 barrels a day. That's on par with what the others produced. They came in that realm. So I feel like it's a very reasonable prediction. And all of our data indicates that we should have been there or better. But as discussed, there's been some obstruction. And we will figure it out, but that's like to be determined for today until we go back next season and get this figured out. All we know from the Shelf Margin Deltaic is there's good oil in it.

Before you move on, Michael, I'd like to make a comment on this and the quality of the work done by the team on the testing here was -- it's quite amazing.

Thanks, Bob. And I appreciate as well, and I'd like to echo the accomplishment for the team out there, really amazing success. And to go in first time to play these rocks and have the success, I'm very proud of what the team was able to accomplish. To take a similar reflection at the Theta West well, bring up this slide and just want to go through the approximate story of the Theta West. We were able to drill the TD, of course. And then the moment that seemed to kind of define the well was in the casing and cementing operations. We ran casing to TD, and we recognized in advance that we would need to cement it in 2 intervals, a lower interval, let that cure so that the integrity to be there to cement in up or interval. To do that, we ran a stage tool, which is a color that with varied plugs, you can open the ports in it and close the ports in. And so you start with the close, you can pump cement past it and then supposed to be able to open it to pump your second amount of cement and then close it when that's done. The tools were misconfigured when they were run. They were -- we rely on third parties for some of this. And in this case, it was improperly run in the case. And so we went to pump our cement and instead of being able to pump past that tool, we end up getting cement locked up in the tool. And so our cement stopped inside of casing rather than outside of casing. And that, in turn, compromised our ability to function the stage tool that we run. So it put us in an interesting situation where we had cement inside of the 5.5 casing. We didn't have enough cement outside of the casing. We didn't have the ability to function the tool to continue with our cement work, nor did we have the ability to close the tool so that we could frac past it. And that was a big challenge, especially in a season out on the ice. We were able to get past it, though, I'm very proud of that. In order to do that, we drilled out the cement from inside the well. So that opened the wellbores to us. We completed our cementing behind pipes through the open ports, but we weren't able to close the ports and restore well integrity, so we had around additional pipe inside of that pipe to cover those holes and give us the ability to communicate pressure-wise below the malfunction staged part. We did that. We ran a liner. We put it in place and cemented it as well. So the bottom of this well was completed in the form where we had a 5.5-inch casing cemented in place. And then inside of that, we had 3.5-inch casing cemented inside the 5.5.

Michael, before you move on, I just want to make one comment. Because Michael talks about it, and it sounds really pretty easy. But when you actually have to do it, you have to drill out cement, over 1,200 feet of cement and a tool, part of a tool, inside of your 5.5, you're using very small tools with very small tubing attached to that said drilling tools. And the -- it really limits your ability to make that happen, and they were able to do it. So it sounded pretty trivial as Michael was talking through it, but let me tell you, it was not trivial at all.

I concur, Jay. I mean it was, again, another one of those amazing accomplishments by the team out there.

No, I appreciate you bringing up those points. It was a challenge, and the guys in the field the whole team, everybody did an amazing job. And it was one of the best team efforts I've ever seen in fixing this. It took input from geology. It took input from drilling. It took input from completions. And we managed to pull it together. And of particular note, when Jay speaks of small tools, the inside diameter of a 5.5-inch casing is approximately 4.9 inches. And that's something you can kind of work with. That's about the size of maybe [indiscernible] water bottle. When you're looking at running pipe inside of that cementing in place, you're now dealing with an inside diameter of less than 3 inches. The ID of 3.5 casing is about 2.9 inches. And so incredibly small tools, that's probably -- you can't really even get your hand in if you need to, much less any strong motors or any strong tools. And so we managed to do that, and we managed to complete through it. But yes, it was absolutely a delicate procedure. And I'm very proud of all the people that pulled that off. When we think about what that meant for completion as well, that meant for every step forward from that point on, it was through 2 pieces of pipe. So for perforating, we had to shoot through 3.5-inch pipe cement, 5.5-inch pipe cement and in the formation. And you have to do that with really narrow guns that have really small charges in. And so it really pushes the boundaries of everything. But we were able to successfully perforate through everything. We were able to successfully pump and manage to salvage a test from a difficult configuration inside of a well. And how wonderful we are able to do that because the big conclusions from the tests are absolutely remarkable. Of course, the highlight, that's the same oil as in Talitha. It's wonderful. It's a 10.5-mile step out and you're hitting the same oil. And despite the challenges despite the difficulties, the poor well configuration and the struggle to continue forward with this we still got good deliverability. We got a stable production rate at 57 barrels of oil per day. And it even looked better. It's more stable. It just -- it was a good result. And so a really wonderful conclusion to a difficult situation. Of note in this one, we did sell a load of oil. So this we are able to take the oil separated process and on location and sell it. So from the Theta West, we sold 38.7 API oil as measured at the delivery point. We are also able to sell a load of oil from the Talitha-A location. So that's all the twice by truck in this season from both of the wells we tested. It's -- I'm very proud, very optimistic about this conclusion. It was a really, really wonderful result of the season. To kind of sum up where that puts us, those rates, 45 barrels a day or 42 barrels a day, it might be a struggle in Alaska. But I really need to reiterate the concept of testing a formation in a vertical well out on ice is much, much different than drilling a horizontal and completing it as a producer for a multi-stage with the right timeline, the right ability to flow, the right ability to operate with it. I mean I can't stress that enough that the concept here in these vertical wells, in this ice road appraisal process is getting ready for what it means for production, which is long horizontal multi-stage wells that will be many, many, many times the contact and stimulation of those. And there's some other things we've yet to even realize when we speak of completions. As I said, we have to be really conservative right now because it's the first time we're ever interacting with this rock. And so we go in very operationally conservative. We don't have the horsepower to pump at high rates. We're stimulating it at 40 barrels per minute pump rate, which is low. We're using thicker fluids and thinner fluids can create a better fracture network. So there's lots of opportunity ahead when we can get away from the early time-constrained, ice-based conservative approach we need to take. So lots of upside in the completion ahead. On the operations side, there's a lot of opportunity for better lift in these wells for available resources, for the equipment we need, for the fact that we have to test multiple zones move up and down the hole, we did lift for these wells with 2-inch coil inside a 5.5-inch casing. Or in the case of the Theta West, we couldn't even get down because the line was down there. And so that's a nimble lift system. It's a fast way to test these wells and is really fit for purpose for when we're out on the ice trying to see how these formations act, but it's inefficient. And our ability to move forward with more efficient techniques is really exciting because we can do a much better job of lifting and producing these wells and interacting with it. And then, of course, we still have a lot on our drilling side to optimize. Once again, when you break free of time constraints, it's wonderful what you can do. And so we've got a lot we're learning about we're improving. Just learning how to see recognize and better interact with all this. And then, of course, we've yet to even high grade any of this. So understanding the better reservoir to land in, understanding the better spots to really complete this we've yet to capture any of those efficiencies. And so I'm really encouraged not just to the scalability of this, not just to the fact that these are small vertical tests and we look to do big serious horizontal producers. But also the efficiencies we'll be able to gain as we move forward. This was try #1, and then there's so much more. So I'm very excited about what this means moving forward, scalability, better efficiencies, there's just so much new there. And sort of really kind of look at the season of what that means. I come back to -- we have 4 giant reservoirs that are all proven. I mean they've all flowed oil, and they've sold oil. It's a huge, huge win from this season. We look at the Theta West, it's a giant reservoir. And there's so much there. We've got a lot to appraise. It's really -- there's great things ahead there as we do further step outs and we further show where this reservoir goes and what it can do. In the slope system, we're just starting to interact with it. And so there's a lot of appraisal there. Before it wasn't a real serious target for us. It was a tertiary concept. But now we've seen some good results. We've certainly prove in the system. So there's a lot to show on that, a lot to derisk, a lot to really prove up. And I very much excited about that zone. In the Shelf Margin Deltaic, we'll get it. something wasn't right out there, but we will figure it out. We've got a lot of opportunity to interact with that. I'll talk about that moving forward, but there's a lot of head on the Shelf Margin Deltaic, and we'll -- we absolutely will figure that out. And then on the Alkaid formation, very anxious for this, we're ready to produce. That's such a wonderful concept to say, we are ready to produce the Alkaid and that's our next step. So that's a great segue into our operation plans for the summer. The focus of the summer is the Alkaid #2. And I want to just take a moment and reflect back on the Alkaid. We've spoken about it some. It's the smallest of our reservoirs and add approximately 1 billion barrels, which is amazing to say. When we spoke of Alkaid in the past, it was a very low oil price environment. I mean we were talking when oil was $30 and $40. And at those prices, the Alkaid is it's still in the black as we've shown, but it's not an enormous value, especially in light of some of these other reservoirs. But in the price environment we're in today, it's a very exciting reservoir. When we did the contingent resource report, we used 55 -- or I should say queuing and used 55 barrels of oil, $55 per barrel for an oil price. I mean that's -- everybody knows we're way in excess of that in today's numbers. But even at that price, it was a $600 million asset. Today's oil value, in the billions. And it's really, really an exciting asset to move forward with. So I just want to take a moment and kind of look back at lower prices, the smaller scale of the Alkaid, it's still in the black, but it was just at the lower price environment. It was a good opportunity to do what we did and appraise bigger formations. Now the fact that we're ready to produce at a high price environment, it's just a wonderful, wonderful opportunity. And so with that, I revisit this slide, this is essentially a duplicate of what was presented in January with a couple of changes highlighted in red. Alkaid #2 is our first crack at taking a vertical and showing what that means for horizontal. And that's the point of the Alkaid 2 and what makes me so enthusiastic about it. For the Alkaid 2, we look to go put 30 or 40 fracture stimulation stages in a horizontal. What we learn in this season is these fracs appear to be acting relatively plainer. And so we might even increase the density of them. And so it's forecasting one stimulation every 200 feet of horizontal, we may even push them in a little closer than that. And so the scalability of this, if they are acting as point of fractures, there may be room to even put a few more in. But ultimately, the question is if one fracture stage in the Alkaid does 108 barrels a day, what happens when you put 30 or 40 of them in a horizontal. And I cannot wait to show this concept. We forecasted about 150 barrels of oil per day for every 1,000 feet of completed horizontal. Now I want to stress that, that's not what we need. We can make it work with significantly less than that. That is the forecast right now is for every 1,000 feet of horizontal we drill and complete, we look for 150 barrels of oil a day production. And then the math for that is done in the bottom right-hand corner, of course. So if we complete 3,000 feet of horizontal that should translate to 450 barrels of oil per day. If we complete roughly a mile, we're looking for 750 barrels of oil per day. And if we can reach further than that, as we most certainly will in development, it will be well [indiscernible] of oil per day. For this well, it's our first crack at it. And so we want to be sure to stress the point that our priorities right now are on operational reliability. We will get this place. So we won't be necessarily reaching for long horizontals on the first go. We want to make sure we show what this can do. But in the future, I mean, once -- as we learn, as we show how to do it, is to really show our capabilities. I mean, there's just so much room for long horizontals for amazing scale. And this summer will be our first scale at it. To discuss a little more of what that means, here's kind of some graphics on the well itself. On the right-hand side is a satellite image of the North Slope of Alaska. What's easy to see in this is Prudhoe Bay in the top right and then the Dalton Highway shown in yellow. And as I've said many times, the Alkaid #2 is immediately adjacent to Dalton Highway. And that gives us the ability to switch from ice to gravel and be free of all the seasonal constraints and free of all the operational challenges of remote exploration. Looking at the graphic to the left. There's a lithological interpretation shown here. The lithology formation scene, you see our location up in the top right-hand corner. Our location in the top right-hand corner here immediately adjacent to the Dalton Highway. And from that location, we'll come in and cut the Alkaid reservoir approximately here. And so with that, that's meant to give us a good representative law and a good evaluation of the formation. So we'll have to reach out just a little bit as we do that. Once we cut a log, it will run a horizontal. And that's depicted in this seismic line just below it. So you see in the seismic line, we intend to run essentially vertical. It will be a slight slant well to cut the formation. We do that, that will penetrate 3 areas that are very exciting. The Shelf Margin Deltaic, we cut it on the way. And so we get another look at the Shelf Margin Deltaic, the SMD. And so that's just a great look at things as we go. We'll get a look at the reservoir we intend to produce on the way down, but we intend to go past that as well. When the Alkaid #1 was drilled, the Sag River overflow cut off the Dalton Highway and it caused the cessation to operations. And so we broke a cardinal rule of exploration and stopped drilling in the middle of an oil pay. I had to do that, of course. Good news since the highway has been fortified. There's not the same risk of any such cut off in the future. But this Alkaid well is our opportunity to go look at the deeper reservoir that we were unable to see in the Alkaid well because of those circumstances. With the gravel, once we're free of the seasonal constraints of ice, once -- we can operate long term, we'll get into long-term production. And so with that, we need to change the way the surface operates. And this cartoon here is a functional schematic of our operating facilities. Starting with the wellhead in the top left-hand corner, we will have 3 phase production from the wellhead, which is oil, water and gas. We will heat the product lines to be able to properly separate them. Once we separate them, oil go into tanks, the tanks are for storage, and we can do finished conditioning in the tanks. And then from the storage tanks, will truck to sales. This has already proven for us. We did this season twice. Really grateful to have that opportunity up in the North Slopes of Alaska. So it's unique to North Slope, but we will be able to truck oil sales from location. The gas that comes to separation will be used twofold. First, we will use that gas to power locations, we do on-site power to generate. The second use of the natural gas from the well is a lift system. So we'll have on-site electrically-driven gas lift system. So this will afford us a long-term design of lift, a low-cost lifting capabilities. It's giving both the power and the medium for which we will be lifting the well. So this gives us the chance to do operations in perpetuity with full control of the well as we see fit. And then finally, the water, shown in the middle here. In exploration, we have to truck and dispose of the water. And this one, we'll be able to reinject it. So we'll have that capability on location. So this is a self-sustaining system that allows us to process oil, water and gas on location, be able to truck and sell water, be able to use gas beneficially and be able to reinject the water system. I offer this slide to dive a little deeper into that facility because it's a very important facility for us. And personally for me, I'm very excited about what it has. This is absolutely unique to the North Slope of Alaska. This scale, this concept isn't really -- hasn't been applied before because nobody else has had the ability to go put a gravel pad next to a highway and make it work in this manner. So you see a schematic of the locations we got here. This is similar to what's done elsewhere on the continent, but in particular, we're looking to Northern Canada, our neighbors, because they operate this type of equipment in similar arctic conditions. And so this will allow us full autonomy on location, full ability to process and operate in perpetuity using methods from just across the border. So this particular system is designed for about 2,000 barrels of oil a day for separation. Hopefully, that's not enough. But that's certainly a good volume for us. And so it's a strong capacity and it's a really, really capable operating system. I spoke about this earlier, but it's fully electric. Everything on this location runs on electricity. And that has 2 amazing benefits. When we operate it, the electric controls just allow it to operate so efficiently, it can all be SCADA controlled. It can all be easily ramped up or ramped down. It can easily adjust to meet the needs. And so it's just a really smooth operating system because we control everything electrically. That gives us the ability to run, I'm going to say, leaner for lack of a better term, but there's a lot of things we don't need. In the past, we've used nitrogen for lift. We won't have to do that because we have the beneficial reuse of natural gas. We'll be doing our own water injection, which is wonderful because the cost and logistics of trucking water is certainly a difficulty, we would rather avoid. And this facility will avoid that. And then, as I said, with the electric system, it allows us to operate without the test personnel. So we will have personnel on location would just be a much leaner group. It will be much more easily controlled, just a really nice operating system. I spoke about it. We've already proven we can truck and sell oil. A big note for the system as well is that we believe we'll have it in place for approximately $1 million. On that note, the majority of this large equipment has already been purchased. And so we're on track. So the thought of $1 million cost isn't a guess. It's something we're absolutely on path to hit. And that is a real cost of entry to production in the North Slope of Alaska. Historically, other operators have had to invest hundreds of millions in facilities before they get the first drop of oil sales. For $1 million, we have a long-term production system capable of being fully autonomous, separating and selling oil. And the only reason we're able to do that is because we have a highway that goes to location. We have the infrastructure we need. So we can do this on a one well basis, whereas operators in the past have had to justify putting in miles of roads and pipelines and facilities and infrastructure. We don't have to do that because the roads are already there. We just have to go put this facility on location. So we take Canada Steel, Canada ideas, [indiscernible] in the U.S., and it makes a beautiful system that we've put in place. Not only is it kind of an international effort on the steel side, but even on the personnel side, we have a great operator coming from Canada that's been helping us on the Canadian side. He'll be -- he's working on this facility now and [indiscernible] successfully many times in the past. And then on the U.S. side, we have a professional engineer named Patrick Simon, who has vast experience doing Arctic work up on the North Slope of Alaska for groups such as Conoco. And so it's a great combination of Canadian and Alaska resources and technology to make the system work. So we look past the operations season of this summer and look into next winter. As I said, there's lots to do. This is our plan for 2023. It's essentially double the plan from the 2022 winter season we just completed. It's 2 new drills, 2 reentries. So starting on the new drill side, on the top left, Theta West #2. As said, there's lots to appraise in this reservoir, and we're going to take a -- take a way and go out and drill a new well to continue that appraisal and really continue our step-outs really show what's there. We spoke of the Shelf Margin Deltaic, and I want to highlight the Alkaid #1. We saw the Shelf Margin Deltaic when the Alkaid #1 was cut. And on the logs, the sediment looks almost identical to the sediment that was tested below in the Alkaid #1. And so there's absolutely great sediment in that well. We've left that well in a suspended state where we can reenter it. And so we intend to reenter the Alkaid #1 to test the Shelf Margin Deltaic. In the bottom left corner, the Talitha A, we've left that well to go back in it. So we definitely need to figure out what's happening there. Go back in, sidetrack the well, get back into the formation and make sure that we figure out the Deltaic and the Talitha A and get it to flow. And then lastly, on the new drill side, the Talitha B in the bottom right-hand corner. That's a new drill for a Shelf Margin Deltaic and a Slope Fan appraisal. Great sediments, good reservoirs. There's a lot to appraise and a lot to interact with. So we intend to go back out and do another drill. And just an update, and I revisited this slide. You saw this slide earlier in this presentation, but in the end of the 2023 winter season, all 4 of these formations will be well appraised. In the case of the Alkaid, it will be producing in with reserves. And so in Theta West, we'll have 3 interactions with the Basin Floor Fan. In the Slope Fan, we've cut it in 4 wells and produced it in 2 with very close analogs in the Alkaid wells. In the Shelf Margin Deltaic, that will make 8 wells worth cut in and finally, they give us 3 wells where we've tested. So we have a great opportunity to go figure that out. We've seen the sediment in lots of places. We've just got to go produce it, and we will. We'll get it figured out in the next winter. And in the Alkaid, all during that time, the Alkaid will be producing. So that is production, that is sales and that is results. So from there, we look ahead to the 2023 season. Summer 2023, opportunities just grow. We showed that the Alkaid is underneath the Dalton highway, but the Shelf Margin Deltaic is as well. So on the heels of the Alkaid #2, we'll take our learnings from that, and we'll go further. We've got another gravel pad to work with 4 miles south. And from there, we can continue our efforts, further wells, further production, further reserves. So the efforts on the Alkaid just really grow into next summer. Our ability to grab more rigs and do more work in Alkaid is very exciting. That's all there. The same concept applies. We can just go further, we can do more, we can just build. In the bottom right here, the Alioth well, Alioth is another star in the Ursa Major constellation. This is where the Shelf Margin Deltaic crosses the road. And so we have the same opportunity that affords us a long-term test that affords us production. It affords a certain that we have that opportunity in the Shelf Margin Deltaic. And so we intend to duplicate that system and go down in the summer '23 on gravel and begin production on Shelf Margin Deltaic. So this is a 4-well program for summer 2023. We believe we can do it with 2 rigs. This is the start of development. And that's a great segue into what development really means for these reservoirs. This is a development plan for the Alkaid. This particular development plan is the one that was accepted by Lee Keeling Associates and is reflected in their contingent resource report. This is 44 wells to develop the reservoir from 4 different drilling locations. The drilling location of the furthest west is the Alkaid #1. The other 3 locations are on the Dalton Highway. The location for the Alkaid #2, of course, to the north, we said we have a second location. It's noted here is the Alkaid #3 to the south. From those 3 locations, it's north of 30 wells that can be drilled and completed. And so with those 2 gravel pads, we can get over 20 and then -- or approximately 20. And then with the third gravel pad, we bolt-on more wells. This development starts, so we just keep going along the Dalton Highway. So yes, in the start of 2022, Alkaid is in production and moving into development. In summer of 2023, we're on to 4 wells in this region. And then from there, we can just keep going. So we can take that same concept and apply it to the Shelf Margin Deltaic. And that's approximately what you see here. In the background of this, the image that you're looking at is the lithology of the Deltaic. But overlaid on that is a conceptual development plan. It is to scale. So each one of those rectangles is a drilling location that would represent a surface location. And as depicted here is 12 wells per [ location ]. So that's 6 in each direction. Some areas on the periphery. You can only go one direction [indiscernible] 6 wells. But the big point of this development is it's over 400 wells to develop the Shelf Margin Deltaic alone. Of those drill sites, 5 of them are in the Dalton Highway themselves. So that's where the development begins. And of course, it begins there. You start with the infrastructure you have. So we can put locations along the Dalton Highway. The top 2 of those stars are the Alkaid locations. So I mean there's amazing synergy there, but we take these locations on the Dalton Highway and we begin the development. We learn how to interact, we learn how to optimize. We learn what to do with that. And then we spread West this time -- over time, we move West. So as we learn, as we grow, we build more pads, go out to the West. I mean, this is years of development. And what's fascinating here is it's not just the Shelf Margin Deltaic. This overlaps the Slope system as well. So when we look at 12 drilling locations from one of these pads, underneath, it's another 12 in the Slope system or more. I mean, this is an extraordinary opportunity and we can start it immediately on the Dalton Highway and be trucking sales. I mean we're ready to move into this. And it's -- I couldn't be happier about it. And looking even broader. So then we look at the shelf -- the Basin Floor Fan and how it dovetails in with the Shelf Margin Deltaic system. And the big punchline, you can just absolutely keep on going. I mean there's so much rock in the Basin Floor Fan and there's so much opportunity to spread and there's so much in using the same infrastructure, the roads and the pipelines. We don't have to build an 80-mile pipeline to get to any of these reservoirs. We started development on the road. We start heading West, and we just absolutely keep going. We don't have a huge cost of entry to get there. We start with a location and a facility on the highway, and we just add and add and add. And this we can add for generations. I mean Jay said it, it's a generational play. I mean this is hundreds and hundreds of locations, and it's stacked locations. It's -- my kids will retire before we can stop doing this. I mean it's -- the size, the magnitude is there's so much to do here and we can begin the development immediately. And so I mean this is the rough development concept. There's so many synergies to pick up on the way to sort of learn this. With each cut, we need to evaluate above and below. I mean there's just -- this opportunity to organically grow from existing infrastructure, move West and have such a scale of growth. It's an absolute world-class once-in-a-lifetime opportunity. And I couldn't be more excited to move forward with it. So I'm going to wrap it up, I get very excited about this, to come back to the absolute truth, we've proven oil in 4 giant reservoirs. I mean, the smallest of which is 1 billion barrels, and we're ready to go produce that. The oil quality in each of them is exactly where we want it. It's light sweet crude. It's got enough gas in it to help sustain flow and to help with our surface facilities and do what we need. But it's not so gassy as to take away from the oil deliverability of the system. And so 36 to 39 API is exactly where you want it. And in Alkaid, it's 35 API oil. And so I mean it's a validation of our hydrocarbon system. It's a validation of the geologic model that led us to -- that led the team to focus on this region. It was absolutely approved at this season. And then in this wonderful confluence of opportunity, the largest underutilized takeaway capacity being the Trans Alaska Pipeline system goes right over the top of it. That's 1.5 million barrels of unused takeaway capacity that goes to the Pacific Ocean. I mean this is absolutely world-class takeaway, a world-class market. And then on top of that, the only paved road in Northern Alaska goes from Prudhoe Bay right to our initial locations. I mean it's absolutely stunning. And we're ready to move forward with this. And I mean that's the biggest punch line. All this oil is here. We've absolutely proven it. We've absolutely proved it flow. We're ready to development -- develop it. And our production, our long-term sustained production begins in October this year.

Well, Michael, I'm so excited. It's hard to put it in words. But when I sit back and listen to all of the whole team, one of the things that came to mind as I was looking at is it's such a privilege to work with this team and see what you guys have accomplished. We had an incredible season. But more than that, we've had an incredible several years. Despite the challenges this season, and there were lots of them, we validated our predrill prognosis. Over 23 billion barrels of oil in place. Call it whatever, 10%, 11% recoveries; 2.3 million, 2.5 billion barrels recoverable. But if we add 5% recovery to that, it's over 1 billion barrels more. These are huge reservoirs. And as we've seen with Prudhoe Bay, big reservoirs get bigger and better over time. And I'm convinced that we're on the cusp of that. So I just want to say thanks to everybody. You're an incredible team. I love working with you. Now on to the Q&A.

Thank you, Jay, on to Q&A and just following on from your comments there, you'll see a quote from Bill Armstrong made this month in petroleum news, and it came to me as part of the questions. And I thought it was appropriate for everybody to read it and to think about it. And he says here that there's no other -- so there's no conventional onshore oil play in the world that has the type of potential that still exists on the North Slope. These massive shallow oil targets more than offset the Alaska challenges of weather, infrastructure and funding issues. And I think the perfect timing for this webinar is something to think about. One of the themes that's come through this webinar has been advantages that we as Pantheon have in location to the infrastructure, which reduces the disadvantage to many of the other companies up there, but also the challenges of funding, and to some extent, weather. Because it -- as we're seeing in the case of Alkaid, we'll have the ability to be active throughout the calendar, which is, of course, a massive advantage both in cost and in time. So with that, I'll get stuck straight into the Q&A. Before I begin, a big thank you again to Mr. Duncan. It's become a bit of a right of passage for him to curate our questions for us. As always, I've got a room of them, and we don't have enough hours in the day to get through them all but many have been covered in the course of the presentation. And so I'll remove those. And where possible, I will answer them myself or a quick one or combine them together so we can get through as many as we can. And just one thing I would say is I'm conscious of this presentation is very technical in nature. It's not intended to be like other company promotional-type presentations. We're not like other companies. This is -- we consider this to be a resource document. We're building a library of these resource documents over time that people can go back and refer to and get some understanding to the depth the science, the depth of the analysis that has gone on to support the statements that we're making. So with that, I'll kick off to the questions. There is a lot, and I've tried to group them as best as possible, but we do bounce around little bit. And I will try and choose the right person, I think, to answer the questions as we go through. And with that, actually, the first question is for our special guest Roger. Roger, I'm consciously you're still caught in with COVID. So I hope this is not too much of a burden for you. But the question, Roger, was -- following the drilling of Talitha, originally in 2021, you readjusted some of your modeling to better integrate and calibrate with the results we've found. How has that, after the calibration, how did that fared coming to this season? And have you had to recalibrate again following this drilling season? Or was there a really good correlation in efficacy in terms of what you did?

That question is easy. Didn't have to recalibrate it at all. It worked exactly right.

Okay. Thanks, Roger. That's great. I've got something similar coming up for Mike actually a little bit later. Yes, the big question that everybody is asking is Theta West. Sadly, we did have some weather issues and our season was cut short. We were still in the cleanup phase, as we know we've lost some time the cementing issues that Michael explained very, very -- in great detail earlier on in this presentation. But it meant that we had to terminate testing activities early. So unfortunately, we're still in the cleanup phase. We had some the given pipe diameters within the wellbore. Bob, can you please comment on or give some color over the pitying at Theta West and actually after that, on Talitha as well.

Well, it's an interesting question. I'd rather give some -- what I would do to say is give some color on Theta West and kind of expand a bit more on what Michael said. When we were drilling the well, just going back even a further step, when we were drilling the well, we were having problems with having tight spots in the well, not just 1 but 2. So we actually had to overcome some problems when we were drilling the well. And we had to make decisions when we were drilling about things like taking whole core. And because we had the problems with these tight spots in the well, we actually decided not to take whole core. And luckily, we didn't. Because if we had, we probably get stuck the core barrel. And when we actually hit TV of the well, we had to make a decision about whether we were going to run logs and run sidewall cores. And we decided not to. And part of the reason for that was we wanted to get the, obviously, get the casing down as quickly as we could. So we wouldn't have the borehole open for a period of time, and we didn't want to get our tools stuck in the hole. So we actually forgo that. And I kind of have 2 rules when I'm -- I haven't -- don't have a lot of experience in terms of drilling, but I always have 2 rules. One is secure the borehole. And the second one is once you're -- once you get screwed in with a problem, it's hard to unscrew you when you're in the well. So we made those decisions to forgo running sidewall cores and running logs so we get the casing down. But it still took us 8 days to get the casing down, right. The guys -- and I was there at the end. In years like I wasn't there when they started, but I was then I remember thinking, let's get it down. And the guys did. I mean they overcame the problems, and we got the casing down. And that -- but it took us -- did take us 8 days. And then as Michael alluded to in very good detail is we had a problem with the cement. And again, they overcame that. And that is kind of amazing kudos for overcoming those problems and getting us in a position to test the well. Again, we had the small sort of liner in the hole and we went in and tested the well. By that point in time, what we were really, really hoping for is that we would get white oil moving and movable oil through the testing. And that was our target. And at the end of the day, we got 57 barrels a day, which everybody was thinking, wow, given what's happened. This is a good -- this is really a good result. And we had to stop. There's just no way around it, we had to stop. We're at about 40-plus percent returns. We're still flowing back hundreds of barrels a day of frac fluid. But we are getting 57 barrels a day of light oil, which we could separate out and sell. And for us, that became a really good result. And as Michael has alluded to, I've given optimal -- given optimizing everything, we're going to see better results in the future. But even taking the results that we have today and taking the information we have today, we can commercialize this reservoir.

Thanks, Bob. I guess that's the key. Ed had spoken earlier on during his presentation about DMAX and so on and how are we expecting the reservoir quality to be improving as we moved from Talitha towards Theta West. 57 barrels a day, we're still in the cleanup phase. We had to stop testing early. But what you're saying is even that 57 barrels a day is enough to give us the confidence that this is a commercial field, hence, the resource that we have today and so on and so forth.

Yes. I mean, that's a simple message that we tried to put out in the beginning, during the middle and at the end. Yes.

Look, just sort of rapidly moving on. Just a quick question on the issue, the cementing issue, you have with the third-party contractor. Questions come in, and that is do we have any rights of remediation or reimbursement of costs or anything like that. Jay, have you got a quick answer for that one?

Yes. It's very difficult in the oil services industry to recoup really anything. Cost of the service is about all you can do.

And of course, maintaining relationships to going forward, Jay, we'll need some big -- high league type contractors. Bob, we have a question here on independent experts reports. What are your plans for an IER for one or any of the projects?

Good question, Justin, but I think I'd like to try to answer that in 2 parts. We're starting a process to build what we call this thing called a geo-cellular model. Or another way to look at this is a 3D visualization of the subsurface. And we're working with Schlumberger to do this. And what we're trying to do is give a visualization of all our reservoir plays, that's Shelf Margin Deltaic, Slope Fan, Alkaid and the Basin Floor Fan. And have an institution detail to aid in the development and execution of those projects. What we're doing is we are building models where we integrate all the well data, 3D seismic. And what the output is, is a volume-based realization of the reservoir distribution across the entirety of our development projects. So all the reservoir realizations have included in them, depositional facies, porosity, permeability, predicted outcomes. So the final product of all this is each reservoir realization will generate a predictive reservoir effectiveness and a performance volume with oil in place and an expected range of recovery. With that, I can then go to an independent expert. That's not the primary use of the tool, but it's a great tool in terms of having the independent expert be able to see in a complete volume all our data set. For us, it's going to be the tool to help appraise and develop these different projects, and it's going to be the tool where companies or people that are interested in investing with us in these projects are going to look at. So eventually, we'll have this done, and we hope to have it done in the fall. And then we can move to the independent experts' reports.

A quick question for Mike, if I may. It's on the VAS work you did. And the question revolves around the quality of the -- or the efficacy, should I say, of the work last year on Talitha versus what we saw this year on Theta West. Could you comment on that, please, Mike?

No, I'm going to interrupt that because I'm going to comment on it because we are -- Mike was 4-for-4 in terms of his prediction and what the results are. He's -- several times that he's done this work independently. So from his analysis, he was saying you will get movable light hydrocarbons from these zones and a prediction of the API. That is phenomenal piece of work that he's done that comes from just his analysis of the cuttings data. So that's the comment I would make. And it's independent, and my view is, if you don't -- if you're not doing this work, what you're scared of is having Mike walk into the room and say, what you're saying is not correct. Because he's very blunt.

So the correlation, Bob, from Mike's work to the work that we saw, you mentioned the plan was excellent, was it?

It's superb. I think every single techie on the call here would say every time we listen to Mike, we learn something new.

Fantastic. Look, just swiftly moving on, the aerial extent of the Basin Floor Fan, we've obviously seen a resource upgrade just coming through. But could you comment on that? It was 10.5 miles between Talitha and Theta West. Has our view on the aerial extent of the Basin Floor Fan expanded or changed?

The -- I would say our confidence level -- the important way to think about this, our confidence level of the extent of the Basin Floor Fan on our acreage has expanded and our confidence level has gone up. So that's part of the reason why we have had the resource upgrade. I'm sorry, Justin, did that answer the question or you would like me to answer....

Yes. Actually, Bob, it led into another question further down. This was on the commercial chance of success. We spoke about your thoughts on that prior to the drilling season. I just wondered if your thoughts on that had changed subsequent to the drilling and testing that we took this winter?

Absolutely, it's changed. It has changed. And I've -- we're much more confident now than we were that we can make these reservoirs work commercially.

Yes. Bob, again, in this petroleum news [indiscernible] very, very recently, Bill Armstrong made this comment, and I wanted to read it to you and ask you if that is valid in thinking about our place as well. And what he said was, he said "most of us are now chasing the shallower Brookian plays, in particular, the Nanushuk," which I believe is our SMD, but you can talk on that in a second. Since we found to pick it up, there have been 33 wells drilled that we know of that has targeted the Nanushuk topside play of those 31 have been discoveries for a 94% success rate. There was not a play on the planet that has that kind of wildcat success rate. What are your thoughts on that, Bob?

Well, my thoughts on that is we've been -- we and I mean, there's Ed Duncan here. And he's been saying that very early on, and I'm going to put into we've been saying that since probably '19 -- sort of 2013. So I think Bill is correct. I think our acreage has the equivalent of the Nanushuk play, which is the Shelf Margin Deltaic. And I think we've got, in terms of the Theta West, probably one of the largest cumulation found anywhere in the world in a long time. So [indiscernible]

Bob, we're just losing your signal. I might -- I think we've got the message here. I might quickly move on, if I may. Jay, you spoke about recovery factors a little bit earlier, and they're quite important, I mean, partly because of the power of mathematics working conservatively on a 10% recovery factor versus numbers as high as 40% elsewhere or is actually higher, but 40% of TAM. I think you mentioned a 5% increase is actually, in relative terms, a 15% increase. What sort of range could we be hoping for out of these fields?

Well, I think once we understand the fields and drill them correctly and possibly do secondary or tertiary, you can get 20% to 30% out of these relative fields. And I mean, that translates into huge numbers, very long.

Bob, I noticed that the resource statement presented earlier in this presentation by Jerry, which showed oil in place of over 23 billion barrels of oil. It didn't include the Upper Basin Floor Fan or Kuparuk. Can you explain the reason for that, please?

Yes. What we are focused on now and how we visualize ourselves as a company is we're now into appraisal and development and production. So the numbers we've put out there are numbers that are associated with reservoirs that we believe are now proven, i.e., have tested light oil, even the Shelf Margin Deltaic has shown that it has light oil in it. We didn't get a flow out of it, but all the other reservoirs have tested light oil, Alkaid, Lower Basin Floor Fan, Slope System. Everything else, they're to be tested. So we don't want to kind of mix apples and oranges. And so the numbers you're looking at are the ones where we've tested hydrocarbons.

Okay. So for the avoidance of doubt, they haven't gone away. It's just that you're now wanting to present it in with respect to the horizons that have actually been tested. Is that correct?

Correct.

Good stuff. And actually, while we're on topic, Bob, there is a question here on the Upper Basin Floor Fan, why did you not test the Upper Basin Floor Fan at Theta West?

Out of time.

I think we all know that that's quite self-explanatory. Jay, a question for you, if I may. Given the enormous size and scale of these projects that we've outlined today, I think you mentioned earlier in the presentation there could be generations of drilling. With that in mind -- and you also spoke about the leverage of improvements in things such as recovery factors, given we're using a base case of only 10% right now and some of the other projects after the North Slope are many multiples of that recovery factor. My question is, could we benefit from things like technological advances or anything else as the project evolves over time?

Well, the short answer, Justin, is, of course, yes. And I'll just give 2 really quick examples. One, I've already talked about, which is Prudhoe Bay, which originally was 10 billion in place and 3 billion recoverable and now is 33 billion in place, and we'll recover more than 16.5. Part of that is growth, but a huge portion of that is technology. The other thing I would mention is in the late '80s, when horizontal drilling was first implemented, a 500-foot lateral was considered a really good outcome. And now 20,000-foot laterals are normal. So yes, these reservoirs will benefit greatly from improved technology. And as Michael explained, just improved knowledge.

Jay, another question for you. We previously spoke about our visions for Green Energy, Alaska. We didn't mention that specifically in this presentation today, but does that remain the vision of the company?

Yes, absolutely, Justin. It's still our vision, and we can move very easily from the facilities that Michael was showing earlier in the presentation to reinjecting all of our emissions back into the reservoir, which is what we planned when we have full scale development.

Great answer. Look, a couple of corporate questions. The first here is whether we would consider an additional listing, perhaps in the U.S. or perhaps a listing in another territory -- the answer is, yes, we're open to everything. We're reviewing them, and we'll make a decision that we think is the right decision for the company. Lots of things to consider. It's not a promise, but we are certainly looking at it. And if we think it makes sense, that's something we'll definitely consider. While on topic, I've got another one here or another couple of questions actually on the topic of PR and our news flow. The question asks whether we intend to ramp up our PR. That's a great question, and it's a question that comes back to me regularly. Ultimately, as shareholders were invested in the stock price and we're looking at making a return. But we as a company to balance that with building a proper company, there is an obsession sometimes among shareholders to keep promoting to get the share price up. That's not who we are. We're trying to build a proper grown-up blue-chip company that's worthy of attracting institutional investment. That capital will allow us to grow that company and to pursue our strategy of proving up and selling at the right price. That's not to say we're not doing things. We are. Shareholders don't always see it. We have a great PR group here in the U.K., who help us significantly. We're in contact with the group in the U.S. We're doing other initiatives such as the webinar we're on today. This is probably our fourth or fifth of such webinars. We'll continue doing these to build up a resource library. Bob and his technical team are now commencing a process of doing technical presentations to industry. They did -- I think Duncan did one recently to a group up in Alaska. In fact, our whole technical team are going up for a technical group think tank in the next couple of weeks to get up to Alaska to work together. So we're doing lots and lots of these things. But the question on public relations and PR and news flow, for something to be picked up on the press, it must be newsworthy. And the nature of our businesses, it can be a little bit lumpy depending on the drilling activity. So -- and also, of course, as we all know, news has a limited shelf life these days because there's always something else happening pretty rapidly. But -- so we're definitely making a concerted effort to be vigilant about getting our story out there. It's important to us. Yes. And that leads into the second question here, which is similar but subtly different. And that's whether or not we intend to change our strategy as a company on RNSs or stock exchange announcements. And the answer to that is no. We must be consistent and we must be conservative. We're aware that other companies have different approaches, some are a lot more promotional than we are. That's not who we are. Again, we want to build a proper blue-chip grown-up company, and we must be consistent in the news flow that we deliver. So we'll deliver news flow when it's price-sensitive, and when it's required. We won't comment on speculation. We won't get called up in what social media was talking about. We'll deliver news when it is. You'll never pick up the newspaper on Pantheon on the weekend and hear about a scoop that's coming out on Monday morning. That's not who we are. We play it by the book. We're going to be consistent, and that's what we intend to do. As the company is growing and as our activity is growing, naturally, there'll be a greater flow of information coming through that will feed through to the PR as well, of course. But in terms of our strategy for Howard writing RNSs and stock exchange announcements, the announcements will be as consistent as we can. And we hope that investors can see that consistency. And of course, in tracking institutions, that's something they want to see to -- they don't want to see promotional stock exchange announcements clearly aimed at trying to spruik our share price. Bob, earlier in the Q&A, you mentioned that we didn't obtain sidewalls cores or whole core data for Theta West. Can you discuss what information and what data we did obtain in that well?

Sure. We did a very extensive logging while drilling sweet. So we got a good set of electric logs that were associated when we were drilling. So a good set of electric logs, disappointed that we didn't get the sidewalls.

Bob, but electric logs or LWD, there's been some real advancements in that over the last 10 years or so. So my understanding is you've got quite rich data for that. Is that correct?

Yes, that's correct.

The next couple of questions concern more corporate matters to do with the company. The first question is one of funding, which, of course, is influenced by the proposed drilling programs or proposed drilling plans planned for 2022, 2023. One of the questions is, how is our cash position? And do we have enough funding on hand to pay for our proposed drilling program? And look, what I would say is, as of 30th of March, we had over $70 million in cash on hand. There was some drilling costs still to come through. But by far, the bulk of those had already been covered off. So we're very well funded. I think the Alkaid well, our budget is unchanged for that. It's about $23 million. The vertical test wells at Theta West and Talitha in the future, obviously, lower cost, significantly lower cost than the Alkaid will being a horizontal long-term production test. So we have enough cash on hand for a number of wells. A more aggressive program, as Michael has outlined, would require additional funding. And that leads into the question of whether or not we still consider another farm-in or other form of funding. Jay, did you want to comment on that?

Yes, Justin, of course, we'll consider a partner, a farm-in. And as we have shown in December of last year, we're perfectly capable of funding on our own, if a partner offers us the terms that we like, and we'd love to have a partner in this with us.

Thanks, Jay. And look, this is a bit of a buck beer of mine. I get -- not a week goes by where I don't get half a dozen questions on dilution and funding and so on. Look, here we are in April of 2022 with 100% of all of these projects and $70 million in the bank. So far, we've managed it pretty well. Yes, we did go down along over the potential farming partner prior to the season. Ultimately, we didn't conclude that transaction. As we previously disclosed, it was a phased earn-in transaction from a minority position for a 10-digit number. There's a question here specifically on that, and that is for the same partner, if we were to contemplate another transaction, would the terms have changed? Look, just very quickly, in the interest of time, I would say, certainly, yes, they would have changed for one, the oil price is higher. Every oil company in the world has assets which are now worth more than they were, other things being equal with the higher oil price. But secondly, of course, as the last 1.5 hours has just shown you, our projects have advanced dramatically. The risk has gone down. The confidence has gone up and the resource number has gone up. So yes, the terms would be different. There's a question here on that exact point. Has there been increased interest from the super majors? And again, I'll quickly tap into that, Jay and pass over to you in a second. Again, there's a fixation with having a major as a partner. We touched on this at all of our webinars, actually. And I think the answer is be careful what you wish for, a super major sounds great because people have comfort in a brand name that is a known quantity to them and because they typically have a larger check book. But it brings out the issues too. And the first -- and I know, Jay, this is your buck beer to control, no super major company is going to come into a project with us without insisting upon control. And at that point, we become a passenger, and we become subject to the internal machinations of that particular company, their strategy and their timings. Additionally, with success we could find a position with a try to outspend us and dilute us that way. So we need to be careful about the partner that we find. Bob, I've got a question for you, and it's on the benchmarking picture. A lot of people have spoken about gave some mix and color on Pikka earlier on today. People are focused on this $3.10 per barrel that Oil Search now owned by Santos in Australia paid back in the back end of 2017. Our understanding is that probably paid about that much again on the assets since they've been there and there's still -- what appears to be quite a long way away from getting to first production. If you reverse the numbers out for Pantheon's continues to resource by its market cap. Our value per contingent resource is about 1/4 of that. Bob, are there any key differences between us and Pikka that would justify that valuation difference? Or is there anything you could add to that discussion?

I think our whole presentation is based on the fact that our location is -- drives our commerciality. -- and drives our valuation and drives our timing to production. I think Michael's presentation, the summing up of it and the details of it is about how we, the smallest company in the conversation, will be on production, selling oil in the fall with $1 million infrastructure build plus the cost of drilling the well, we will be selling oil in the fall. And that to you everything about NPVs, valuations, commerciality that you need to know.

And I think everybody sort of reiterated at that point. On Jay's slide, there was a heading that said location, location, location. Michael spoke about developing this thing from East to West not necessarily because the eastern assets are our biggest or best but because that's where the infrastructure is and it makes sense to move away from those. So really, really -- a really important point. It means everything Net present value is a function of discounting cash flows back to time 0. So time is a very important element in that. And you can't get -- if you can't get the production, it makes that discounting pretty, pretty heavy. So it's a really, really significant advantage for our company. Ed, I've got a comment for you, if I may, and it's another Armstrong comment, but he says here "In this month, April 2022 that the management play on the North Slope is undeniably the greatest onshore conventional oil play in the entire world." You've been -- you're a bit of a pioneer like, Bill, I guess, to some extent, in Alaska, you founded Great Bear Petroleum initially over 10 years ago now. What are your thoughts on that comment? And perhaps how it reflects upon the play that we're pursuing at the moment?

Well, Bill's certainly a successful entrepreneur and very good at promoting his projects. The Nanushuk is a successful play, at least in the context of exploration. Very little oil has been produced out of the Nanushuk and very little oil will be produced at the Nanushuk for years and years and years to come. The comparison across the Slope from -- by play type at least, whether it's Nanushuk or our companion which is I'll be [indiscernible] our companion as Shelf margin Deltaic, which would be the equivalent play. The real thing that drives this, and it really -- this is also relates back to a comment that Bob made that -- or that Bill made, and Bob commented on about success rates. The thing that's driving -- the success rate, the thing that's driving our success in our portfolio is the fact that with 3D data and modern processing, we can see the pay. And that's what's driving the success rate in the Nanushuk. It's not something magical about the play itself. It's the fact that data has been collected that allows targeting, very specific targeting in seismic responses that have been calibrated to oil pay. We're doing exactly the same thing in our projects. And in the old by the way, we're batting 100% when we're targeting seismic amplitudes.

Fantastic. Thanks, Ed, for that really great feedback. A question for Michael, and this is more operational and the impacts of inflation that we're seeing in the world today. Are we seeing any impacts of inflation and/or any supply chain issues that may impact our drilling activities going forward?

We are. On the commodity side, especially things like pipe, steel, we have seen a price increase there. When we look at the Alaska industry in general, rigs are purchased. There's no new rigs, they're underutilized. There is personnel available in Alaska. And so there are portions of this that we've yet to see the increase on. There are portions that are more commodity-based like steel that we have. We'll see how it unfolds. We haven't seen it change our AFEs yet, but we are seeing some inflation and some minor price changes.

Good stuff. And of course, look, we all know what happened in the oil industry post COVID, it took a real nosedive. And we saw a real falloff in capital budgets for exploration. We're seeing the benefit of that now with the fuel price in terms of these supply shortages and a lack of large projects on the horizon. So I guess it's a sort of quasi hedge against that pricing increase. In the event of success, we're picking that up in terms of a stronger oil price. So look, thank you for that. A quick question here, which I'll read, you can't really comment on it. It's a question. One of the neighboring companies, neighboring Pantheon's acreage has made a number of recent statements comparing Pantheon's acreage to theirs, and there was a question as to what our comments were on that and what our inferences were. And I think as a rule, we as Pantheon, don't comment on other companies projects which saw the very, very best of success, particularly in Alaska. Everybody's success is welcomed, but it's not something we're going to give any comments on. The Kuparuk has come up. Again, really exciting project for us. But the question is when would we plan to drill the Kuparuk, and is the zone that may be targeted from another upcoming -- a planned upcoming drill? Bob, I guess this is one for you. It's probably a matter of priorities. I would have thought.

Yes. I mean our -- exactly. Ultimately, when we drill, my guess will be when we drill a Theta West appraisal well, that we can -- we will be targeting one of those wells. Eventually we'll be targeting the Kuparuk when we -- in the future. I think that the next Theta West appraisal well that we drill is going to be too far to the west to test the Kuparuk. I mean I have to look at the map, but I just can't see that happening next season. But we will do it -- but we're -- there's going to be a lot of wells drilled and we will do it.

Justin, to comment on that, the really quick to depth and the pressure of the Kuparuk may also require higher pressure-rated equipment and some custom equipment that isn't -- so it needs to be a very targeted effort when we do take that step because it will require a little additional effort on the pressure temperature side.

Yes. Understood. And just generally, I think this has come through in the presentation, too. But as a company, the Alkaid is of great importance to us now, particularly with the ability to come into production and generate cash flow for the company and for that to roll out to a full-scale development program. That's what our company needs at this point to turn us from an appraisal into a proper producing company. It attracts a different investor base and generates cash flow to fund operations, minimize dilution. So yes, look, great feedback. Thanks. A couple more questions here. Finally -- not finally, but one of the final questions is, Jay, this is one for you as the CEO. We've spoken previously about this prove up and sell strategy. We've been quite unashamed in saying that, that is our strategy. Michael has given an indication that there's hundreds or thousands of wells to be drilled over generations to our belief, by the size and scale of this project. Jay, what's your thoughts on this prove up and sales strategy? And where is the sweet spot?

Well, I'm not sure exactly where the sweet spot is, Justin. But the way to maximize the prove up and sell is to do exactly what Michael has laid out. go forward with our development plans and prove what we have, then we're going to be a very attractive target for lots of companies because of the size and the scale. And as we've said, the generations of development, which is exactly what big companies like to do. They like to spend billions and billions of dollars, making a good return over a period of time. So not sure where the sweet spot is. I wish I were younger, still prove up and sell is a good strategy for us.

It's really interesting, and you and I have spoken about it a million times, but additional days we get, it's a sort of hyperbolic value curve for the company at this point in time given the size and scale of the projects. Is that a fair comment?

Absolutely. Absolutely. If we're right, and let's say -- let's just -- let's pick this Santos Oil Search number. So they've invested -- they bought in for 3. They've invested in another 3 at least, probably more than that. And they're still years away from production. And we apply that number to our what we think producible resource potential reserves are. I mean we're in order of magnitude, larger market cap than we have now. So it's hyperbolic.

Yes. Great. And just there's only a couple more questions to go, guys Then I think we can wrap up, given the time. I'm just slightly circling back to this farm-out question, would we consider it again. The answer is, of course, all options are open, and it's not just farm out or possible equity or some sort of other structured finance product or we've got our eyes open. We're open to all opportunities. But what I would say is we're in a much more privileged position than we have been previously with a healthy cash balance and some great data and some significant sizes with increased cost level and increased data in these projects allows us a much stronger negotiating position. And we don't need to take -- we're not -- we've got other -- we have more options available to us, I think, is probably the best way of saying it. We're not as desperate to do a farm-out as we may have been perhaps in the past. Look, with that, guys, I think we've covered everything off. As it's become a bit of a tradition for Pantheon at the end, I'd like to just pass around to a couple of you and just give your final comments, if there's anything we've missed or if there's anything that you'd like to say, anything that sort of appeals to you that may not have been highlighted as much as we could have otherwise highlighted. Jay, I'll finish with you at the end, being the CEO. Bob, just the geologist, you set back a little bit in this presentation and let some of the team to do some talking. What's your view at the end of the season, we've tested Talitha, we've drill Theta West and done our best we can to get some testing there. What's your take on the season and what it means for Pantheon's future?

Well, it's an incredible season. We have found, tested, proven that we have this enormous accumulation. We keep coming back to this phrase, which is resource density, possibly the largest -- highest resource density accumulation of hydrocarbons that have been found since Prudhoe Bay and North America. We can say that with more confidence now than we could before. We can say with more confidence that we can commercialize these -- what we found. I mean that's -- it's an unbelievable season. And we think it's an unbelievable 3 years. So I mean, the story now is turning it over to Michael and his crew and getting the oil out of the ground and first trucking it up the highway and then plugging it into the pipeline.

But it's a perfect segue to Michael. Michael, great season of drilling. We actually had the privilege of zooming in on new while you were there. We had some great photos and videos and things coming through from location as well. But look, you mentioned to me many times when we spoke that actually, when you're drilling a new well, you're always -- as much seismic you have, you're always encountering things for the first time, too. So there's a really great improvement curve that's natural in any reservoir as you start to drill your second and third and fourth well. A classic example is in Theta West. I think you mentioned we had these swelling clays. That's something that we couldn't see on seismic. But in the next well, you just run your [ exiting ] program a bit deeper and the problem is no longer a problem. What -- if you could give some thoughts on how this may -- you gave a very -- a great presentation before, we could see your enthusiasm. But is there anything we've missed or anything you'd like to say about the drilling and how we would see that evolving going forward?

Absolutely. I have such enthusiasm for world got ahead and what we've done, but also the enthusiasm for our team and our internal capabilities. We've got just some world-class people, some of the best logistics on the planet. Our drilling capabilities are really going through the roof and our new facilities group is absolutely stunning. And so our team is really growing as our assets are. Our capabilities are coming together, and it's very exciting to watch talent and watch abilities from different areas come together and be in the right place at the right time. And so that's the real excitement. Not only are we learning, we're growing our capabilities, and we've accomplished great things. And we've got the right team in place to really continue to improve and continue to really show off what we can do operationally. It's a very exciting time.

Can I add to that, Justin? I'd just like to add my thoughts to that, is that in a few months' time, Michael has put together an amazing staff of people to execute across the board. And that's something we haven't really talked about at all in this webinar is that where we were sort of 5 months ago and where we are today in terms of the people that are now on board to help us execute. So I think that's a great point, Michael.

Thank you. It's really world-class people on this team, and I'm fortunate to be able to work with.

Look, Bob. Thank you very much for those comments. Ed, one question for you, if I may. You were the original founder of Great Bear. So this is a -- so 10 years in the making, how is this vision change or evolve? You've seen the data from drilling. I know you were on location this winter, muxed up with the guys down there at the Theta West and the Talitha. How was it changing for you in terms of the data we're collecting our drilling capability and the vision for the future?

Well, it's actually -- we started the process, and this really relates back to the earlier comment I made. We started the process in 2012 of collecting 3D seismic data and being consistent and focused and committed to collecting seismic data across the entirety of our position. And that investment that we've made over the years is really truly paying dividends now. We expected the inventory or the portfolio opportunity set, if you will, to grow as we analyze the data. We've seen that happen with Alkaid. You've seen it happen with Talitha. We've seen it happen now with Theta West. So the very broad vision, the very beginning in the company particularly as it applies to exploring for conventional-type reservoirs in the Brookian succession is very much alive and well and in line with what we hoped for back in those days. And I think the broader vision that we had, that is now actually crystallizing into very specific actions and executables. And as Bob and Michael and Jay and everybody actually on the team, our e-size partners have illustrated, we can see and we can see what we want to do. And now we can execute and make it happen. So it's just an extraordinary thing to see. It makes me very, very happy that we've got the commitment and the team in place to continue this because it's just an extraordinary group -- our portfolio is an extraordinary grouping of assets that I think are second to none. Bob said it well, highest resource density probably in North America. And you could take all of the oil in place and the manager plays that have been -- [ manageship ] discoveries that have been announced, all the oil discoveries that's in Conoco's portfolio and now Santos portfolio and put them inside that yellow shaded oval on a map that I presented. And they probably total up to about 50%, maybe less than the oil in place that we have in our portfolio.

Yes, amazing. Amazing. So look, Ed, thank you so much. And thank you to all the other presenters, particularly our special guests, Mike, Roger. I mean, Roger is suffering with COVID and still soldering on. So thank you very much. Mike, as always, just we really treasure the input from the expertise that you guys bring to the table. It's something special. For our team, you obviously, we just heard from you, Michael, Bob, Jay, of course, who will start off in just a second. And not to forget Jerry, our little [indiscernible] in the background there. Look, just as I'm passing off, one comment that I'd like to make is that I speak to everybody or interface with everybody in the market. I read into Pantheon. And there's been, for a long time, just a sense that it's kind of sounded too good to be true, a lack of believability. And I'm conscious this has been over 2 hours now on this webinar. We've got a number of these. Again, these are resource documents, I know people that do half an hour a day, but they work through them, they go back [indiscernible] them, revisit them 6 months hence or 12 months hence or whatever. And this will continue to build this up going forward. It's not what other companies are doing. We don't care. We're doing it our way, and we think it's the right way. And we're building up this knowledge base of the company. So you can all see the enthusiasm is genuine. We've got an elephant by the tail. We really believe that. And it's now our job to exploit it at a minimum dilution to shareholders. We've got 100% still. We're in a great spot. And with that, I'm going to pass over to Jay for some closing words. Thank you for everybody's time, and then we'll sign off after Jay. So thank you very much, Jay, over to you.

Yes. I would just say that proof of this season is in the fact that we are now building out a development team. And we've been so judicious in the way we've spent shareholder money, and we are now confident that we are going forward to build out Michael's team. And it's just -- it's so gratifying to do that and to turn everybody loose on getting it all out of the ground and selling it.

Well, thanks, Jack. I think we can sign off. Good evening, good morning, wherever you may be in the world. Thank you very much, and we'll speak to you the next webinar, hopefully, before the commencement of operations at Alkaid sometime in July. Thank you very much.