Pantheon Resources Plc (PANR) Earnings Call Transcript & Summary

Hello, everyone, and welcome to Pantheon Resources webinar for our technical update. Before we get into it, I apologize for the technical issues we had yesterday and we simply made a very difficult decision, because this technical update is really a resource document that we couldn't do it unless we were fully satisfied that all the tools at our disposal were working. So we made that difficult decision to delay by 1 day. So thank you all for joining today. Good afternoon to those of you in Europe. Good morning to those of you in North America. And good evening or good night to those of you in Asia. You don't need to see me at all. I'm Jay Cheatham. I'm the CEO of Pantheon. I'm going to turn off my camera before I introduce everybody. So on today's webinar, myself, Bob Rosenthal, our Technical Director; Justin Hondris, our Finance Director. And then we truly have an all-star lineup from eSeis, Roger Young, Chief Technical Officer; and Dan Hughes to go through their seismic petrophysics. From AHS Baker Hughes, Mike Smith, the President and Founder to go through his volatiles analysis. Ed Duncan, a geologic consultant to Pantheon, who will take you through a brief regional geology of the area and why Theta West project is truly unique. Jerry Nichols, another consulting geologist for us, we'll do the volumetrics and then a 3D video of the subsurface. And if you're like me, I'm a visual learner, and that is just really fun to see. Finally, I'll wrap up with project economics after Jerry does his volumetrics. So to set the stage for the people that are new to our story. This is a map of the Alaskan North Slope. To the north is the Arctic Sea. Why are we the North Slope? The simple answer is it's where the oil is. There are giant multibillion barrel oilfields here, anchored by Prudhoe Bay, discovered in the late '60s. When Prudhoe Bay was originally discovered, it had an estimated 10 billion barrels of oil in place and 3 billion barrels recoverable done by DeGolyer & MacNaughton. Today, Prudhoe Bay is 33 billion barrels of oil in place and will recover more than 16 billion barrels. It will recover more than the original estimate of the oil in place. It's simply an indication that good, big oil fields get bigger and better and we'll show that to you on our acreage as well. To the west of Prudhoe Bay is Kuparuk. It has more than doubled in size now to 7 billion barrels. Going further to the west is the Alpine field. Now Alpine was discovered by Roger Young and Dan Hughes, when they were at Union Texas Petroleum. It has more than doubled in size. It's on its way to over 1.2 billion barrels recoverable. Why else are we in Alaska? It is a stable economic environment. We have very, very low royalties on our acreage, .That's outlined there in gray, about a 15% average royalty. We have 1 royalty owner, the State of Alaska. It is basically an under-explored basin. Now normally, you need several hundred million barrels to be economic on the North Slope, but you will hear this over and over today. Because of our location, we can make accumulations much smaller than that economic and they are. We have about 160,000 acres. We have high-graded this acreage from a much, much larger acreage position. The area to the west of our 2 units, that's outlined as Theta West, we have 9- and 10-year tenure. And on our units, Alkaid and Talitha, we have permanent tenure as long as we are carrying out the scheduled work program through the state. It's all 100% working interest acreage. We can do 2 of these developments from the Dalton Highway, and the Dalton Highway is simply the feeder road that delivers material to the North Slope. Now 2 weeks ago, I was driving the Dalton Highway. I drove the Dalton Highway from Fairbanks to Deadhorse, camped out, spent 3 days. It was glorious. It was fun to drive along the Dalton Highway and see the Trans-Alaska Pipeline, which runs right along the Dalton Highway. It was like a Tinkertoy set sitting out there. So we can do 2 developments from the Dalton Highway, Alkaid and part of Talitha. Now because of its location, Alkaid, our smallest of our projects and something that's 100 million barrels or slightly smaller, we can develop it. We can do it year round from gravel pad set along the Dalton Highway, and have high net present value per barrel. It is because of the location. We are not saddled with the long distances and other environmental issues that can happen when you're further away from the main infrastructure of the Trans-Alaska Pipeline and the Dalton Highway. Now our 3 projects combined, Alkaid, the Talitha Shelf Margin Deltaic and Theta West have a combined 1.9 billion barrels of contingent resource. Now by comparison, in 2017, when oil prices were lower, Oil Search paid $3.10 a barrel for contingent resource barrel on their Pikka-Horseshoe development to just enter that development. And you can see where it's located, much further away from the infrastructure. By comparison, at today's market cap for Pantheon, we are below $0.30 a barrel or a contingent resource barrel. Now Finally, the management teams. We all have deep experience, deep experience overall and deep experience in Alaska. We plan to prove up and sell this asset. For many on our team, this is our last endeavor, and we plan to exit with a big win. Now I mentioned how do big oil fields get bigger and better? Well, you get bolt-on fields. But also, we have 16 billion barrels of oil in place from the 3 projects I mentioned, Alkaid, the Talitha Shelf Margin Deltaic and Theta West. At our recovery factor, around 1.9 billion barrels, we're in the low teens on recoveries. What if we improve that by -- from low teens to the mid-20s, we double that resource or that reserve. Also not included, the Shelf Margin Deltaic [ ANC ], the Slope Fan and the Kuparuk. So next slide, please, Justin. What are the key points? As I mentioned, 1.9 billion barrels contingent resource recoverable, growth potential, and I didn't mention the number, but about 200 million barrels is accessible from the Dalton Highway. This presentation, highly technical is a distillation of thousands of hours of technical analysis. All of the work that you'll see here and the drilling that we've done has reduced greatly the development risk, and we have 100% working interest in these projects. In red, that's a quote from IHS Markit. I don't need to read it to you, but it is about the Talitha-A well. So just to recap the webinar agenda I've just done the introduction. Roger's going to do the Talitha-A update. Mike Smith's going to do the volatiles analysis, then Ed Duncan, then back to Roger. And Jerry for the volumetrics And on all of our fields, I'll do the development economics. And finally, we'll do the video presentation and have our Q&A. So before we get into it, we've got 2 slides to show you just an outline of what we learned from the Talitha-A. So this is the outline of our units. You can see in light blue, the Theta West outline. That will be discussed today. Next slide, please, Justin. And that is an outline of the Shelf Margin Deltaic B. That's the change from what we've learned with Talitha-A. And now I'll turn it over to Roger.

Great. Thank you, Jay. We're going to get into the log analysis. And what I want to share with you is log analysis is an interpretive process. It's interpretive because we don't measure how much oil there is with logs. What we measure are things like how fast the sound go through the rock. What's the -- what does the rock do to gamma rays? How does the rock interact with new tranche? What's the conductivity of electricity in the rock? Obviously, none of these things are things we really want to know. We want to know how much oil there is. So we integrate all this information or invert all this information to try to sort out how much oil we have. As you can see, there's room for error, room for interpretive biases. So what we do is we take rotary sidewall cores and in this well, we took 100 rotary sidewall cores throughout the whole section of rock that you see there on the left. This allows us to ground-truth the log analysis so we can really get a comfortable answer on what's going on. Because this is such a long, over 0.5 mile of gross reservoir rock, I'm putting the -- on the left side, the log analysis of the whole section, just so you have some perspective of where we are. We're going to start at the bottom at the Kuparuk. And the first thing we're going to look at is the lithology results from the log analysis. Shale is green, sand is yellow. This green here is oil, and these are heavy minerals. Now on the next track, what you're seeing is the amount of oil in green, but you're also seeing a lot of dots. Each of those dots are core points. So as you can see, we've got quite a few core points just in the Kuparuk and the HRZ above it. And what we're measuring in that track is the porosity of the core compared to the porosity of the log analysis. And as you can see, there's a very strong relationship between the 2. When we go to the next track, what we're looking at is the water saturation. So this zone here where the Kuparuk is, that's the most interesting zone. And you can see that the water saturations from the core highly match the core saturations from the log analysis. The following track is the mobility that we see from the core. When it's green we're seeing oil that has moved through the rock. When it's black, like up in the HRZ, which is a source rock, that oil is not movable. And then the final track that's interesting is this, that's the permeability track. So you can see that there's a [ great ] relationship between the permeability and what we calculated from the core. So overall, what we see in the Kuparuk is it's filled with oil, both from the rocks, from the permeability. We have movable oil. The Kuparuk is a good reservoir. And you're going to see, from Mike Smith afterwards, that his analysis also shows the Kuparuk to be a very good reservoir. I'm going to move uphole now, and we'll go to the Basin Floor Fan or the Theta West Rock. What we're looking at here it's over 600 feet of rock that's filled with oil. You can see the great relationships between all the core points and the log analysis porosity. And you can also see that I am still being very conservative about that correlation. I can very easily scoot everything to the left, make things a little bit more porous than they actually -- that I actually have currently. But I'd rather be conservative than overly optimistic. In the water saturation track, you see a very nice correlation between the core points in the water saturation and also notice how movable that oil is through that whole entire section. We'll move up now to the Basin Floor -- the upper Basin Floor Fan, so there's the huge shale between these 2 fans and then the Upper Basin Floor Fan is in a very distal position. But nevertheless, even though it's so distal from where we think the reservoir is really good, it's still filled with oil and it matches -- that the logs and the core match. Move up further to the Slope Fan. These aren't even included -- the Upper Basin Floor Fans or Slope Fans these aren't even included in the contingent resources that we're showing you today. But as you can see, there's still a lot of prospectivity here with lots of movable oil. Now up to the Shelf Margin Deltaic. In the Deltaic, we have 3 lobes, the A, the B and the C. What we're going to be concentrating today is on the B section, the one in the middle. But overall, what you see is, again, good tie between the log analysis and the core. So now what I want to do is pass it off to Mike Smith and you can see how his work in the volatiles world matches what I've showed you here today.

Hi. I'm Mike Smith. I'm President of Advanced Hydrocarbon Stratigraphy and I'm here to talk to you about the volatile analysis services that we performed on the Pantheon Talitha-A Well and the North Slope of Alaska. This is some of my previous history. I've been working on analyzing volatiles and cuttings for about 40 years now. I invented the first mass spec system that analyzed individual fluid inclusions back in the 1980s. From there, I went to AMOCO Research, where I invented fluid inclusions stratigraphy, which was recently purchased by Schlumberger, and won me a very prestigious award at AMOCO. I left AMOCO and founded AHS in 1994 and invented a new technology called fluid inclusion volatiles. After just 5 years, at 1999, ExxonMobil purchased fluid inclusion volatiles from me and the lab is still in use, in large use and used worldwide by ExxonMobil that considers it as a strategic asset. After my 10 years of consulting with Exxon, I refounded AHS and worked on a new technology we're calling volatile analysis services or VAS and this technology differs from the previous 2 in that we are now looking at present day fluids -- formation fluids, oil, gas and water trapped in very, very, very tiny spaces and cuttings, drill cuttings, which are the rocks brought up by the drill bit. And this tells us about the present day distribution of fluids in the subsurface as opposed to fluid inclusions, which were -- are information about the past. We've been in a strategic partnership with Baker Hughes since about 2018 and they market our technology worldwide. This is a list of some of my patents, just to demonstrate my bonafides in the field. There are 3 systems in the world that really produced the bulk or all of the volatile information on cuttings. There's the fluid inclusion stratigraphy system at Schlumberger. There's the fluid inclusion volatiles system at ExxonMobil and there's our system. So if you're working on volatiles and cuttings, you're almost certainly working with a machine that I invented and designed and built. We have a philosophy at AHS of unbiased science. We ask our clients not to provide us with any information on their well or their prospect before we do our work. And this is the case with Pantheon, Great Bear. We had no information from any of their results on these wells while we were analyzing their cuttings and not until we had our final data drop-off and long discussions with the Pantheon scientist as to what the information mean did they turn around and inform us of anything. So this study that we're going to show was then completely bind by AHS with no information from Pantheon. This is a slide showing some of the results. So these are -- we worked on cutting, 2 types of cuttings for this well. We worked on what we call sealed at the well cuttings, which are caught right when the cuttings come to the surface, and within a minute of being at the surface, are sealed in our tubes that we provide to the well. And then they shipped back to the lab to be analyzed. The other kind of cuttings we look at are ones that we load in the lab. So the cuttings are just caught at the well site and then washed and dried and brought back to the lab and we analyze those as well. So we get a little bit different information for both types of cuttings. If you look at the left curve here, it looks mostly solid green and above it is blank white. And on the left of that, there are some red -- small red bars, which show where we had samples. And you can see, we have solid green for most of the wells, about 3,700 feet of well there that's showing green and that's like 416 or some-odd cutting samples. And what this tells us is that every cutting sample in this well from the top of that green bar to total depth on the well contained oil. So there was live oil in all those samples. At the top of that sample is the regional seal. And what we see above that is we see that almost all the samples we analyzed above the regional seal, except for one, do not contain oil. So we have a continuous column of oil in cuttings from the base of the regional seal to TD in the well. Every cutting we analyzed contained oil for 3,700 feet. This is a quite unusual occurrence and really speaks to the great strength in the petroleum system here where this well is drilled. This is really a world-class petroleum system. The second curve from the left is kind of green and yellow shaded, somewhat irregular in character. That's telling us about the reservoir quality, and that's from comparing the sealed well samples with the lab loaded samples. And so by making that comparison, we can document where the good reservoir are in this well, and there's quite a bit of good reservoir in this well. Up and down the section, we see good reservoir. Now the length of that column is -- that's the length of the number of samples that we had that were sealed at the well. So below that, there's no data because there were no seal at the well samples. But for the most part, what we're seeing is great reservoir up and down the well. The other thing of interest is if we jump over to the right, the second curve from the right, which is orange in color, is our estimate of the oil quality that we see in the cutting. So for most of the cuttings, what we're seeing is that the oil quality is very good, very high oil quality, somewhere between mid-30s API gravity to low 40s API gravity, which is pretty much the best oil quality you can get. It's really, really good oil quality. The other thing we have besides the cuttings to work with are the sidewall cores. So the sidewall cores were taken in this well. There's a little tool that'll go up and down the bore hole after the well is drilled. That's like a little drill bit, but it's hollow, and it'll cut a core out of the side of the wells, such the name -- so the name sidewall core. So we had -- Pantheon really did a great job on taking quite a few sidewall cores in this well. It's excellent data, and we were able to analyze small bits of those. We don't use very much data. To the left then is our cuttings data and to the right is our sidewall core data. So now let's look at some of the sidewall core data in detail. On the left, we have a pink curve, which is CO2 and CO2 is very useful for us in determining subsurface pressures. The main driver of increased CO2 in cuttings is increased pressure in the subsurface. So you see at the bottom, we have high pressure -- a thin zone of high pressure, and this is in the pebble shale. It's also a zone of high water content. As we look through the data, what we see is that many zones are showing low water content. So our lab is one -- is the only lab in the world right now that's able to provide meaningful water formation, water information on drill cuttings, and this has taken many, many years to develop, but we finally cracked that nut. And what we can see is that up and down the bore hole, both in the cuttings and in the sidewall cores, we see many areas of low water content indicating high oil content. So it's only 3 types of fluids in the subsurface oil, water and gas. If your water is low, it means that the rest of the core space is being filled by petroleum. And this is looking at the data, scale the same for the cuttings and the sidewall core, scale the same as far as depth goes. And you can see again that many places, we have low water content here, and those are areas where we think that the well is going to be particularly prospective. And overall, we have this very large column of cuttings that all contain live oil, 3,700 feet of cuttings with each 1 having live oil in it. We have good reservoir quality. We have low water contents in many of those reservoirs, indicating that they're charged with petroleum. And we have good quality oil as shown by that orange curve over towards the right. So that, I would just like to conclude saying again that we have all these samples below the regional seal, 416 cutting samples plus all the sidewall core samples that we analyzed, all contain good quality light oil in the range of the mid-30s to the low 40 API gravity. We're seeing multiple pay zones throughout the section drilled, including the Kuparuk, the Theta West and in the Shelf Margin Deltaic. And really important, even though our analysis were done blind and without any information provided by Pantheon, our conclusions line up very well with Pantheon's petrophysical analysis of this well. And both were done totally independent of one another. So with that, I'd like to say thank you very much and pass it off to the next speaker.

Thank you, Mike. My name is Ed Duncan. I'll be talking to you today about the Theta West Fan. The Theta West Fan Complex is our largest new play in the portfolio. It's truly unique. The physical scale of the fan is amazing. It is the largest new play on the more North Slope and we control it. I think it's important to recognize that because we invested the time in shooting and acquiring 3D across this vast area, it's allowing us to see things now with calibration from our own wells, the heretofore have never been seen before. The focused continuity of this fan is truly impressive. Over 100,000 acres of our leasehold focused by our 3D and the technology that we use to analyze the 3D and tie it and calibrate it to the wells that we have drilled are allowing us to see light oil in reservoir. The thing about the Theta West Fan that is so impressive, the size of the area that has these attributes that are clearly indicating this is a play that is charged with light oil over a vast area. That's very different than the other new plays that you've heard about on the North Slope. This is not a widely distributed series of individual pools like you have in the Nanushuk, scattered over thousands and thousands of square kilometers. This is a focused geologic system with reservoir that is charged with light oil. The fan itself is deposited directly on top of the HRZ oil source rock in the basin, directly on top of the HRZ oil source rock in its peak-generating fairway. We know this because we've done the work. I think it's important to realize now that we have captured this new play systematically since 2019 in our leasing. We're not playing from behind on this. Let's look at the next slide and talk a bit more in detail about the fan. Let's take a look at the details of the Theta West Fan. We have a penetration now at Theta West with the Talitha well. You can see the entirety of our multiple zones of interest on the left-hand side, everything from the top seal, down through to the Kuparuk, remembering this entire section is charged with light oil as Mike Smith has just explained. The interval that is Theta West is shown here, labeled BFF, that's Basin Floor Fan. It's an extraordinary section. 600 feet thick, extremely high net-to-growth, probably 50%, maybe a bit higher, maybe 60% sandstone in this interval, extraordinary. It's Campanian in age. Why is that important? Campanian sandstones are different from many of the other sandstones seen in this basin in this general time section. The Campanian and the Albian Nanushuk are very, very similar, mineralogically, high quartz-rich sandstones, very low volcaniclastics, well sorted, texturally mature, fairly coarse grained, fine to medium green sandstone. That's a really big positive for us. What's amazing about Theta West as we see it recorded in these logs, each depositional cycle is showing a constructional phase of an upbuilding aggregational phase and an abandonment phase. So we have this cyclic system deposited in the basin floor across a vast area. As we've already talked about, this huge area of continuity that has reflection character, seismic attribute character, telling us that we've got a light oil charge through this section. Well, we've got a penetration at Talitha that tells us there's light oil charge throughout this section. It's an extraordinary occurrence for us. And we know, based on regional models, that we're going to see variations in reservoir quality through here. Each cycle is going to have channels. It's going to have overbank phases. There's going to be levies, there's going to be some channel lobe complexes, going to be all kinds of assemblages of depositional phases that are our reservoirs in this fan system. It's going to be an extraordinary thing to drill and develop. I'll spend a bit more time looking at an analog. Tarn is a good working analog for us. It's an oilfield on the North Slope. Just a few tens of kilometers to the northwest of Theta West. It's in an older stratigraphic section. But from a depositional system, phases architecture perspective, reservoir architecture perspective, I think it's a good analog. About 150 million barrel oilfield, 130 million of which has been produced to date. It was discovered in the early 1990s. And it's a good working model for us to look at. It's much, much smaller, though. And Tarn's about 25 square kilometers. Theta West Fan, the focused continuity portion of the Theta West Fan that we have leased is about 100,000 acres or about 500 -- close to 500 square kilometers. So it's a good analog, but a small analog. The thickest reservoir in this type of depositional system are interfan lobes, channelized systems, channel lobe complexes. We get into thinner reservoirs, more thinly bedded reservoirs. We get into the interchannel areas in the outer fan portion. All of these phases, though contribute. All of these phases have been drilled and recorded in Tarn. They all make a contribution to the production. And we expect nothing less than that when Theta West is under full development. Let's step on and look at some seismic data, because this is really what drives our ability to capture value for the company. The massive investment that's been made in 3D and the technology that's been built around that 3D, the analytical geophysics and so forth. But the raw seismic is really quite fun to look at for folks like me or seismic stratigraphers. Let's look at the Theta West Fan Complex, which is lined in here, all right? There are a number of horizons that have been interpreted here that will help guide our discussion. The green surface is the onset and conformity of the Theta West Fan. It actually shows a truncation of the underlying margin on lap of the fan back to the west, which is fundamental to the trapped geometry of the fan. The yellow surface is an intermediate seal, a very important seal to the lower fan lobe. And the upper lobe seen here has the upper surface and top seal, as shown in orange. All of these zones show seismic reflection geometry and attributes that support our interest and drove our leasing. At Talitha, we drilled 600 feet, as we've already talked about, a very high net-to-growth section. Campanian age sandstones, probably 50% to 60% sandstone in this interval. That section, that interval in the lower lobe thickens to the west, doubles in thickness, more than doubles in thickness, 1,300 feet in this location. It also is substantially shallower, updip, right? We cut the top at the lower lobe at 9,200 feet here. We're going to cut the top of the lower lobe at the appraisal well location at about 7,000 feet. The upper lobe, we drilled into it about 6,000 feet. That change in depth manifests itself in a number of ways. Importantly, it's a lot less expensive to drill. But also the change in depth means lower depth of burial. And that manifests itself has better reservoir quality, less compaction, all right? So that's an important concept to apply across the North Slope, not just to our project, but across the North Slope. Depth imperial is important. It's important for cost. It's also important for reservoir character and porosity and permeability. But this is an extraordinary occurrence folks. An absolute huge basin floor fan that we have captured, we have covered with our 3D, and we have captured with our leasing. I'm an exploration geologist and petroleum systems, I hesitate to say expert, but let's -- petroleum systems guy. I love looking at the regional geology as a key to how and why things happen in a basin like this. Let's look at this map. It looks fairly mundane, but it's actually super important. These are paleoshorelines through time, 80 million years, red and progressing it through outbuilding of the shoreline, shelf margin at the end of the Campanian, which is the age of the section that we were focused on in our projects, 73 million years. So 7 million years of building captured on this map. You can see the progress at the shoreline made through time with each advancing colored surface. What's going on here, though. We've got this -- we've got continuous progradation, continuous progradation. All of these shorelines start converging back into this area, and nothing happens for millions of years, or apparently nothing happens as far as shoreline progradation. Now what's happening during that time is there's all kinds of things happening out here. The Theta West Fan is fed by an extended period of stalled progradation. Effectively, the sediments that are coming into the basin that are outbuilding the shelf margin here are simply bypassing this very steep margin here and depositing into the Deep Basin. That's what gives us this extraordinary fan system, an extended period of shelf margin bypass and deposition into the basin floor. Importantly, deposition in the basin floor directly on top of the HRZ-source rock, extraordinary by any major measure, extraordinary. We've spoken a lot about Theta West Fan. How did we find it? How did we convolve all the knowledge and the technology that we have available to us to translate a seismic panel that looks like this into a well that looks like that? Well, it's amazing. What we found is truly amazing. The Theta West Fan, while we thought it was going to be good, it's spectacular. Let's look at the reservoir interval in Theta West in a bit more detail to give you a better understanding of what these things look like in as much detail as we have. The Formation Micro Imaging tool, FMI is a tool that records bed thicknesses in -- at a level of resolution about the thickness of your finger. So this tool is run throughout the entirety of the Talitha well. We've recorded this interval of the Theta West Fan, and we're looking at that today. Sandstones are -- the cleanest sandstones are the brightest colors, brightest yellows and whites. The higher clay content, you get darker colors. Some of the very, very thin strips in here, have higher clay content. Importantly, this entire section has still high net to gross. Maybe more importantly, definitely more importantly, it's oil charged. We looked at a smaller interval, a 20-foot interval, thinner interval on the FMI. You can see the nature of the bedding in more detail. You see the individual sandstone strata here recorded by the FMI within higher clay content beds between them. This is a fantastic picture nearly, like, whole core, looking at rocks on the surface in detail. This gives us an understanding of what the reservoirs are like in the subsurface, and how we want to approach drilling and completing and producing in them. This is an extraordinary outcome for us. Again, the Theta West Fan is the largest new play on the North Slope. Not just largest in physical scale, it's largest in volume, in my opinion. So let's move on to the next presenter. Thank you for your time.

Okay. Thanks a lot, Ed. What we're going to do now is talk about the volumetrics for the Theta West Complex. First thing I want to point out is how we define that volumetric, how we define the container. And the way we do that is by mapping the upper surface here and the lower surface here. The volume is the thickness between these 2 intervals integrated over the entire 3D area or the entire fan area sorry. Sorry. The other thing to point out here is that we can go almost 3,000 feet updip from the Talitha-A Well here. You can follow along the Theta West reflector. You can go up to the upper fan complex. And up here, we're almost about 3,000 feet updip from the Talitha-A Well. So I'll go on to the next slide. The question then becomes how do we define the aerial extent of this fan complex. We can measure the volume now how big is it aerially. And to do that, we look at our pet physical processing here. Seismic petrophysics, we call it. Here, the data is processed in the offset domain. So in other words, what we do is identify characteristics of the seismic attribute that are indicative of hydrocarbon. So we're just going to call this our hydrocarbon stack, hydrocarbon indicator stack. And what we're looking for is this red color. And this red color tells us a section rock, it's indicative of both reservoir quality sand, but also the presence of light hydrocarbons. So we could see that as we move updip from the Talitha well, that response in Theta West is very robust and continuous all the way updip. We also see the response in the upper fan. And we're showing a provisional location for the Theta West #1 Well. We haven't landed on that yet. We're still discussing it, but we will be obviously designing that to test both the upper and lower fan in areas where we see the favorable hydrocarbon response. So that -- so what we do is at every point in the survey, we extract the value of the Theta West reflector, you can see there in the red, all right. So now we're showing the hydrocarbon indicator extract in the Pantheon leasehold. You can see here that this red color, this is corresponding to the seismic line we just saw. This is -- and these are areas that we think are hydrocarbon saturated. And so we've outlined that with that with that solid blue polygon. That's our Theta West lower most likely case. And just a word about this area down here, this is an area where there is no seismic acquired. So of course, we can't show the hydrocarbon indicator attribute there. But we see that it's surrounded on 3 sides by robust hydrocarbon response. We believe it's there. And also the depositional setting there is exactly the same as the surrounding area. So we believe that this area is highly prospective. And in fact, we acquired that acreage in the January lease sale. The -- one other thing to point out is this dashed or dotted line here in the north. That is the Theta West Upper Fan Complex overlaying for reference. So we'll see that in just a minute. So moving on to the next slide. Here it is. There's the dotted line. And then you can see the polygon, Theta West Lower and Theta West Upper. And this is -- the Theta West Upper Fan is also very strong response, and it also exhibits a geometry that you might expect from a submarine fan being shut off, shelfed to the west. So let's move on and look at the volumetrics. We take inputs from Theta West -- sorry, the Talitha well, but also the gross rock volume, and we run this through simulations, 2,000 trials, in this case, in a Monte Carlo analysis. And we get a P50 or a median case oil in place of 12.7 billion barrels. And 11 billion of that is net to Pantheon. And recoverable reserves, we are using an input distribution of recovery factors. We get 1.2 billion barrels net to Pantheon. And in the middle panel, this is just a list of sensitivities, the sensitive inputs and the greatest sensitivity, as I said, at the top there is the gross swap volume. So we'll move on to the upper fan, it's the same analysis. Only here, the only difference here is that instead of a mapped upper and lower surface, we're using a slab distribution as an input because it doesn't have as widely bearing thickness as the lower fan complex. And so in this case, we get a P50 or median value of 1.29 billion barrels in place, of which 1.1 billion would be in Pantheon acreage. And we get a P50 recoverable of 210 million barrels in Pantheon acreage. So adding those up, just to summarize, we have, in the Theta West Fan Complex, a gross of 14 billion barrels, of which 12.1 billion would be in Pantheon acreage. And in terms of recoverable 1.41 billion barrels in Pantheon acreage. So just to take away some points on Theta West. This is a really exciting project. This is one of larger projects we've seen in the onshore in a long time. The polygon encloses both the upper and lower is shown here in different colors. And that polygon is 18x larger than Tarn. We estimate Tarn's EUR to be about 150 million barrels. So we can also say that this project is well defined by proprietary 3D and that we can go 2,000 to 3,000 feet updip to pay in the same interval in the Talitha-A Well. And as we go up dip, not only do we expect improved reservoir character, but we also are seeing, from the seismic, that it's going to be 50% to 100% thicker, depending on where you are as you go updip. The seismic attribute analysis that we used to define this feature, we can say it worked at Talitha-A, hey, we saw an improved response in Talitha-A relative to pipeline. And that response correctly predicted the hydrocarbons in Theta West at Talitha-A. So we're very confident going further up to the Northwest that this will be successful. And the added bonus here, so we're only 5 to 20 miles west of Dalton Highway. So you look down and there's the highway, closest point would be about there. There were only about 5 miles west of that. And as the project is developed, we can move up and expand. So that's 12 billion barrels of oil in place net to Pantheon. Let's turn it over to Roger to discuss the Shelf Margin Deltaic sequence.

Thanks, Jerry. This slide, you've seen before. This is the SMD section in Talitha. I brought this up again just to impress you that we have gained an awful lot of information from the rocks with the core, with what Mike Smith gave us. And with that information, that knowledge, we can transfer it to the other wells in the area. For example, let's go to Alkaid. As you know, Alkaid has a tested zone right here. We tested 6 feet in the zone here. And as you know, we only have oil all the way down to the TD of the well and continues on going most likely. But you don't know what's going on above it. This is the SMD-B section. With the knowledge we gained from Talitha, we now know that, that section in Alkaid is also filled with oil. So let's zoom in on that a little bit and look at what's called the FMI tool, the formation micro scanner or the imaging tool. It's a much higher resolution than the regular logs are that we do the log analysis with. It just gives us an image of what's going on. When it's brown, we're looking at shales. This is the interface between the [ K10 ] shale and the SMD B section. When it turns yellow, that is sand filled with oil. So what I'm going to do now is page down and we'll look at the FMI at numerous locations. We dropped down a little bit. We're down into the best zone or a better zone, at least anyway, of the section. And what you're seeing is it's filled with oil, very high net to gross sand to shale. Continuing on. It gets a little bit shalier, but still high net-to-gross. A little bit shalier in this section. Now we're getting to some thicker sands, but still maybe 50% net-to-gross. Get a little bit further and we get to a zone that's really quite shale-y and likely separating the SMD B section from Alkaid. Getting a little bit sandier as we continue down, sandier again, get into the Alkaid zone, and we're getting very sandy. And again, all filled with oil and continuing down all the way to the bottom, you can see how it just varies in net to gross. So there's an outline of all 12 sections that I've pulled out of the FMI. So you can see the tremendous variability that exists in this section. The next question becomes, okay, with all that information we have, the SMD now also being in Alkaid. We know it's in Talitha, we had it in the pipeline before. How does that all fit together? How do we map that together? So we've designed an attribute from the seismic that will highlight the SMD B rock and show where it is the best. It's not tied to any of these wells. It's simply an attribute. And that attribute is shown there in the map that you see. Right here is the pipeline well location, and that's the pipeline well, 500 feet of SMD Pay. The Talitha well location is right here on the edge. Alkaid is over here. Merak and Alcor are here. All these zones have oil in them. And this attribute fits perfectly all 5 wells. So now we can get a really good confident understanding of what the outline is of the SMD B section. Just to contrast, prior to gaining all this knowledge from the Talitha Well, Talitha-A Welll, we thought the SMD B section look like that. So let me point out some landmarks. There's pipeline, here's Talitha, there's Alkaid. So that's what we thought was going on. But what we know now is it really looks like that. Pipeline, Talitha, Alkaid and Alcor and Merak. And really nice is here is the road and the pipeline. We can produce this reservoir from numerous locations on the road and the reservoir has gained in size and quality. So this is a really exciting project. Jerry will show us the volumetrics now.

All right. Thanks, Roger. We'll walk through this in a similar way that we did for Theta West. It's the same procedure. So what you're looking at here is the same map Roger just showed. It is just a different color scale, just to highlight the dynamic range a little bit. And a couple of the features you can see on this are much thicker and more robust response off to the Southwest. But we do know that there's pay up in here with sort of a little bit more modeled look here up at Alkaid. So now we can see that we have a response, trending all the way from pipeline, wrapping around what we call the funnel and then up into Alkaid. And so we're going to define the most likely case as the polygon you're looking there -- looking at in blue. And we're going to constrain that to a 100-foot isopach, and you can't see that very well. But that's this line right here. So we want to be -- calculate volumes for areas where the isopach is greater than 100 feet. So we're going to look at the same kind of analysis that we looked at before. This is a Monte Carlo simulation. In this case, the 10,000 trials. So here, we calculate a P50 or median volume of 2.77 billion barrels, of which 2.66 are net to Polygon. So we control 96% of this project. So we have almost all of it. In terms of recoverable resources, we're at about 400 million barrels net to Pantheon. All right. Now I'll turn it over to Jay, who's going to talk about the development of these 2 projects.

Thank you, Jerry. Well, now I'll talk about monetizing the assets. As we've heard, and as I've talked about and everyone else, location is key. These are drainage areas along the Dalton Highway. We will put development pads along the Dalton Highway. We'll simply put down gravel in the disturbed area. We can work 24/7, 365 days a year. Prior to getting a full field development plan, as long as we're within a disturbed area along the highway, and we can develop about 200 million barrels in that manner. That is a huge oil field in its own right. Now on to some full field development economics. This is simply a matrix showing the net present values in gross and in per barrel terms at various oil prices. I don't need to read them off to you there. ANS crude sells at about the equivalent of Brent. As you've heard from Mike, our crude is between mid-30s to low 40s API. It's very sweet. We believe we will get a premium to the normal taps crude price. You can put in your own Brent crude price. But at $60, the combination is about $3 billion net present value to Pantheon. And remember, we have 100% of this project. So before we go into showing the video and then to the Q&A. We are going to do this environmentally with no emissions. We are simply going to produce the product. We're going to burn the gas to produce electricity. We will do that both in our development scheme and in our production scheme. We will reinject the CO2. We will reinject the water and we will produce the oil either directly into taps or in the early stages, truck it up to Pump Station #1. We call this Green Energy Alaska, Green Oil Alaska. So back over to you, Jerry, for the video.

All right. Let me launch the video.

And while Jerry is launching the video I just wanted to say that we made the video because we recognize we've presented a lot of technical information. And as Jay started -- stated at the very beginning, trying to see it if you're not an experienced technical person, trying to understand it and visualize it is very difficult. We're hoping that this video we'll clarify it for the non-technical audience and kind of give you a picture of what's going on in the subsurface.

All right. We'll start with the surface view. You've all seen this before, so we don't need to talk about that. What we're going to do is rotate this up and look at the subsurface, and we'll make a few points before we start showing you the layers. So first, we're going to start with the pipeline well. This is kind of the driving force that is responsible for a lot of what we've seen and have presented to you so far, out of the results of our work program, originated with this idea. We are showing here the oil saturation curve, that's in green here, and just presented as a lake. So you can think of this as a lake to kind of display where the larger diameters in green indicate higher oil saturations. At pipeline, due to various technical issues, we believe that the log was not -- the well was not properly evaluated. We went back in and reevaluated it and saw that there was about 2,700 feet of oil-saturated column in this log, bounded -- in this well, bounded mainly by the [ K10 ] on the top and the Kuparuk at the base. So we went out and acquired about 1,000 kilometers of 3D seismic data, excellent quality. We tie in the pipeline well to that data volume. And you can see that we're going updip from oil saturated rocks as we go to the Northwest. And now we'll replace that with the same line, but this time process for hydrocarbon indicators. Again, the red meaning better hydrocarbon indications, and we see those increasing, going updip again from the pipeline well. And from this data set, we're able to extract surfaces, so we could have the geometry of all the relevant surfaces in the area. And now we're going to look at the Talitha well. So we've rotated around. Here's pipeline. The Talitha well was drilled right about on this location, just to the downdip edge of the Theta West, both in terms of structural dip, but also in the seismic response. And Talitha's shown here. And Talitha confirmed our prediction based on seismic attributes. We saw oil saturation throughout the Talitha [ Calm ], as Mike Smith showed you, over 400 samples, all oil saturation saturated in the [ K10 ] to Kuparuk interval. So what we're going to do now is start layering from the bottom up starting with the Kuparuk so you can see in 3D what these horizons look like. So this first one here is the Kuparuk. This is the regional Kuparuk surface. And the color scale, we're using lighter colors up here, being shallower; blacker, darker colors mean deeper. So it's generally dipping off to the Southeast. We extract the hydrocarbon indicator response. It's shown here just underneath the Kuparuk surface. So we'll make that transparent, so we can see it better. And now you can see the hydrocarbon response defines the outline of the Kuparuk reservoir, so that the reds and oranges are the best responses. And you can see the type -- Talitha and pipeline were drilled and similar responses in the Kuparuk. Both had oil in the Kuparuk. And then we'll turn these reservoirs green, and we'll refer to them as geobodies. After -- shortly after the deposition of the Kuparuk, just about right on top of the Kuparuk actually is HRZ. As Ed mentioned, this is the regional source rocks. It's a very important horizon for our analysis. We're going to rotate that up and look at that in map view. All right. This map is showing HRZ maturity. And by that, we mean generally the capability of the source rock to generate oil. Up in the north in the blue colors, the HRZ is immature, meaning that wasn't capable of generating hydrocarbons. And on the south very too deeply, and it's in the gas generative phase. The peak oil saturation of generation was down in this fairway, right underlying the Pantheon leasehold. And that's not coincidental. We acquired the leases to be on the main oil-producing fairway. But also near the Dalton Highway. All right. Now we'll continue on back to our 3D view, and we'll move up into Theta West. So in this view, we see the base of the Theta West Fan Complex. So in other words, this is what C4 topography approximately looked like at the time the Theta West Fan Complex was underway, the deposition was underway. And what we're seeing here, red is shallower water, blue is deeper water. And what we're seeing is about 40 million years after the HRZ. By that time, the Continental Shelf margin had advanced almost into the western part of our acreage. And shortly afterwards, this is the top of the Theta West Fan Complex. In a relatively brief period of time, you can see much less slope here. The Theta West Fan Complex or the depth -- sedimentation from the Theta West Fan Complex resulted essentially in this basin being almost planed off. And so we're going to now peak in between these 2 layers. And there, we'll see the hydrocarbon indicator body for the Theta West Fan Complex. We'll make that transparent. And this shows the outline of the Theta West Lower Fan Complex where we see the positive hydrocarbon indicators. And the proposed location will lie somewhere within this disk. All right. And then moving up from Theta West, lower, we saw a period of shale deposition, deepwater organic shale. It could seal the huge shale, and following that, the Theta West Upper Fan was deposited. And then relatively rapidly came the Alkaid shelf margin. So in a relatively short period of time, the shelf margin advanced all the way to the Alkaid area, the eastern part of our acreage. And so we'll pause here just to rotate this around so you could see in 3 dimensions, what these Theta West and Kuparuk reservoirs look like, how they relate in time. And in particular, you can see how thick and just how massive that Theta West lower reservoir is. So now we'll stop here and just point out the faults associated with the Theta West -- with the Alkaid reservoir. This yellow fault forms the Northwestern boundary of the -- of the Alkaid reservoir. And this pink fault divides the reservoir complex into 2 fault blocks. So we'll strip off the Alkaid shelf or we'll make it a little more transparent so that we can see the faults and the geobody below it. And now we're going to rotate this around and take a look at the complex from the back and we'll have a look at what the Alkaid 2H well will be designed to do. So bear with us and it'll -- this will take a few seconds to get here. Okay. So what we're looking at now, this is the back wall or the fault-bounded northwesterly surface of the Alkaid geobody, the Alkaid reservoir. And you can see these red-gold responses are indicative of high hydrocarbon saturations. That response was tested by the Alkaid, Alkaid-1 well, #1, and it was successful. So we're going to try and test the same anomaly a little bit further to the left there with the Alkaid 2H. So we'll zoom in on that a little bit. And we're going to make it transparent in a second. First, I'll just show you the Alkaid oil saturation. So it's, again, that late display, larger diameters, mean higher oil saturations. And the Alkaid 2H well will be drilled from the highway, near the Alcor level surface location. We'll come down into the Alkaid reservoir and then go horizontal towards the Alkaid well, and you can see that wellbore in the reservoir there. And we'll just twirl around to get to some more perspective on that. Okay. What we're going to do next is we're going to replace that geobody with an oil saturation geobody. This was created by projecting the oil saturations at the Alkaid #1 well. So not a lot of data to go on, but it gives you an idea of what we're trying to do here. So I'll turn this around a little bit. And we should make the point, before we go on here. That disk that you see is the completion at Alkaid #1. So that's a 6-foot interval there that produced -- floated 100 barrels per day. So what we're going to do now is drill horizontal wells through the oil saturation zone, you can see here by the green cells. We're going to penetrate that zone with a horizontal wellbore. That wellbore will be on the order of 7,000 feet of horizontal section, plus or minus. It'll have 30 stages as opposed to the 16-foot hole here. And there's not going to be just 1, there'll be 44 of these wellbores at Alkaid, each one of them should be capable of producing 2.5 million barrels per well. So we'll zoom back now to get our Northwestern review, and we'll make the Alkaid shelf opaque again. And we'll conclude with the SMD B. So following the Alkaid shelf was the K10. This marks near the top of the SMD reservoir. And we've mentioned the Supertrap before. If you remember that. That's this area here. You can see it right between the Alkaid shelf here and the [ K10 ] shelf margin above it. So now we'll show the SMD. We'll layer that on here, and we'll rotate into a little bit easier angle to view this. And you can see, well-developed amplitude anomalies on the Southwest side and extending all the way over into Alkaid, a little bit thinner on that side than it is on the Southwest. All of this, the entire complex of 5 reservoirs was then blanketed by the Decker D regional seal. So now we'll strip that off and show all of the geobodies in space. Those are the Brooking ones. And now the complete section down to the Kuparuk. I put our lease hold on here so that you can see that we control most of this by volume, and we're going to rotate this up and around. So you can kind of see a perspective as we rotate around how these all look, how they relate in space and thickness. And I'll just stop here just to name these again. So starting at the bottom, the Kuparuk, Theta West Lower, Theta West Upper, Alkaid and SMD B. And in this view, you can really see the massive scale of the Theta West Lower reservoir is huge. It's thick and it's extensive. And now we'll swivel around and look at this in map view. And what we can see from this, it looks like if you were just talking about in terms of surface area, we'd have about 76% of the oil in place of these 5 reservoirs. But the more accurate way of doing this is by gross rock volume, and in that sense, we have 89% of the oil in place of these 5 reservoirs. So that concludes the video. I hope that helps. And thanks for watching.

I'd just like to add something at this point. You've got there -- what you're seeing there is all the stacked reservoirs, one on top of the other. And again, point out that to the Northeast is Prudhoe Bay to the next kind of green blob up there to the Northwest is Kuparuk. Kuparuk is about 14 billion barrels of oil in place, Kuparuk and West that. That area that we've just discussed today is over 16 billion barrels of oil in place. This is an incredibly dense kind of resource that we're looking at. It's comparable to the early discoveries that were made in the '60s back when this -- before -- when all the first discoveries were made. And so I want you to keep that picture in your mind right here. What we're looking at is an incredible resource density right next to the Dalton Highway and Trans-Alaska Pipeline, which -- it is unique for the North Slope.

Well, that's been great, guys. I mean, it really has. So we got a lot of questions in. So we've got a little bit of time to answer some questions. So Justin, I think you're the Q&A master.

Thank you. Yes. Thank you, Jay. And look, a big thank you to everybody that spoke today. I think we had a fantastic -- I think shareholders would appreciate, we've had a fantastic access to some very, very high-level technical people, which is very rare for companies. It's our objective to really let people have a look under the hood to believe in us to believe in what we are telling you to believe in, that this data behind what appears to be very, very large projects for Pantheon. So also a very big thank you to Mr. Darcon for curating a specialist of questions. As always, they're long. They've been coming in thick and fast. I've got over 120 questions in front of me. I won't go through all of them. I'll do my best to pick the key ones out. I will pass questions out to who I think is the most appropriate person. And in the interest of time, I'll whiz through any quick ones myself. So sort of getting into it straight away. The first question that's come up is, when will the webinar be available on the company website? Noting that the last webinar took a few days, what I would say is that we have recorded these webinars live. Again, it's something very rare for companies to do. We do it because we wanted people to see the energy and to feel that energy and I guess, the authenticity of the presentation. And that's the reason that it took a few days to get them available. There's been sound issues, there's background noise. Sometimes, because it has been live, there's people talking over each other. This time, we've done our very best to make it different, so we hope that they'll be available -- we're aiming to have it available tomorrow onto the company website. Another question here, assuming we had an optimal work program over this coming winter season. We've talked about Alkaid, we've talked about going back and testing the Talitha well, which was already drilled last year, as we know. And of course, the giant these Theta West well. First question over to you, Bob. What would your preferred drilling program be if we had the opportunity this season? I guess, from the first question is, would it be possible if we had the funding in place to do all 3 of those projects? Or what's your thinking on that, Bob?

So this winter, we're going to be focused on testing Talitha and drilling Theta West. So that would be the first wells that we drill. Our preference would be to drill Alkaid, not as a winter well, but something that we can start in the spring and get going next summer. So if we were completely funded, test -- drill Theta West, test Talitha, and then follow on with the Alkaid well.

Yes. Thanks, Bob. Of course, because drilling out of the winter season, it typically comes at a lower cost, because you don't have to winterize the rig and do all those kinds of things.

Correct.

Yes. Another question here. There is no particular order, although I'll try to group as best as possible. A quick question just on how do we avoid confirmation bias in our analysis? And I think Mike talked about that specific point in earlier on when they do their VAS completely independent of the data from the company. In fact, they specifically did not want any data on the well from the company. And likewise, in any group setting, every natural resource company in the world, in fact, every company in the world trying to prove something face the same issues. We try and have a disparate group of people to challenge each other, to debate concepts, and we support that by consultants and independent experts where we can. Another random question here. Have all members of the Pantheon, executive team, vaccinated -- been vaccinated against COVID. The answer is, to my understanding, yes, everybody has. So the next question concerns the decision this week regarding Conoco's Willow project. And the question specifically is whether or not we have any -- or we expect to face the same issues that Willow has and the other implications for Pantheon. Jay, what are your thoughts on that?

Well, the big difference, as you can see on this map, is that Willow is on federal acreage in the NPRA. We're on state lands, and so that's the biggest difference. We will need to get a permit to put gravel down. That's a given. We don't see that as a big issue. Our path to first oil is pretty clear and dealing with the state as opposed to the feds makes a huge, huge difference.

Yes. And I guess, Jay, of course, being, again, the same point, location, location, location.

Location, location, location.

Yes. Okay. Thank you for that, Jay. Look, while we're on it, the other question is concerning farmout and funding for Pantheon. This is a question that comes up a lot, and we're happy to answer it. Where is Pantheon's status on that at this point in time? And the answer is precisely what we said in our stock exchange announcement of last week, and that is that we're running a farmout process. We do need to complete a farmout all to, otherwise, fund the company to have any activity this winter season. That's our objective. We're working towards it. It's always been the objective and we're very, very confident that we'll get to that point. Noting last year, we didn't do a farmout. We ended up equity funding it. We made that equity funding transaction in late November, so we do have time, which were to find the right partner. Getting in -- with a farmout, it's an involved process. It takes time for them to understand and to do their DD. It is like a marriage. We've got to make sure that we share the same objectives in terms of development and so on with the projects. So it's important for us, and that, I guess, includes us taking a view on that company's other activities elsewhere as well. So it's as simple as just chasing the checkbook. It's about finding the partner that makes sense. But, look, right now we're focusing on that. It's the summer break. We've got time enough, thankfully. So we'll make decision going forward in terms of what we think is the right decision for the company. The next question here actually leads off that. It specifically is how critical is it to find the right partner that understand Pantheon's place. I think I just touched upon that. Look, again, money is -- capital is one part of the equation in finding a partner. The other, of course, is what that party brings to the table, be it skill set or other form of resource, and we'll consider. If a company doesn't -- if a company comes in that doesn't have that skill set, we have the ability to access that skill set through third-party independent contractors. There's a question here on noting that Santos had made a bid for Oil Search. And does that -- is there any see-through implications for valuations and so on? I think the answer to that one, if I can just take that one on is, we can't speak to Santos. We know that Oil Search has 2 major assets, one, of course, in P&G. They have some more mature assets, which are producing. And of course, their Alaskan assets. What we do know, of course, is that Santos will run the slide rule across Alaska. They are better funded. So we think it's a net positive for the area. Moving forward on to Talitha-A, question for you, Bob, and that is that we've never ascribed probabilities of success on outcomes for the world for each particular zone. I know you have views on this, Bob, is that something that you want to talk about?

Well, Talitha-A, the way I would put it is we've drilled it and we have found hydrocarbons in the zones that we've described. Today, we've got hydrocarbons in Theta West Fan, the upper part of Theta West Fan, the Shelf Margin Deltaic and the 2 lobes in -- that are in the slope system. So how those individual wells will perform? We'll find out when they're tested.

Yes. Just to stay there, Bob. Another quick question, and that is, the guys have spoken earlier in this presentation about our contingent resource, about 1.4 billion barrels of recoverable contingent resource in Theta West, but we've based those on primary recovery only. Why have we not -- why have we not included or have we not considered secondary or tertiary recovery methods? Can you give us some comment on that?

I think we're trying to be conservative. The numbers we're putting out there are numbers that we think are completely justifiable. And as you can see, we're not using high recovery factors and that gives us considerable upside. So that's why we've done it.

Okay. So it's not that secondary and tertiary recovery methods are not applicable, you've just taken a conservative approach and elected not to use those at this point in time?

Correct.

Okay. Great. Jay, a question for you, if I may. This is about using independent experts. We previously had used the experts at Lee Keeling to do some work on us for Alkaid and also the Kuparuk. The question is, would we consider using those for Theta West and for Talitha?

Well, yes, we will. And I think at some point in the future, we will bring in independent experts. We haven't done that to date. I'd like to have one more well in Theta West. I'd love to have more testing data on the Talitha-A Well before we would do that. So I think that would be the appropriate time to bring in independent experts. And we'll make a decision at that time as to who would be the best.

And just -- yes. Understood. A question for you again, Bob, if I may. And we saw it briefly on the 3D video that Jerry just showed, and that is this huge expanding thick section moving from Talitha towards Theta West. How far does the Theta West target extend from Talitha? And how does that compare, on a relative measure, to other projects you've seen?

Well, I think for the North Slope, this is unique. I think Ed described it perfectly. It's 100,000 acres of a huge, thick, confined basin floor fan. 600 feet at Talitha, 1,300 feet to thick at our proposed location. I mean it's -- it is enormous. I mean, I have yet to see anything comparable described on the North Slope like this. And what it's comparable to is things that people have seen in deepwater plays in different parts of the world. So, I mean, this is a deepwater fan play that we can drill and develop onshore.

Okay. Yes. Thank you, Bob. Question here is how deep would you propose Theta West will terminate. And will that also extend the Kuparuk?

No. What we plan to do is drill the upper part of the Theta West. So we do the upper lobe and drill through the base of the lower lobe. So that's it.

Understood. And with VAS, we had Mike Smith earlier on, with it being so successful in its analysis at Talitha, is that something that we intend to use in future wells?

Yes. Absolutely.

Okay. Great. And a question for Ed, if I may. Ed was speaking about the Tarn field earlier. I had a question here, talking about the similarities and differences between the basin floor fan and the Tarn field. We've referred to them previously as an analog.

Thank you for the question. With regard to similarities and differences between the basin floor fan and the Tarn field, I can tell you that from a depositional process perspective, they're very similar. It's really scale. That's the primary difference. In addition to age, I can't forget that. Tarn is Cenomanian age. Its reservoirs have a lot of volcaniclastic debris and the digenetic products or the chemically changed products at those volcaniclastics actually are quite detrimental to overall reservoir quality at Tarn. Campanian sandstones, as we talked about earlier in the presentation, do not have volcaniclastics or significant amount of volcaniclastics, in them. That's a very big positive for Theta West and our projects in general. From a process perspective, Tarn a lower slope apron and basin floor fan complex, similar to what we expect to see at Theta West. Probably, the upper lobe of Theta West would be a very good direct analog with Tarn from a process perspective. The lower lobe is so much larger and thicker that it's Tarn times 20. And -- but from a process perspective, phases architecture perspective, I think we're going to see something similar to that, just many, many, many times larger.

Thanks, Ed. We'll have you -- hang around, I have another question. It concerns Alkaid #1 well, which was originally drilled as we know. Can you please just briefly explain why that well didn't reach its intended target depths, i.e., why the drilling was concluded prematurely?

The question about Alkaid is an important one. We plan to drill Alkaid through the Kuparuk. We were encouraged by what we saw in the Kuparuk and Alcor and Merak. It was thin, but oil bearing. We wanted to test the Kuparuk a little more basin-worth. Hopefully, picking up a thicker section, we realized that there was Kuparuk with oiling in the Sequoia well and oil in the Kuparuk and pipeline as well. So the plan was to drill through the Kuparuk. In late February, remember it was very, very cold in Alaska at that time. It's hard to believe that there could be flowing water on the surface, but in late February, the Sag river, which was just to our east experienced what's called an off-ice event, where the normally thin rind of ice across the flowing river below it, flowing north, froze to bottom, just to the north of our location, just opposite the Alcor well that we drilled in 2012. That freeze to bottom caused a temporary damming of water flow to the north and forced an inflation of the ice sheet that covered the flowing water that eventually ruptured. And that rupture started fairly passively, obviously, a big concern for us, but the Dalton Highway is really built on a major man-made gravel berm, effectively a dam. So we were confident that we were going to be in okay shape. But the off-ice event evolved into a full-on breach of the Sag river bank and across the tundra and actually cut the Dalton Highway, a couple of miles north of our Alkaid location. That cutting of the highway effectively severed our ability to resupply the rig and created, not just an operational challenge that was extreme, but created a serious safety challenge for us. We knew at the time that the breach of the highway started, that we were going to have to wind up operations pretty quickly. And that's when we made the decision that we would get through the primary seismic anomaly target of interest, get as deep through that as we could and then stop. In fact, we cut the seismic anomaly of interest right on depth, and we were still in oil, when we TD the well at 8,600 feet. So it is an unfortunate circumstance, but mother nature does that to us from time to time. Importantly, since that off-ice condition, that was the only one ever recorded that actually cut across the highway. The state has improved the Dalton, raised its bed substantially and buttressed it against any further events like that in the future. So that's not something that we genuinely need to worry about to an extreme degree from this point forward.

And what -- so at that point in time when drilling operations were concluded, am I correct in understanding that we were in the middle of the pay zone at that point?

Thanks for the question. Yes, definitely. When drilling operations were concluded at Alkaid, we were still in oil. We knew that from the mud log cuttings at the time. We knew that from the gas chromatograph at the time. And we've used all of that type of information in the course of reevaluating Alkaid into its current state as we see it today. It is a very thick oil column from -- really from the [ K10 ] top seal all the way down to TD. And I -- it's an extraordinary circumstance, not dissimilar actually from what we're -- what we now have seen at Talitha. The petroleum system is so proficient. It's so effective and efficient that really, if you have porosity in this section sitting above the HRZ, it's very likely to be charged with light oil.

And Bob, you've spoken about this. You used these words, "oil down to," frequently. What does that mean, Bob, in terms of our estimates for Alkaid. So Ed said that the world terminated in the oil section. Have we included anything from that depth below in any of our estimates?

No. We haven't. So we expect another 300 or 400 feet of section to be tested. We have no reason to believe that there will not be sands down there and will be hydrocarbon bearing. But we have not put those in, in any of our estimates.

Okay. Okay. So if we -- if and when we drill Alkaid #2, how much deeper that will be drilled?

So what we plan to do is, first, do a vertical hole and collect data through the whole section. So get it down to the HZR, not drill to -- not drill to the Kuparuk, but collect data to -- through the whole section, and then come back, kick off and drill the horizontal through the zones that we've already tested.

Great. Thanks, Bob. Now I have a question here for Mike, if he's still available, and that is on VAS. And thank you, Mike, for the great slide presentation you gave us earlier on today. The question is, have you used in other fields elsewhere? And how accurate is it in its assessment?

Yes, we're working all over the world. It's been very accurate. I'm not sure we have statistics on that, but not just other places, but in non-Pantheon wells in Alaska. We've been able to -- our data kind of mimics other companies' wireline [ logs ] and we did a big exploration well for another company in -- the year before we did Talitha. And again, we did a blind. We picked all their main pay horizons. We -- everything -- when they did their final petroleum system analysis and overlaying our data on their seismic and everything was spot on and stuff so...

Yes. Brilliant. Okay, Mike. Well, thank you very much. That was -- it was leading to the second question, which was whether or not you'd look at other wells in Alaska, and you've answered that so...

Yes. So up on the slope and also in [indiscernible] and stuff, so yes. And we're doing a big study with the state on their old wells that were drilled by the Navy in the 50s and stuff, so...

Brilliant. And Mike, in terms of efficacy, and excuse me if this is a silly question, but you do lots -- this is your specialty, of course. Was the quality of the samples that you received out of this well, do they enable you to get an accurate -- I mean, were you happy with the efficacy of the work that you did based upon the quality of the sampling out of the Talitha well?

Yes. One thing is, right, I mentioned this week, we work on cuttings that are both -- 2 types of cuttings: cuttings that are sealed at the well and cuttings that are not so at the well. So the fielded well cuttings, within a minute of coming to the surface, they're captured and loaded into tubes that we send up there and hermetically sealed. And then they come back and all that oil and gas that was in the cuttings, when they got to the surface, they're still there and we analyze that. Those were done very well and give us a good shot at making some resource assessment in the quality of the oil and stuff. And then the other kind are the lab loaded. And they have usually lost much of their oil and gas before they get analyzed then, because they haven't been sealed up. But that's the data in that second column that we were talking about producibility or movability of the oil. So a good quality reservoir rock will show -- that's charged with oil, will show quite a bit of oil in the sealed-at-the-well sample. But the better the quality, the less oil you'll see in the lab-loaded because the oil won't be lost and stuff. But these are -- the guys that caught these samples did a very good job. We have a philosophy, besides of not wanting to know what everybody else knows, we also -- one of the reasons this works is because our processes are very gentle. So we strive to keep the oil and gas in the rocks before we try to extract the stuff as opposed to other cutting analysis processes, which drive most of the oil and gas out of the rock before the analysis begins and stuff.

Fantastic. Look, thank you, Mike, very much. Well, I'm very, very conscious of time. I've got 1 or 2 last questions, and then I think we can draw a line under the presentation for this evening. One is about -- back to this question of a farmout. This just -- the question just popped up. Jay, perhaps for you. The question is, are we looking for a farmout for the whole -- for all the projects or just for 1 project? Jay, could you comment on where we're at on that?

Yes. Well, the answer is yes and yes. We've talked to people about farmouts on 1 specific project. We've talked to people about farmouts on 2 parts of 2 projects, and we've talked to people about the whole suite of our 160,000 acres. So the great thing about having 100% working interest is you can be totally flexible on what you do. And we're totally flexible. And given the fact that we're in this to prove it and sell it like a venture capitalist, like a private equity just gives us all kinds of flexibility to make like the deal that fits with the farmout partner, if they're the right partner.

Yes. Thanks, Jay. I mean, another question here related is what makes you think you can achieve a farmout this year if you couldn't achieve one last year? I think what -- Jay, you and I have spoken about this many times. Last year was a different world for oil and gas companies. We're in COVID times. The oil price went to 0 at 1 point, but was probably $30 to $35. During the time, we would have been looking for a farmout partner. Today, it's $65. We had companies, oil companies really looking inwardly at that point in time last year, fighting for survival, getting their own portfolios in line, certainly not looking for new projects. But the big one, of course, which we don't speak about is Theta West. Last year during farmout discussions, there was no mention of the Theta West, because so much of that acreage we had to pick up in the lease sales, which occurred, of course, in January of this year. So last year in farmout discussions, there was no talk of Theta West. It was apples versus oranges and I think it's a really important point. So we're in a much better time and a place this year. Doesn't guarantee anything, but we're in a much better time and place and Pantheon's -- given the success of the results and what you've seen before us earlier today, the balance of probability has swung significantly in our favor in terms of our confidence in the project, the understanding of the project and all leading towards a greater chance of success in either achieving a farmout or otherwise funding the business. I think that's probably about it for the key questions. Yes, just as a closing point, perhaps, Roger, we haven't heard from you in the Q&A and you've turned into the sort of the minor celebrity for Pantheon shareholders who have grown to love your style and your enthusiasm. If I may, how has the project evolved from your perspective, since we drilled the Talitha well? Has your understanding or has your confidence or has your concern -- or how do you feel about the project we have now post drilling Talitha, perhaps, before drilling Talitha?

It just keeps on getting better. Like Jay said at the beginning, good projects get better. Well, from the exploration phase, it keeps on getting better. It's -- I've never seen anything like it. To be able to even say the words 0.5 mile of oil, that's ridiculous, but it's true. It's awesome. I've never seen anything like it. It is very, very exciting stuff.

Yes. Thanks, Roger. And Jay, look, perhaps leading off -- finishing off with the CEO. One quick question that's come up. And this is an unusual presentation in that it's highly technical and it was intentionally highly technical to try and provide support for what we're saying. So we don't expect everybody to understand everything, but the information is there almost as a resource document. It's not a typical glossy investor presentation. That's not what it's intended to be. But the question that keeps coming up, because many investors are generalists, and they don't have the specialist knowledge that everybody on this call may have. And they look across it, in fact, I've got it on my screen here. They look across at the Willow field over -- sorry, the Horseshoe field over here, which Oil Search came into it and paid $3.10 per barrel of contingent resource back at the tail end of 2017. And based on Pantheon's assessment of its contingent resources, we've got a tiny market cap of GBP 350 million or about $500 million. If you do the math, it works out to be, as you said, less than 1/10 of that, Jay, less than $0.30 per barrel. What do we need to do to try and bridge that gap and, perhaps, get a bit of a better confidence in our -- to bring a better valuation into our resources? Jay, is that 1 well or is it 100 wells we need to drill? What do you think we need to do to bring the...

Well, it's 2 things. Sorry, Justin. This webinar, I think, does it. But I think the 3 operations that we are planning for this next season, going back in and testing all the zones at the Talitha-A Well, a well that's already drilled. So that's a relatively inexpensive operation to get all that data. Drilling the updip Theta West, moving that 8 miles or 9 miles and 2,000 feet updip and getting into that thicker section that everybody described that we see on seismic and the attribute analysis and all. Doing that, testing that, getting a test on that, and then in the spring summer, drilling along the Dalton Highway, putting the gravel pad down for a full pad development there and drilling that horizontal well in the Alkaid anomaly and putting that on stream. In my opinion, that gets us 90% of the way to that valuation.

Okay. I have a question here, which I'll pass in the direction of Bob. And Bob, the question is, would you consider Pantheon to be an exploration play? Or has it advanced beyond that in your perspective?

It's definitely advanced beyond that. We are at the appraisal development stage. The last, probably, exploration well in my career was the Talitha-A Well. All the other wells we're going to be drilling are appraisal and development. So we've eliminated the exploration risk. We found hydrocarbons and we're well beyond the exploration stage.

And Bob, what does that mean in terms of both risk of the project, but also confidence or probability of success, if you like, in terms of developing or commercializing these fields?

Well, again, it is -- we're at a much lower risk profile than we were 2 years ago and even where we were from the fall. So we are at 60%, 70% confidence of success.

Fantastic. Jay, a quick question for you, if I may. And back onto this topic of location, a very specific question here. And that is, how important is Pantheon's location, in terms of commercialization, both compared to Alaskan projects, but also perhaps compared to other projects internationally.

Well, I don't think we could say it enough. I mean, we're right next to the Trans-Alaska Pipeline, which is running below 1/3 of capacity. We're right next to the Dalton Highway, which carries all the equipment up to the North Slope. We're onshore. We're not in a terribly environmentally sensitive area. I mean if you're talking offshore, in deepwater, you have much greater logistical issues than we have. It just makes all the difference in the world to be that close to your infrastructure, it makes everything much simpler and easier and less expense.

Thank you, Jay. And Bob, 1 question for you, if I may. If the company's resource estimates are proven to be correct, how significant is this play relative to other plays, both onshore and offshore?

Well, it will be as big as anything anybody's found in the world in a long time. It's -- 16 billion barrels of oil in place is world-class whether you find it in deepwater West Africa or deepwater Guyana. I mean this is a world-class resource. And the resource density as, probably mentioned earlier, research density is comparable to the original discoveries that were made in the late '60s by Prudhoe Bay and Kuparuk. I mean, it's massive.

Yes. Okay. Look, great. Thank you, Jay. And thank you, everybody, today for your contribution to the webinar. Very conscious time, it has gone on considerably. So thank you all, in particular, our special guests, thank you for taking your time out to present for our shareholders who, I know, greatly appreciate it. Thank you to Mr. Darcon, again, for his contribution as Chief Curator of Questions. And I think that's us over and out for now. Thank you, everyone.

Bye, everyone.