Hello and welcome to the Pantheon Resources AGM webinar. I'm Jay Cheatham. I'm the CEO of Pantheon Resources. Today, you'll hear from our Technical Director, Bob Rosenthal, and one of our Consulting Geologists, Dr. Ed Duncan. We also have a special guest with us today, our newest member of the board, David Hobbs, who I invited to participate in this webinar. First, I would like to acknowledge that we're aware of all the turbulence that's gone on in the last six months, especially in Pantheon share price, and we understand the frustration that shareholders feel. During today's webinar, we'll talk about our lessons learned by Pantheon management. Also, I wanna dispel some of the disinformation that's in the marketplace about Pantheon. Bob and Ed are gonna talk about some of the achievements of the last year and talk about Alkaid- 2.
Then we'll talk about our path forward and value accretion for Pantheon. Jerry, if you could put up the map, please. Please, everyone, look at the disclaimer. This is an updated version of the map we normally show of the North Slope of Alaska. Thanks to Jerry Nichols, he's made it an interactive map when you go on our website. It has a lot of data on it. To the north is Prudhoe Bay, the original discovery for the North Slope. Lying about 20 mi south of that is the Pantheon acreage. In the sort of turquoise color is the 153,000 acres that we have, including our two units, Alkaid and Talitha. We're also in the process of beginning the process for a unit on Theta West.
Outlined in turquoise is the approximately 40,000 acres that we were the high bidders on in this past year's lease sale and should be awarded soon. As many of you know, I joined Atlantic Richfield Company because of their announcement of the discovery of Prudhoe Bay. That was back in 1969. The original DeGolyer and MacNaughton independent expert report for Prudhoe Bay had the oil in place number at 10,000,000,000 bbl and the recoverable number at 3,000,000,000 bbl. Today, the oil in place number at Prudhoe is in excess of 30,000,000,000 , and the recoverable is in excess of 16,000,000,000 . Two things to take away from that. First, big good fields get bigger and better. Secondly, normally, the initial independent expert report or CPR report is very conservative.
Now, it's not a direct comparison, but our oil in place numbers are circa 20,000,000,000 bbl, and our recoverable resource is a little bit in excess of 2,000,000,000 bbl. We sit right along, as you can see, the Dalton Highway and the Trans-Alaska Pipeline, which is terribly underutilized. If we go to the west, way out west is the Willow project by ConocoPhillips in the National Petroleum Reserve-Alaska. That means federal land. That is a 600,000,000 bbl of oil equivalent development with a development cost of $8 billion to get to first oil. That was recently approved by the administration just two weeks ago. That is not only good for Alaska and the U.S., but I believe it's good for the world.
If we go down to the south, there's a well, the Hickory- 1 well, that is only 500 ft below our southern lease line. That well spudded a couple weeks ago as well. That well will test the SMD, the Slope Fan System, the Basin Floor Fans, and the Kuparuk. We look forward to 88 Energy having success there. Before I turn it over to David, I also wanna let everyone know that we've added Tony Beilman to our technical team. Now, Tony's a petroleum engineer with over 40 years of experience. He specializes in executing horizontal drilling and completions in these horizontals. I've known David since his ARCO days. He will help our company in communications, strategy, partnering, and David also has just a lot of good common sense. Over to you, David.
Thank you, Jay, and good afternoon to everyone here on this webinar. I'm David Hobbs, a petroleum engineer and energy strategist, and I don't wanna spend too long talking about myself as you can read the specifics of my background on LinkedIn. In the big market profile, there is a link to my LinkedIn profile. The highlights are that I've spent nearly 20 years in operational and business development and commercial roles in the upstream oil industry, and then the next 20 years in policy and business strategy advisory roles at CERA, which is now part of S&P Global, and then at KAPSARC in Saudi Arabia. Between sailing across the Atlantic and around the Caribbean, been doing some consulting and structuring work, in between.
For the avoidance of doubt, I previously had an online presence as Telemachus, and I mention that because I'm a firm believer in transparency, and that will allow people to put the two together. Now to the present day. The question I've been asked most often in the past couple of weeks is, why would I join the team after the beating the company's taken on Twitter and in the markets during the past several months? First, let me say I've got the utmost respect for what's been achieved to date in discovering and starting to appraise a truly world-scale resource, measuring more than 20,000,000,000 bbl in the ground and an expectation of recovering at least 10% of that. There's also been some questioning of the integrity and competence of the team. I've got no doubts on either count.
It doesn't mean there have been no missteps or that there's no need to increase the organizational capacity to better meet the challenges ahead. As I say, I have no doubts as to the integrity and competence of the management team of Pantheon. If you look at a share price chart over the past couple of years, I think we've seen this picture before. Go back to the spring of 2021, and the share price was pretty similar to today's. Back then, the share price had fallen out of bed after what was an inconclusive test of the Kuparuk Zone and running out of time to test the main pay zones in the Talitha well. However, once the market had digested the full well results and understood the forward plan, it recovered.
We hadn't then drilled the updip well at Theta West that confirmed the giant scale of the Basin Floor Fans, nor had we drilled and flowed the Alkaid- 2 appraisal well, which we will undoubtedly discuss further during this webinar. Back then, the market was focused on how much money would be needed to appraise and develop the resource to a point at which it could either be sold in whole or in part, or be brought into production by the company. Just as I was back in the spring of 2021, I am today confident that the quality of the resource base and the recognition by management to build the team and recast elements of its strategy to move to the next stage, and that will underpin a recovery in the company's fortunes.
For example, you heard earlier that Tony Beilman had come on board to add his experience in engineering and operations as we graduate from proving up in-place volumes to establishing the most economically robust means of recovering those resources and turning them into revenue and value. I'm confident that in the coming weeks and months, the additional actions necessary to meet investors' concerns and demonstrate that management understand the challenges and have a plan to implement a successful strategy will become clear. Perhaps there's no more tangible demonstration of that confidence than that my not insubstantial holding is now public and restricted through director dealing rules. If I had any doubts about the outlook for shareholders, I would hardly have accepted the board's invitation to join the team and place myself under those restrictions. Now, back to Jay.
Thank you, David. Excuse me. Jerry, on to the next slide, please. We have listened to the feedback from shareholders, and we definitely have some lessons learned. We know we need to improve communication to shareholders. We endeavor to do that. We recognize that we are a small team, and that we need depth to execute our forward plan. Keys to that are bringing in a partner or a farm-out, farm-in ee that will help strengthen the team. As you know, we've added both David and Tony to that team. We need to tighten our cost control. Clearly, we took our eye off of the ball with our permanent facilities, the expansion of which we undertook while we were drilling the Theta West well. We endeavor to do much, much better on tightening our cost control in the future.
Thirdly, we know we need to reduce the execution risk vulnerability that was demonstrated in our inability to get timely equipment on site, especially at the Alkaid- 2 well. I call this we have no purchasing power. To that end, we're looking to partner and to have that power through that partner. Secondly, we're working on a plan to partner with some service providers on the North Slope to have availability to a coiled tubing unit and a workover rig. Next slide, please, Jerry. There have been a lot of misperceptions and market disinformation, and I just wanna talk through some of those. The top box, questionable resource claims. We even heard the word fraudulent used over and over again. But what's the reality? Well, if it's fraudulent, then SLB, Baker Hughes, AHS, Lee Keeling, Netherland and Sewell, Wood Mackenzie are all part of that.
The state has awarded us two units which recognizes the underlying hydrocarbon accumulation. This is either an uninformed or deliberately distorted view in the market. Second block, Halliburton relinquished 25% of the entire project for no value. The reality is Halliburton had a 25% interest in six of over 60 lease blocks. That was about 2.5% of the project working interest. We later dropped two of those blocks. Halliburton's a service provider. They like to receive money, not pay money for operations. They no longer had a unit that would compete with their customers by taking working interest. They were the partner of record for the Oil Search project. What did they give up?
They gave up 2.5% project working interest to avoid payment for back costs and a release from future liabilities. Thirdly, Alkaid- 2 flow condemns Pantheon acreage. Bob and Ed will go through this in detail, but just let me say that there is extreme variability within reservoirs, much less across different reservoirs in a more than 10 mi resource base. So you'll see that later. The fourth one was that the NGLs and condensates on the North Slope are worthless. Well, that is not true because all of the liquids that are not burned and produced on the North Slope are blended and sold as Alaskan North Slope crude at Valdez. ANS normally trades at a premium to Brent. One last item before I turn it over to Bob.
On Alkaid- 2, we're getting close to having the data we need to achieve our objectives of understanding the EURs, and that's as the production starts to level off. Just a reminder, this was always a test well, not a production well. To be a good citizen, we do not want to flare excessive volumes of gas, NGLs and condensates. Plus, we will eventually need that vertical wellbore to test the Shelf Margin Deltaic above that lateral. As a result of that, we may not ask for an extension of our pilot-flaring permit from the state of Alaska. Now, over to you, Bob.
Hi, I'm Bob Rosenthal. I'm the Technical Director of Pantheon Resources. Again, like everyone else, I would like to say, you know, I appreciate that you are attending this webinar. Look, I'd like to spend a few minutes going on describing where we're at and what we've done this year and, you know, what are we doing to move forward. First, I'd like to point out that we drilled the Talitha- A well back in 2021. As David pointed out, we were unable to test the main objectives in the Talitha- A well in that year.
In the winter of 2022, we began testing the Talitha- A well, and we spudded the Theta West well, which was an appraisal well of the Talitha well, 10.5 mi step out. While we were testing Talitha- A, we were drilling Theta West. We tested multiple zones in Talitha, and they were light oil-bearing. We then went over to the Theta West well and tested the Lower Basin Floor Fan, 1,500 ft up dip, and like I said, 10.5 mi from Talitha- A, and we found light oil in the Lower Basin Floor Fan, which conclusively showed that we had a huge accumulation of light oil in the Theta West Lower Basin Floor Fan.
As Jay's alluded to, we only found out a couple of days ago that WoodMac has published it as being the fourth largest discovery in the world for 2022. Back in 2021, IHS said it could be one of the top discoveries of that year. You know, that's where we stand there. We believe we have 17,000,000,000 bbl of oil in place in that and we're evaluating it. Immediately following the Theta West discovery, we were planning and executing and drilling the Alkaid- 2 pilot hole and then the Alkaid- 2 horizontal well. As Jay's alluded, we are finishing up the long-term production testing of that well.
At the end of all this is we, you know, we found out the sort of like earlier or late last year, based on all the results that we've had and announced that 88 Energy announced that they were going to drill, and they have spudded the Hickory- 1, which is 500 ft south of our acreage, and they are testing the discoveries that we already have, which is in the SMD Slope Fan System, Basin Floor Fan, and they're gonna go down and test the Kuparuk as well. These numbers that I've been talking about are oil in place numbers, and we have a resource of about 2,000,000,000 bbl.
Pantheon, over a period of four years, has found 23,000,000,000 bbl oil in place, over 2,000,000,000 bbl of recoverable resource, all of which has been tested, and that is at about $0.10 a barrel finding cost. Which is pretty good. More than pretty good. That's very good. How are we moving forward? I think David very eloquently said, you know, what we need to do is move from resource to recoverable resource, recoverable reserves. At the end of the Theta West testing program, we engaged with Schlumberger to put together their dynamic and beginning of a static model and the beginning of a dynamic model, which would discuss how hydrocarbons would move through each one of our reservoirs.
They came up with an oil in place of 17,800,000,000 bbl across our number of reservoirs that we have. What we are doing today with them is moving forward on the dynamic model so we get a recoverable resource. That's really important to understand. They are putting together the dynamic model. We'll have a recoverable resource, and we'll update the static models that we have, which will include the new leases that we've acquired in the last lease sale. We're actually engaging with one of the top service companies in the world to help us optimize development scenarios through all our reservoirs. Now, this is important for a number of reasons. Primary, it's for us to understand how we're gonna move forward and develop these different reservoirs.
It's to get to a recoverable resource, but it's going to be very important in our farm out, our partner meetings. This is the information that they are going to be looking at in detail to make a decision about our acreage. Now, we've also engaged with Schlumberger to provide the data room. They've actually, you know, said that was something they volunteered they could do, and they said they would be quite happy to present the work that they have done to potential farmees and partners. At the same time, we've engaged with Netherland, Sewell to get an independent expert's report, the first one we have on the Theta West resource. Because we're working with Schlumberger at this time, we'll also have a recoverable resource with that and have an IER on that Theta West discovery.
We're also going to update the Alkaid resource based on the Alkaid- 2 result and looking to get an Alkaid reserve. Again, all this, having all this together is important to us in terms of, you know, finding a partner and, you know, finding a potential farmee. But also important to us, we see them as part of our team in moving forward to, you know, optimize our drilling technology or drilling and completion work, optimizing location of our next wells, and moving forward in evaluating these different resources and getting it to a recoverable reserve. I think I'll turn it over to Ed Duncan, and Ed's gonna take you through a few of the findings that we saw at Alkaid- 2 and talk about some of the implications of what it all means for the rest of our reservoirs.
Thank you, Bob. This is Ed Duncan. I appreciate your time and attention. As always, it's a pleasure to present and speak to you through these virtual meetings, these webinars. We're gonna reflect back on Alkaid- 2 for a bit. Much of this you perhaps have already seen in previous webinars and previous discussions. Let's just hit a couple of the high points here. The slide in front of you has two important bits of information. It's a vertical looking well profile, but that's actually the lateral. The toe at the bottom, the heel of the lateral at the top of the log traces on both the eSeis process well log data and the Halliburton mud log. We see 5,213 ft net oil pay across the horizontal, continuous oil from heel to toe.
Effective porosity is ranging from 8%-18% with an average of 12%. Importantly, this well has de-risked the eastern extension of the Greater Alkaid structure. You probably have heard us talk about effective block in the past. Well, that's what we're talking about here, the eastern extension of the Alkaid. Oil from heel to toe. We penetrated oil-bearing reservoir in the pilot hole below the zone that we went in the lateral. This was a target, a stated target for the pilot hole to test to see the extent of oil beneath the primary zone of interest. We've proven that oil-bearing to TD. Importantly, we penetrated the oil-bearing extension of the regional Shelf Margin Deltaic play. This is a play that was really focused and centered initially on the Talitha- A well. We recognized it in the Alkaid-1 well.
We tested it here in the Alkaid-2 well, and we'll see in the next slide. Jerry, if you can advance. You'll see the shelf margin oil pay zone on the left-hand side, the Baker Hughes AHS volatiles panel. Lots of colors on this, so we won't go through those in detail, but the three columns in the middle with the green shaded areas, those are the oil pay zones. The SMD Shelf Margin Deltaic play at the top, and the Alkaid zone of interest oil pay zone in the lower section. Focus also on the very left-hand side of that AHS volatiles panel. The red dashed lines from top to bottom are the samples taken by any measure, comprehensive.
These data and all of the geochemistry we've run, all of the test results we've run, are being incorporated by SLB, formerly known as Schlumberger, to update the static and dynamic models that Bob referred to in the previous presentation. Schlumberger is also critically reviewing the volume of gas that we're producing, and they've presented a possible scenario to explain the volume of gas. Perhaps we have encountered a gas cap, a small gas cap in the Alkaid structure. What's interesting about this conclusion or this scenario is that we have three independent data sets collected while drilling that illustrate unequivocally that we were in oil from heel to toe while drilling. What we believe we may have done is the stimulation may have fracked up into the gas cap that lies just a few tens of ft above the oil zone.
We're going to investigate this further. We begin the second phase of the SLB work in a couple of weeks. This will be a headline topic for the next phase of the evaluation as we update the models and improve the accuracy and fidelity of those models. Next slide, please. We classify our projects and our reservoirs by play type. By play type is defined by the reservoir bearing depositional system. For example, deltaic system versus the Basin Floor Fan system. Two distinctly different reservoir systems that have different critical controls on reservoir distribution and the resulting nature of the plays themselves. The results at Alkaid-2 are going to apply to Alkaid.
It's a separate play from the Shelf Margin Deltaic, the Basin Floor Fan, and the Slope Fan System. We can't take the results of Alkaid-2 at reservoir level and transfer those definitively across to the Basin Floor Fan, the SMD or the Slope Fan System. That is just not going to happen. It would be an incorrect thing to do. We see significant variation in reservoirs, actually, even within the same plays. We see different reservoir character based on depth of burial, different reservoir character based on grain size. All of these things we understand. We've collected data. We've reviewed that data.
It's incorporated into the model now, and it's going to be continued to be incorporated into the model going forward with SLB. I think probably the highlight on this slide is really the important point for us, and that's the Huron quote from June of 2022. There's zero chance that the result at Alkaid is gonna reduce their enthusiasm for the main prize of Lower Basin Floor Fan at Theta West structure. This is a quote that came out before the WoodMac citation of being the fourth largest discovery globally in 2022. That's the grand prize. All of this can be great, but that Lower Basin Floor Fan system is truly massive. Next slide. Speaking to variation within the same depositional system, the same play type.
Talitha- A and the Theta West one well both penetrated the exact stratigraphic succession cyclic reservoir deposition of the Basin Floor Fan system, but separated by 16 km , 10+ mi. Talitha- A, the deepest, greatest depth of burial. Theta West, 1,500 ft shallower. Same reservoir system penetrated at different depths of burial. From Talitha- A to Theta West, that's 16 km. That's a big step out as we've discussed in the past. A 60% improvement of porosity. That's exceptional. Now, when we look at our acreage further to the north and west, the new acreage that we've picked up, we can go another 1,000 ft updip. That's gonna manifest itself as yet even continued improvement in the porosity of the Theta West Fan reservoirs. The dash profile that you see here is our predicted histogram. If you will, for porosity in an updip position from the Theta West- 1 well. We know the reservoirs are full of oil. High 30s API, sweet, light crude. A fantastic result and a lot of running room yet to come for the Theta West Fan. With that, I'm gonna pass it to David for a review of key takeaways.
Thanks very much, Ed. I'm pleased that I have had the opportunity to now have a look at the technical data, discuss with the technical team, and present some preliminary conclusions to you on the takeaways from the Alkaid- 2 well and the several months of testing, coming at it on the outside with a fresh pair of eyes. The first thing to say is that the reservoir quality, as demonstrated by the total fluids rate, is better than pre-drill expectations. The well flowed more than 1,000 bbl a day of total liquids, notwithstanding that the gas flows would have restricted the amount of liquid that could flow through the pore space. So in the absence of such large gas flows, the liquids rate may well have been better.
That comfortably exceeds the pre-drill guidance of 150 bbl per day per 1,000 foot of lateral. If you recall, one of the pre-well concerns raised by some people, some commentators on Pantheon, was that there wouldn't be enough gas. There was an estimate of around 600 cubic ft per barrel. There was a concern that there wouldn't be enough energy in the system to meet even a 10% primary recovery factor. In truth, what we've seen in gas is much more compressible than water or oil, so it provides the energy to maintain flow without reservoir pressure dropping as much. In simple terms, gas volumes that we've seen and the reservoir being as close to the bubble point is good news.
The flow test tells us there's plenty of energy in the system, and that may well translate into higher primary recovery factors. Of course, if this was a thin reservoir, the presence of the gas would be a problem because it would be difficult to get away from the gas. This reservoir is very thick. There's plenty of space to separate future wells from the problem. Whether the gas flows are from a thin gas cap or they reflect how close the reservoir pressure is to the bubble point at the top of the reservoir, the fix is the same. We will complete future wells further down the oil leg, where the differential between the bubble point pressure and the reservoir pressure is much greater, and that leaves a much wider margin for production without gas breakout and will allow higher flows of pipeline quality liquids in subsequent wells.
My key takeaway really is that any technical reading of the data suggests that the likelihood of commercial viability of the Alkaid project is higher today than it was prior to the well. We've gathered enough data to address some of the risks identified pre-well, and the deliverability of the reservoir has been shown to meet or exceed those pre-well expectations and comfortably exceed what's required to underpin commercial development.
I would finish by saying that in addition to the potential of the Shelf Margin Deltaic above it, the location that this well is drilled from is highly likely to be a key center for commercial oil and pipeline fluid flows going forward because the resource that sits under it can be accessed with horizontal wells and potentially in due course, even commingled, so that we see higher rates in aggregate per well than even the Alkaid lateral itself has demonstrated as being achievable. With that, back to Bob.
Thanks, David. I just want to finish some of the technical talk on just this one slide. What you see here is the hydrocarbons found over from 2015 to 2021. This is the, you know, recoverable resource numbers. They include oil and gas. Those are the total volumes found over that period of time. On the right, you see what I would say we found over the last couple of years. That's all oil. So that's the Pantheon. The little brown box there is the Pantheon resource that we've actually found. If you just look at compared to 2021, so all the thousands of wells drilled in 2021, we found approximately half the same resource that they found in that year.
Again, there are some key bullet points that came in with the WoodMac publication. I think, you know, highlighting it, there's, you know, again, the fourth biggest global discovery in 2022, probably the largest onshore discovery in 2022. As you see in there, Theta West pushes our resource estimate past 40,000,000,000 bbl oil equivalent threshold for Alaska. This is, you know, a lot of oil that we found. We're very focused on moving that oil in place to really getting it to recoverable resource and recoverable reserves.
Thank you, Bob, Ed, and David. Of course, that's what we all want. We wanna move recoverable resource to recoverable reserves. Jerry, next slide. This is our final slide. This is our value accretion story. There are a couple of metrics on this slide. In the upper right hand, it's the $3.10 a barrel that Oil Search paid for their entry into their Horseshoe-Pikka project back in November of 2017. On the left-hand bottom is Pantheon, valued at about $0.11 A barrel of resource. The lower left block is what we've accomplished to date, and Bob talked about that. The middle, 2023, that's what's underway.
The two independent expert reports or CPR reports by Netherland, Sewell , the SLB work that Bob talked to you about, the multimillion-cell static and dynamic model, the data room, et cetera. For 2023, it's what we have planned. What is on our to-do list. Test a new Alkaid well, a new Theta West well, a new Talitha well, and test the SMD at Alkaid. People might think that we're a long way from reaching that summit, but we're not. We're well more than halfway up that summit. Now, yes, there's a lot still to do, and we recognize as a small team that we'll need to add to that team in the future to reach that summit. We're a long way towards that summit. I think it's time for the Q&As now.
Thank you, Jay. As always, [Mr. Darcon] has very kindly curated a Q&A list for us. I'll endeavor to go through those as best I can. I do think that many of the questions have been answered throughout the course of the presentation. Nevertheless, we'll get stuck into it straight away. Jay, the first question I think you can address while you're there, it's on the SMD. There's a question concerning the method of flow testing that, given it will be in the Alkaid- 1 well or the Alkaid- 2 wellbore. How would you go about undertaking that SMD flow test in that wellbore, Jay?
Well, first of all, we would test both of them in the vertical section. Alkaid- 1 obviously was a vertical well. If we went there and that would be an ice road test and more expensive, that would be in the vertical section. But also in the vertical section in the Alkaid- 2, we would come up hole from the horizontal, which is in the Alkaid anomaly, up into the upper portion right above it and test the vertical SMD at that location. I just point out that, Justin, that the SMD there was actually better than we had anticipated. It was a surprise on the upside as we were drilling through it.
Thanks, Jay. Jay, if that was the case on drilling through, why wouldn't you have flow tested the SMD first and then gone down and perhaps done the Alkaid section second in that order? Is there a reason for that?
Well, of course. You test from the bottom up, Justin, because you have to plug off the lower zones as you come up the hole to test the upper zone. You test from lowest to shallowest.
Gotcha. Jay, while on the topic, another question here on Alkaid in particular. Given the production of the NGLs and the condensate, which of course we're not currently stripping out, there's a question here asking whether or not there's a financial case to purchase the equipment necessary to extract those NGLs and condensates and to allow them to be sold. Can you answer that, please?
Well, everyone must remember that Alkaid- 2 is actually a test well, and it's not a long-term production well. The liquids production was a bit of a surprise, so in advance, we didn't know how much NGLs and condensates we would produce. Since it is a test well, there probably is not an economic case to spend the dollars required to put in a refrigeration unit, plus the time that would that's required to one, permit it, you know, secure the facilities, move them up to the North Slope and install them. It's not economically feasible until we probably go into full field production.
Jay, I guess from a practical perspective too, given, we only have the ability to flare gas for certain periods of time. We [crosstalk] can only-
Right. Yeah, exactly. It's a test well. It's not.
Yeah.
It's not a long-term production well.
First one is to you, Jay. It's clear from the presentation that we've just heard that Pantheon has enormous volumes of oil in place. You touched upon, I think on that last slide there, but how do we go about moving those large oil in place numbers to value for our shareholders?
Well, I think Bob answered a lot of that, and it's the data room, bringing in a partner. That, you know, that solidifies value. And just executing better and executing on our future to-do list of the three new wells and the testing of the Shelf Margin Deltaic at the location at the Alkaid- 2 well. Those will move that needle way up toward the top of that summit.
Yeah. Jay-
We understand execution is a key in this.
Understood. The first point, bringing in a partner, we've said this before, I mean, we have opened up a data room before and ultimately didn't come to culminate a transaction for a farm in. What's different today here in March 2023 than in previous years, whether you opened up the data room?
I'm gonna jump in. I would say the big difference is, you know, we've tested oil at Talitha, we've tested oil at Theta West. We're flowing oil at Alkaid and selling it, you know, moving it down the Dalton Highway and selling the oil. Those are massive differences. I'd say another huge key difference is all the work that's been done by Schlumberger over the last, you know, five or six months. Again, started that in June and the ongoing work that they're doing now. You know, having these dynamic models, actually, you know, 3D visualization of the subsurface, having those models together with all, you know, which is the input of all our data is, you know, it is completely different than where we were in December 2021. Massive difference.
Yeah. Bob, actually, it's not only having tested, for example, Theta West. We hadn't even drilled those wells the last time we had.
That's- [crosstalk].
The data room open. Yeah.
Oh.
It is a massive difference. Just on the subject of operations, it's well known that we experienced some significant operational delays this season. What can we do to avoid those or minimize that, minimize the risk of those going forward? Bob?
Well, probably the biggest problem we had this year was being able to access workover rigs. Again, we've talked about having one on standby, and it moved out and you know, it had a catastrophic failure when it was doing other work, but we had problems you know, post that you know, waiting on workover rigs or waiting on coil tubing, and that was one of the major causes of our delays. What we're trying to do is actually partner, possibly partner with other people or partner with the service providers in such a way that we would be kind of first in line for getting this coil tubing rig or having the workover rig.
We recognize that is one of those points where you have the biggest chance of having a delay, and we're focused on solving that, and there are a number of ways of doing that. That could be, again, working with other companies to possibly, you know, buy a rig or, you know, have one that would be on call or having a partnership with one of the service providers and providing us with a rig.
Yeah. Thanks, Bob. A question that's come back from a number of investors is: Why didn't we have a spare rig parked to the side just in case, you know, it was required?
No. Absolutely none available, period.
Yeah. Okay. Well.
It's hugely expensive to do that. It is hugely expensive.
Yeah. Actually just on that topic, we touched upon it previously. There was a rig that we thought we may have been able to get, but we crossed over this period from summer to winter. Can you just explain what the difference is between the summer season and the winter season in terms of requirements for drilling equipment?
Well, the main difference is the rig needs to be winterized properly for winter operations. This particular rig, the state had deemed that it was not winterized properly and therefore we could not use it during that period. You know, we asked the state for a waiver, and they turned us down. That was not an option for us.
Understood. Thank you, Jay. Jay, you mentioned a strength here of the team earlier on, and we've heard from David today, and you also mentioned Tony Beilman. How important is it to continue to strengthen our team or to supplement our team, perhaps with advisors or consultants going forward?
Well, can I jump in there
Of course.
Answer that? I think we've done that by. Well, what I would say is bringing Schlumberger into, you know, what into what I would call our team. As we are moving forward with the work program, the completion design, everything, we've engaged with Schlumberger, which is a huge service provider, to help us. They're not just. You know, they're just not putting out this dynamic model and saying, "Here you go." They're coming up with, you know, to work with us to how we're gonna develop, you know, these fields. How are we going to drill the wells? You know, where are we gonna place the wells? So it's very much considered part of our team now.
Thanks, Bob. Of course, we're using extremely high quality names as partners too. On that topic, you mentioned Schlumberger to help us with our modeling. We've also mentioned earlier in the presentation we've contracted Netherland and Sewell to do some resource or re-resource statements for independent expert reports for us. Bob, can you explain the difference between what Schlumberger will be doing and what Netherland and Sewell will be doing?
The independent expert or Netherland and Sewell is coming in, and they will be looking at our dataset. They have a very strict guideline on assessing resource or reserves, and those numbers have a very strict meaning behind it. We're working with Schlumberger to put together the fundamentals, i.e., the reservoir models and put all the data together and help produce all the maps that then Netherland and Sewell will come out and look at to evaluate to get to their analysis.
Thank you, Bob. Look, a question for Ed, just moving across to the Alkaid result. Ed, what is the estimated size of the gas cap that we believe we've encountered at Alkaid- 2 versus the total reservoir size? How big is it?
Yeah. Aerially it's quite small. Volumetrically, well, it depends on ultimately how thick the gas cap is. If it exists at all, most likely less than 5% of the gross rock volume.
Okay. I've got a question here. I might pass this one over to David. Given that Alkaid's only less than 4% of Pantheon's resource base, how does the outcome of that well in your view relate to the stock market reaction that we've seen?
Well, Justin, I think there are two parts to it. The first, as I mentioned earlier, the review of the data actually underpins the quality of the reservoir and the resource. The first thing is, looking from the inside, that's the result has not been as negative as it's been perceived. I think that the market reaction has been more to do with a mismatch between expectations of outcome and the actual outcome. The presence of gas in larger volumes and the potential of a gas cap has obscured
A simple understanding which would have allowed people simply to say pre-well expectations were guided as 150 bbl per thousand foot, and instead seeing while it requires more nuance than that. In a market that was primed to be disappointed, the reaction has understandably been negative. The important thing will be to find a way of demonstrating clearly the deliverability of the reservoir and its commerciality. I believe that Netherland and Sewell work when they review the data as an independent expert, taking no guidance from Pantheon as to how to interpret. That's part of the underpinning of an independent expert's report. If their confirmation that the data does indeed support the underlying commerciality because of the deliverability of the reservoir that was demonstrated. I believe that will help rebuild some confidence in the value of that resource and indeed in management's understanding of the totality of the resource base, so that people can look across and see that they can trust what's being said about Theta West, the SMD, the slope fan systems, as well as on Alkaid.
Okay. Look, great answer. Thanks, David. Actually, you mentioned some other reservoirs there. A question here for you, Bob, a bit further down the list. It concerns the SMD. We've mentioned that there's the opportunity to test the SMD on the Alkaid unit. Can you explain the pros and cons essentially of testing the SMD at Alkaid one versus the Alkaid-2 wellbore?
Well, Alkaid- 1, or I'd say take the positive first is Alkaid- 2, you know, we've got a great vertical hole there. We've got a good cement job. We have good logs, good VAS that indicates that we have good reservoir with oil in it. Great place to test it. You know, we're on a gravel pad and, you know, we're right next to the road, which means we can do that at any part. You know, we can do that during the summer. We don't have to build an ice road. We don't have to build an ice pad. It's much cheaper and it'll give us a good shot of testing the shelf margin delta.
Bob, for the non-technical people out there, given it could be in the same wellbore, in the Alkaid- 2 wellbore, is it independent of the Alkaid- 2 horizon? Or would the results that we've seen in Alkaid- 2 in any way impact an SMD test in that wellbore?
No. Again, separate reservoir, separate test.
Brilliant. Thank you very much, Bob. Just while I have you here, Bob, stay there. I have another question, and it's this question of chances of success or probabilities of success. Somebody's noted that other companies out there publish probabilities of success relating to their various horizons. Can you give us your interpretation of probabilities of success in relation to the reservoirs on Pantheon?
We have flow tested oil at the Lower Basin Floor Fan, and too, that there's not a probability we're gonna do it. We've done it. We've tested oil in the Slope Fan. It's not a probability if that's gonna happen. It's happened. We've tested, you know, we're flow testing oil out of the Alkaid anomaly. It actually is moving hydrocarbons. It's not a probability of moving the hydrocarbons. Our goal now is to move to commerciality. Commerciality has a lot of functions associated with it. You know, it has oil price. You know, how much is it gonna cost to drill wells? You know, what kind of facilities you need to put in place? All of that. We, you know, talking about what is our probability of success of, you know, testing oil at Theta West is, well, it's one, 'cause we've done it. Now it's about putting together the program to move these numbers to recoverable resource, to commercial reserves.
We have a question here on the cash position or Pantheon's present funding position. Just with respect to that, at the end of December, we reported that we had about $16 million cash in the bank, and obviously there's been some further expenditure on that, most notably on the Alkaid- 2 well. Our latest cash position will be disclosed when we publish our interim results at the end of this month, so not too far away. Of course, as is always the case, additional capital is gonna be required for the next stages of our development, be that drilling, leasing, G&G or general corporate purposes. The board, as we always do, continues to evaluate all those options for funding, whether it be through a farm-out, as we mentioned earlier in the presentation, that's commencing.
Although the data room is certainly opening pretty soon, or from any other sources. This is always the case for Pantheon, and nothing has changed in that regard. Just a couple more questions. Bob, this one's for you. Jay touched upon the Hickory well being drilled just, I think, about 500 ft south of our border, spotted in the last 10 days or so by 88 Energy. Testing a bunch of the targets that Pantheon has in its acreage. Bob, what should shareholders be looking for as a Pantheon shareholder in any logs or results that they publish.
Well, I think, first of all, they're probably not gonna be able to test this winter. So what I suspect they will see is hydrocarbons in the Shelf Margin Deltaic and the Slope Fan System. Possibly tag, you know, tagging the Lower Basin Floor Fan at a kind of a distal level and finding hydrocarbons in that as well. Again, you know, it's only 500 ft from our acreage, and we wish them luck.
Bob, you mentioned at a distal level, you know, for the non-techies, what does that mean? Is it deeper or is it a similar sort of setting?
Well, as a whole, the reservoirs have been buried deeper. In terms of the Lower Basin Floor Fan, distal means possibly slightly different kind of reservoir quality than what we're seeing at, sort of in the heart of the Theta West fan.
Yeah. Understood. Look, a question here on upcoming news flow. I think most of these things have come out throughout the course of this conversation, actually. While I'm here, I can probably run through them and you can add if I've missed anything. Obviously, we'd be expecting a Netherland, Sewell report on Theta West. Expecting a separate Netherland, Sewell report on Alkaid. Bob, Schlumberger or SLB, should I say, completion of phase II of their project. Obviously, we've got the data room to look forward to. Perhaps there'll be some news from there. You know, we don't know until that process is underway, but certainly that will be opening. We're excited about that. The ADAC Energy World that we just mentioned, Hickory, there'll be some news flow concerning that over the next month. Anything else that I've missed, Jay or Bob?
No, no, Justin. I think, for the immediate news flow you've got, you've got it all.
Fantastic. Just, I think really one or two more questions and then we're done. The next question concerns Pantheon's profile and what we can do to increase that profile. Historically, of course, we made an effort to keep a low profile while we were prosecuting our acreage strategy. But now, of course, we have a much more secure acreage position and a very large acreage position, and we've got an opportunity to increase that profile. Bob, can you give me your thoughts on what we can do in terms of increasing our profile to industry?
Well, probably one of the biggest events that has increased our profile has happened over the last, you know, two or three days, which is the WoodMac report. You know, Wood Mackenzie's come out and said that, you know, last year we made the fourth largest discovery in the world. That. You know, a lot of people, you know, read the, you know, WoodMac information. So that's a major change for us, you know, to be included in the conversation of the huge accumulations that have actually been found on the North Slope. So that's a big change. The Willow approval and the moving forward of the Willow project out in the NPR again will get more eyes onto Alaska.
You know, Jay alluded to, you know, we're going to have some independent expert reports that are done. Again, you know, one of the things I'd like to highlight is, you know, when we talk about, you know, Schlumberger and working with Schlumberger, they, you know, they do a lot of their own evaluation of our data. They don't just, you know, we don't just give them, you know, numbers and say, "Crank this stuff out." They, you know, they look at it, and if they saw something wrong, they would be telling us, you know, very quickly that this is where we don't agree with you. Getting, you know, the Schlumberger work out there, getting the independent expert who comes in and evaluating that, getting these reports out there, these different things will, you know, certainly increase our profile over the coming months.
Bob, I'd just like to add a couple of things. One, our discovery is onshore, so it's the largest onshore discovery in the world last year. The other ones are in deep water. Secondly, with the addition of the acreage that we were the high bidder on in last year's lease sale, we no longer have any commercial vulnerability in showing what we have to the large players. It's a different ballgame for us now. We'll be along with SLB showing everything we have to the people that come through the data room where we had some inability to do that in the past.
Jay, it's interesting, isn't it? I mean, just from perhaps for some repetition, our current acreage position is about 153,000 acres, and the new acreage is about 40,000 acres. But even if there was zero resource associated with that, our numbers, you know, are still so large that there's so much potential for really any company to come in and exploit. It's a really huge opportunity we have ahead of ourselves, and our job is to increase the profile, increase, you know, the obviously the stock price for shareholders and the presence of Pantheon as a company in industry. Look, guys, I think that wraps up the questions for this presentation. A big thank you to everybody for contributing. Jay, did you have any final words as CEO that you want to pass on before we conclude?
Yeah. I wanted to thank all the listeners, everybody that watches it live, everybody that'll watch it, later. I especially wanna thank Bob, Ed, and David, for their contributions. We have an exciting time ahead of us.