Pantheon Resources Plc (PTHRF) Earnings Call Transcript & Summary

Good afternoon, and welcome to the Pantheon Resources plc Investor Presentation. [Operator Instructions] Due to the number of attendees on today's presentation, the company may not be in a position to answer every single question received during the meeting itself. However, the company can view all questions submitted and publish responses where it's appropriate to do so. Before we begin, we'd like to submit the following poll. I'd now like to hand over to Max Easley, CEO. Good afternoon, sir.

Thank you very much, Paul, and thanks for joining us, everyone. We pulled this webinar forward 1 day, but still, I hope it's not disrupting any holiday plans. For today, first, I would draw your attention to this disclaimer. I won't read all of that, but you know what it says as pertaining to -- this is for information only, and we will be making some forward-looking statements. So, use them as you will. So joining me today, you can see on the screen is our Chairman -- Executive Chairman, David Hobbs, as well as our Chief Development Officer, Erich Krumanocker. As you've read today, we issued a letter to our shareholders announcing a number of things today. First and foremost, we're choosing to move forward on Dubhe-1 to do a pressure buildup survey, which means a temporary pause. And this is occurring at about 50% of the load recovery to date. Erich will talk more about that in a minute. We firmly believe this is the right thing to do, both financially and operationally. To put it into context, done a lot of my life on the North Slope of Alaska. And this time of year, we've had three blizzards in the last 2 weeks. And that's a very, very difficult time logistically, very expensive logistically. And the costs we're incurring on a daily basis are north of $150,000 per day, given the depth of winter that we're in. But we proactively raised funds, as you know, in the third quarter of this year with this in mind. So we've been testing this well for some 60 days now, but pushing it into the depth of winter of December and January really is not the best use of shareholder funds. So, we're going to take stock and take our time and learn from what we have already, do a pressure build up and then come back in the Spring. The big point here is we're not done with the Ahpun. The resource remains unchanged. It's just a delay. We also discussed in the letter some forward plans on Kodiak, not only in terms of what we intend to do, but how we might choose to finance that. We'll be discussing all of this over the next half hour or so. Following the presentation, we will be taking some questions and answers. So, we got lots of pre-submitted questions, I believe, 50, and I anticipate getting a lot as we go through the webinar. Hopefully, many of those will be addressed in the presentation itself, but we'll certainly take the time to listen to your questions. So firstly, I'll hand over to David. He'll put all of this in strategic context, then Erich will walk us through what we've learned on Dubhe, what our next appraisal steps are on Dubhe and also what our plans are to mature Kodiak in parallel. So, I'll hand it over to you, David, get us started.

David, sorry, can you just unmute yourself.

There we go. I apologize for that. Thanks, Max, and thank you all for joining us on the webinar. Let me start by saying I empathize with all our investors. This is not the news that you hope for or that we expected in terms of where we're at, pausing for the time being in order to get pressure build up, et cetera, as Max just said. I feel your pain. I'm sitting on a substantial loss, and I'm completely aligned with you and motivated to help drive a recovery for all investors. The -- it's worth reminding ourselves why we're here and what the investment thesis is, and that's what this slide is talking to. We have an advantaged location close to infrastructure for a part of our assets. We have an absolutely world-class asset base. When you look at the Kodiak accumulation, billion barrel fields are few and far between. It's an absolutely perfect time to be progressing a major energy infrastructure project, the tailwinds, particularly federal, but also state for Alaska provide the backing that we require. And of course, the Alaska LNG project and the associated pipeline provides additional growth levers for us. Also over the course of the last year, we brought in experts in the field, recruited Max, Erich, Tralisa, and other technical staff. So, refresh the leadership team and the technical team to make sure it's best suited to moving the assets we've got through to FID development and then production. But before we move on to talking about where we're at on Dubhe, I think it's worth taking a recap on where we set the strategy in 2023 and remember why we're doing the things that we're doing. First thing is Kodiak was always the prize in terms of it being the largest accumulation in the acreage. Its location makes it equivalent to Pikka in terms of development costs, in other words, several billion dollars to get to first production. And frankly, for a company the size of Pantheon, little prospect of achieving that level of capital formation. So, the only option for getting value out of Kodiak in the short term would be some kind of farm-out or partial disposal transaction. And at the stage of discovery and appraisal, remember, Kodiak has two wells in it, the Talitha-A well, right down at the down-dip most easterly location and then in the middle of broadly the geographical area of Kodiak, the Theta West well. It would be very difficult to achieve a farm-out that represented even a fraction of its potential intrinsic worth. So, to have any chance of farming out to a partner at the, of quoted $3 plus per barrel, that might represent, spent a couple of hundred million dollars over a 4-year period drilling sufficient appraisal wells to have reduced the risk to a level that would allow someone to pay a full value. Now by contrast, Ahpun is a collection of smaller reservoirs that are closer to the existing infrastructure. The top set, the SMD-B reservoir is the largest of those, but you've got the zone of interest, you've got slope fans, you've got the SMD-C, but 280 million barrels appraised in the Ahpun field. But near enough to the road that instead of billions of dollars to get to first production, realistically $150 million from FID to first production and $300 million from FID to cash flow self-sufficiency. And during a period of maybe 3 years to get to FID, we'd only have to spend half as much appraising Ahpun as we would have had to have spent appraising Kodiak. And in reality, it's worked out that way. The cost of the Alkaid-2 Re-entry, the Megrez -1 well, the W-1 well, in total, less than $100 million. If we add to a lower cost to get to FID and to realizing full value, the prospects for the least dilutive funding possible, and that includes -- if you remember, when we set the strategy, we said that it was likely to be a combination of one or more of vendor financing, off-taker-backed financing or forward sales. The path we chose and still believe is the best option is off-taker-supported financing. That's the reason for the Gas Sales Precedent Agreement and our coordination with 8 Star Alaska to move forward as quick -- as much aligned in terms of the pace as we can with their program. So, we chose that path and have executed against that in terms of the program and where we're up to. If you remember, the original plan also included the prospects for a U.S. listing. And we -- you'll recall that Pantheon has been talking about a U.S. listing since 2020 at least, but it wasn't in a position to list on a serious exchange any time quickly. So, we took the steps to prepare in terms of putting in place accounting, cost control, governance, including delegations of authority and ensuring an independent Board, that were low-cost steps, that would have reduced a long period to get to any kind of listing to being potentially less than 6 months. And once we're in a position to move ahead with that, we retained advisers to look at potential pre-IPO transactions that would create tailwinds for a U.S. listing. if that proved to be the optimum path for minimizing value dilution for shareholders. We've answered the same way every time the question has been asked. So, let me preempt any questions on that. We're not spending money or appointing lead book runners or undertaking any activity that we wouldn't undertake anyway whether we move forward to a U.S. listing or not. So, it's against that background of de-risking the portfolio, using Dubhe as the path to financing Kodiak such that we were able to retain as much of Kodiak as possible for shareholders and in Dubhe itself would be a useful value addition, that we have drilled and completed the Dubhe well. We're moving upon towards FID. And my expectation is that when we resume that process outside of a Winter season, we remain on track to achieve that goal. But to understand the specific details, let me hand over to Erich to talk about the Dubhe-1.

Excellent. Thank you, David, and hello, everyone. So first of all, what I'd like to do is recap on the key objectives of the Dubhe-1 well. So, number one was to progress our contingent resources as evaluated by the independent experts, Cawley Gillespie. And to do this, we needed to assess the Shelf Margin Deltaic formation, the SMD-B, as we've talked about, for development. This also enables us to prove pipeline quality gas for the Alaska LNG project. So location -- location criteria is a key point here. We really wanted to prognose and confirm the thicker reservoir near pipeline state. So, we actually went down-dip, as you know. And we wanted to also confirm the lateral continuity with the Talitha-A & Pipeline State #1 well. And another really important piece, which David alluded to is the proximity of the road. We've actually wanted to drill this from a gravel pad to be able to execute the long-term flow test. So the outcomes, which most of you are probably very aware. First of all, we did confirm the thicker target reservoir. We executed the 5,000-foot horizontal lateral in the target zone, and we successfully fracture stimulated it. We know the fracture stimulation was good as well, because we got good productivity, which I'll come back to and talk a little bit more about. And right now, we're still in the cleanup phase to really understand our fluids and to understand what our type curve looks like. So, all this complexity to date has been executed safely. I'd really like to personally thank and congratulate our operations team for a job well done. But let's go ahead and look at what the well has produced so far. So, we started cleanup of Dubhe well in mid-October, and this was following the fracture stimulation where we injected 200,000 barrels a day of liquid. This is predominantly water. So a lot of times, we interchangeably will say liquid and water when we talk about our production. We first opened the choke slowly to ramp up. We did this to reduce the chances of pulling sand from the frac and the formation. I should note that today, we have produced minimal solids. I think that demonstrates the quality of the frac and the rigor of cleanup operations. Once we ramped up the well above about 2,500 barrels a day, we allowed the well rates to decline naturally. We produced back some of those injected fluids and let that decline. We didn't fully open the choke up at that point. But shortly after that, we ended up producing gas. Gas production started at low levels initially, but actually ramped up, and you can see that ramp up throughout this flow period. And as the gas started to ramp up in early November, we started to produce small amounts of oil, and we have continued to do so. We initiated gas lift around the 9th of November, so shortly into November. And really, that was to improve our flow rates. The gas lift essentially gets our rates up higher. And you can actually notice that ramp-up kind of past the first week of November, you see a ramp-up on the chart. And since then, we've continued to produce kind of minimal operational updates and weather impacts. There were some small ones in there. You see a little blips along the road, but actually really steady operations. To date, we've produced about 100,000 barrels of water, which is about 50% of load recovery. And we might use this term load recovery periodically. It's essentially the percent of liquids that we've produced back relative to what was injected in the well for the stimulation. So 100,000 out of the 200,000. And so far, we've produced about 100 barrels, a little bit over 100 barrels of mid-30s API oil, fairly consistently with what we've seen in other areas where we've tested. We haven't seen the oil breakthrough as we've expected, and I'll explain that a bit more in a minute and particularly in comparison to our Alkaid 2 flow test in a comparison. But first, what I'd like to do is orient everybody around the location of where Dubhe-1 is. So, this cross-section from west to east, this is in the southern part of the Ahpun field. The main reservoir intervals were discovered in 1988 to that Pipeline State #1 well. Oil was confirmed in the cuttings there, and there was also core was taken and there was oil measured in that core. In 2022, the company drilled the Talitha-A well off to the west and up dip and that confirmed a thinner section of the reservoir, and we also carried out flow tests. These flow tests included the basin floor fan formation as well as the sections above. And we'll come back and talk a little bit more about the Talitha-A test in a minute. So, both of those wells were drilled from ice pads, very much limited to operations only in the winter. In Dubhe-1, we confirm that down-dip, thicker continuation of the main reservoir that I alluded to earlier, and we're able to do it next to the Dalton Highway. And this obviously provides us a lot more flexibility for operations and is actually key and pivotal to our forward plans, I'll talk about later as well. The Alkaid-2 well that we talked about was to the north. It's not shown on this. It's almost into the screen, if you imagine that. And it was drilled from near the highway as well from the Alkaid pad. The stimulation and production from a vertical section in that SMD reservoir at that location produced substantial oil volumes. For those that have been around, they've probably seen lots of that details, but I'll come back and show what the production profile looked like. But now let's go ahead and see how these compare. So, the top chart here shows a comparison of Dubhe-1 and the Alkaid-2 SMD flow tests. The Alkaid recompletion into the SMD zone was simpler with only one single stage. It was essentially a vertical well, as I mentioned earlier. On the chart, the X-axis, which shows the load recovery. So, load recovery is a percent that's on there, and Alkaid-2 shows minimal hydrocarbon production until we get to about that 50% mark. If you notice there at the 50%, there was a sharp increase in oil cut. As you can see on the chart, we've now produced Dubhe-1 in the darker blue there to about the same threshold of around 50%. The lower chart shows Dubhe-1 in comparison to our Talitha-A well. Like Dubhe-1, it started producing gas fairly early, so very similar, and it did produce small amounts of oil. It didn't have that sharp rise. At 65% load recovery, the well stopped flowing. The team at the time believed that this was due to a blockage in the wellbore. Given the poor winter weather conditions and other competing operations at the time, the flow test was stopped. We're not aware of any specific regional analogues for this reservoir and completion other than what we have within our area. But based on a number of engagements we've had with industry peers, there's a wide range of possibilities for load recovery. And again, a reminder, the load recovery is the percent of fluids that we injected for the stimulation versus what we've taken back out. There are other reservoirs we've heard that are being commercially developed around the world that we believe produced up to 100% of that load, basically 100% of that injected fluid and even beyond in some cases, before commercial quantities of oil were produced. So, what's our way forward from here? So, we're going to continue appraisal of Ahpun, but we want to do this in a financially prudent way. So, we know the well is strong. We got a good completion. We saw the high rates, I showed on the chart. We know that oil breakthrough is not as early as we had hoped, but we potentially need to be able to move all the way up to 100% load recovery. The winter operations, as we've alluded to previously in the presentation, involves a lot of cost and risk. Winter operations are not great, particularly if we do have some issues and current operating costs are very high. So, what we want to do is, move into a planned pressure buildup. We installed a downhole pressure gauge in Dubhe-1 specifically to be able to gather this critical reservoir information. A pressure buildup after an extended flow test period provides a wealth of data for appraisal and development includes things like the reservoir pressure, connected volumes, reservoir productivity, quite a few things as well. So, this was always planned. We also want to carry out some special core analysis. From the core that we collected in Dubhe and compare that to the core collected at Alkaid-2 and at Talitha. These results can provide insights into the way the fluids move in the reservoir, so absolutely critical for our ongoing appraisal and development. And finally, we see ways to improve the lift of fluids from the well. I mentioned the nitrogen lift earlier. That did get some lift, but there's opportunities to really improve it. That will increase rates to get 100% low recovery in a quicker, more expedient way and also in a much more cost-effective manner. And the team will be working with key suppliers to develop that plan for restart. But what else could we do? I want to go back to the Kodiak. As David reminded us, Kodiak is our main prize in our portfolio, has a best estimate of 1.2 billion barrels of liquid hydrocarbon contingent resources. That's based on independent experts report from Netherland Sewell. The Kodiak reservoir has been penetrated in three locations, and we've successfully flow tested in two wells, and I'll come back to that in shortly. And in addition, the picture in the upper left shows a map of the estimated improvement of reservoir quality up to the northwest of the field. Essentially, if you see red, the red is better end of the scale, yellow kind of in the middle and the green at the lower end. So, this improvement results in estimated increase of additional 600 million barrels of recoverable black oil resources in the field. So, let's see -- let's look a little bit closer at what that means. So, now we move to a cross-section, kind of orient ourselves. The -- if you look on the upper right of the slide, you can see the pipeline and road to give a sense essentially where we drilled Alkaid and Dubhe from. And then as you move to the west, you can see our three well penetrations. We successfully flow tested oil from the Kodiak reservoir in 2022 in both Talitha-A and Theta West. In this cross-section, you can see the Kodiak reservoir, and it's colored. I've actually colored it in the color schemes exactly aligned with the previous map view. So essentially, the red is the good stuff. The yellow is the middle and the green is the lower end. And you can see that the previous wells there are mainly in the yellow and the green. Up to the Northwest, in the up-dip, we really like to test that higher quality reservoir shown in the red. So, we intend to start planning for the Theta -2 West well to penetrate this upper part of the reservoir and access potential upside volumes. And maybe even more importantly, the volume is potential for higher production rates as well with higher permeability. So, what will this take? So right now, in the Kodiak area, the seismic is reliable to interpret the reservoir in the southeast of the field. You can actually kind of see in the Southeast, those reds, it's kind of nice contiguous area where we've drilled some wells. But up in the northwest of the field, there's a lot of issues. The seismic quality, it's not just on this level on this map where you can kind of see it's kind of scattered in green. We can see it all the way up in the shallow horizons. And we think it's created by just some of the issues in the shallow horizons as well as the Kuparuk River, which runs in that area on the surface. The data was also processed a decade ago, and this is probably not done and even done well at that time in hindsight. The technology for seismic reprocessing has also improved dramatically in the last decade, and we're now using techniques and supported by high-performance computing and AI and machine learning, all these things. So the technology has really moved on. We already have proposals in place with competing suppliers to reprocess the seismic. I also mentioned the core -- special core analysis on Ahpun. That work includes analysis of core from Talitha-A taken from the Kodiak reservoir as well. So, this will help underpin additional engineering and petrophysics assessment of the reservoir and particularly down in Kodiak as well as Ahpun. So success in the early stages of the seismic reprocessing allows us or enables us planning for the Theta West-2 well. And planning really, if things go as we expect, we could be ready and to execute as early as next winter. The well itself will be much simpler to execute than Dubhe-1, essentially a vertical well and the reservoir is shallower than what we drilled to in Dubhe-1. We do have to construct an ice road of the location to be able to drill the well and would be limited to that winter window, but we have a good track record, particularly from the Talitha-A and the Theta West-1 wells in the past. So, there's a lot of potential work to do in both Ahpun and Kodiak. But relative to the scale of the resources that are potentially at play here, it's definitely worth it in my view. We have an active data room in place, and we're working hard with our potential investment partners and really help working with them, if possible, to bring this all to life. But with that, I'll hand back to Max for a wrap-up.

Thanks, Erich, and thank you, David, as well. Hopefully, that answered a lot of questions. We'll get to some more questions here shortly. But moving forward from here, as I mentioned upfront, and Erich just expanded upon it, we executed this well very efficiently. And we had hoped this well would have produced a lot of oil by now. It hasn't yet, but we're not done with it. We're not done with Dubhe-1, and we're not done with the greater Ahpun area. There's a lot more to appraise and figure out. But until proven otherwise, as David said, our strategy remains as is. And we have a delay here, but we still are working toward an FID for Ahpun in the 2027 timeframe. But in parallel, we need to mature the prize, which is Kodiak. As Erich mentioned, we're looking at partners for this. We'll need a well pretty soon, perhaps as early as next Winter. So we'll be looking for partners for that. And we remain in the gas picture for the Alaska Gas line. There's been a lot of news flow on that recently. Maturing that contract is subject to their FID timeline, but we remain in discussions with them to eventually translate a Precedent Agreement to a Full Agreement. As David said, we built a new team in Pantheon over the course of this year. It's a team designed to develop reservoirs. It's the right one to progress this. We've already improved tremendously in execution, and I believe we're the right crowd to finish the appraisal job, not only in Ahpun, but also Kodiak. So, I think it's time to go to questions now, which is what most people really want to hear. So Paul, can you give some instructions to everyone?

Absolutely. Thank you very much indeed, Max. [Operator Instructions] As mentioned, due to the number of attendees on today's call, the company will not be able to cover every single question that we've received today. However, we will be able to review questions and publish responses where it's appropriate to do so. Just while the team take a few moments to review those questions submitted today, I'd like to remind you, the recording of the presentation, along with a copy of the slides and published Q&A can be accessed via your Investor dashboard. Max, Erich, David, as you can see, we've had a number of questions both pre-submitted and throughout today's presentation. Thank you to everyone submitting them. Can I just please ask you to where appropriate to do so, read out the question directed to one of the team and give your response, and I'll pick up from you at the end.

Okay. Very good, very good. So, there's a combination of general, in specific. Let's start out with something pretty foundational. Why hasn't oil flowed yet? There's oil in the reservoir and what's going to be different in the spring? That sounds like an Erich question.

Okay. I'll repeat a couple of things just to make sure it's there, but add a bit to it. So, we -- obviously, we injected 200,000 barrels of liquids into the stimulation. We produced 100,000 back. So, half of it has come back. We obviously hoped for earlier, but that's the first thing. Hopefully, that the chart we showed earlier on Alkaid-2 shows what happens when the oil arrives. We obviously -- we need to be more cost efficient and be able to pull this back. We've engaged experts. I mentioned it earlier, but 100% load recovery is very possible and has existed elsewhere. I think, maybe more important in everything else, is even within the same formation, we've heard that the load recovery varies significantly in the timing. So, even our closest analogues may give varying results. So I think we know there's oil there. We saw oil in the cuttings. We saw oil associated with the gas. Essentially, the gas was associated gas. We've actually measured oil. We produced over 100 barrels in this, and we produced gas to date as well. So, we just haven't gotten there yet is our view right now. So, I think a bit of patience, I think, is one of the things in the team, but we have to do it in a very cost-effective way. So, that's the proposal we have right now is to do that.

Okay. And there's three lightning round follow-ups here. I think I can do these ones. Has the well had any mechanical problems such as blockages, sand, et cetera? As Erich mentioned, we are very careful with this when we started up given the Alkaid-2 result, the way we beamed up the well. We don't believe we have any blockage or mechanical problems in the well. But I do encourage everyone in the modern world, we mentioned a pressure buildup survey. We're not going to go into the math and physics of that, but there is a place you can go get the math and physics, it's called ChatGPT. And one of the things that we'll find out when we pressure buildup is the degree of cross flow amongst the stages. And so that will give us infer -- we can infer there's no blockage as well. Second lightning round question was, is nitrogen required for the well to flow? As Erich mentioned, we're using nitrogen for artificial lift. For a period of time, the well flowed naturally. And we converted that to gas lift using nitrogen up until we paused the well over the weekend. And the last one lightning round question was, where does that 150,000, a day come from? That sounds like a lot. In broad, broad terms, this is amplified logistically because you can imagine minus 40 degrees Fahrenheit or Centigrade with howling wind, about 50,000 a day is the nitrogen itself. About 50,000 is the testing equipment. The disposal of the water is another 30,000 and the remaining 20,000 are miscellaneous things like personnel, et cetera. Again, those are all amplified by the logistics challenges of Alaska in the deep winter. All right. Another question, I think I covered this one. But what does this mean for a GSA for the gas line? So, the Gas Sale Precedent Agreement with 8 Star, Glenfarne, operator of it, again, that GSA will be on the timeline for their final investment decision. So, we are engaged with them in discussions on this. And again, Ahpun is delayed, not canceled here. So there's no reason to suspend that. So, we're in active discussions with them, but really follows their timeline. All right. What else do we have here? Just one for you, David. You sort of covered this. But what's your current view of the commercial viability of Ahpun? And what did you mean as an envelope of expectations? Where are we in that envelope?

I knew that, that phrase would come up. It was in some of the pre- -- the previous asked questions as well. The point we're talking about was we didn't expect to see any oil before we saw oil. The envelope of expectation, therefore, is when is the earliest we might see it, when is the latest we might see it. And when 2 weeks ago, when we were talking about it, we're at 40% recovery of the frac load. And just to be clear, it's not like a piston where you put frac water in and you get frac water back and then one day, it stops being frac water and it's either oil or it's formation water. It mixes within the reservoir. So, what you're getting back is initially pure frac water and then a mixture of fluids and eventually you're expecting oil to cut. So, we have been and frankly, still are, given that analogous reservoirs have required substantially more than 50% load recovery before they cut to significant oil, we're still within that window of expectation that the oil will flow. There's no data that would allow us to conclude that it's not going to do. There's no data that would dam the Ahpun field or indeed the prospects of the Dubhe well cutting to oil. So, in terms of where expectations are, it's a pause. I think you said it right upfront. It's a pause, not a stop. We stopped when we did in order to ensure that we had the financial capacity to restart at some later date that we didn't want to find ourselves in a situation where we were betting everything on, will it turn to oil tomorrow and what will our cash situation be at that time, that far better to make sure that we remain in control of that process, preserve cash, take the opportunity to do the pressure buildup survey that we knew we had to do anyway and use that time to plan for what is the approach and cost structure that is going to deliver the greatest chance of economic success. I think that, that's -- I think that may probably goes further than the question, but hopefully helpful insight.

Okay. And a couple of, I'll cycle back to you, Erich here. One -- two lightning round questions. One is, do we know where the stimulation fluid went into the reservoir? And the second one is, can you speed up the flowback?

Yes. Okay. Yes. First one, in terms of where it went, we -- I think, I've seen some of the questions coming in. I think we've communicated pretty well. There was 25 stages in the stimulation and all were successful. So, we know went into all those stages. I think there's an inherent question I see coming through on the questions as well about, do we know have we put tracer into the well and where did we -- where -- is it coming back? We didn't put tracer in, and that was actually a very conscious decision around cost. It was going to be extremely costly. But to be honest, our dynamic flowing, we're going to get -- first of all, the pressure buildup will give us some information. But actually in our dynamic flow period, we've had no indications that we've lost any sections and the productivity looks that all stages are producing. At some point, we might do more diagnostics, but I don't think that's an issue based on our productivity and what we've done there. In terms of speeding up the flow, I mentioned the nitrogen lift earlier. So, we did use nitrogen lift going. One of the forward program plans is to really speed that up. There's a couple of things we can do. Right now, we're not nitrogen lifting from the bottom of the tubing. It was built, they designed specifically to open up with a slightly different hydrocarbon column. So, we can actually just specifically put an orifice down at the bottom and lift from the bottom. But probably more expediently, we could actually put a submersible pump down into the well. And we've already started getting some quotes about what that would take. And that's very much a process, particularly since we haven't produced any solids to date, it seems like it could be a good option. We obviously wouldn't have done that previously given our history in the field and particularly having sand production and sand blockages that would destroy an ESP. But right now, given the quality of our simulation, that looks like a very feasible option. But we want to get this right. We want to do this in a very prudent manner from a capital perspective.

Great, Erich. And here's a question that will be very, very important to many shareholders, if not all. Given the $27 million of liquidity in the letter, how will you prioritize Ahpun versus Kodiak? First thing I would say is, there's no need to raise capital in the near term. As David mentioned, I think I mentioned as well, we very prudently raised a surplus of capital in the third quarter with this eventuality in mind. But when you think about Kodiak, that's a major capital item. As David said, on a stand-alone basis, that would be a very large endeavor, which is why we're seeking investment partners into that. So, there's some things we can do in the short term with the funds available, but any large, large cap items will require a farm-in partner, and we're proceeding with those discussions. Anything you want to add to that, David? That's a really important question.

I think that there -- absolutely right. Let me just come back to Kodiak, because I know people have been asking if Kodiak has surprised, why aren't we focusing on that? Let me go back to what I said right at the start. To appraise Kodiak to get to a point at which its intrinsic value would be recognized, would need to be spending at least a couple of hundred million dollars over a 4-year period. That's more than twice what we have spent trying to bring Ahpun forward. And the benefit of bringing Ahpun forward is that, it would provide the capital funding and also because Ahpun partially overlies Kodiak, there would be lower cost into the appraisal of Kodiak. So, the focus on Ahpun first is because it would allow shareholders to retain far more of the value of Kodiak than if we were to focus on appraising Kodiak in a conventional way, it would require 5 or 6 wells, probably $40 million to $50 million each before you'd get to a point at which industry recognition of value would recognize the same intrinsic value that our shareholders do. But as Max just said, the cost of drilling a Kodiak well, Erich, we thought was sort of in the $35 million, $40 million, including the testing and whatever other data evaluation. That's clearly beyond what we would be able to do. And what we should expect shareholders to fund given where we're at, the dilution inherent to raising equity for that versus the potential for an industry transaction means that definitely, the responsible thing to do is to be pursuing farm-out activity as -- I think, Max, you just mentioned.

Okay. And here's another foundational one, and you may want to chime in on this one too, David. How should shareholders interpret management confidence in the reservoir given this result? From my perspective, the potential of Ahpun is unchanged. If we were still flowing the well, we would be saying patience is required. As Erich said, this could be a wide range of outcomes on the water coming back before the oil. We've suspended it and decided to do the pressure buildup survey now mainly for financial prudence, because north of Alaska in the middle of winter is not for the faint of heart. But we know there's hydrocarbons in the system. The graph that Erich showed, we had an increase in gas rate throughout this entire period. So, we know there's hydrocarbons in the system. We're just going to be patient with it. And as I mentioned, there's no immediate need to raise capital, but you can do the math. $150,000 a day plus if you ran this out to 100% load recovery, that would be a sizable sum to do that and unnecessary and to do it through the winter. So, it's a good time out to plan very carefully. And the question about artificial lift was a good one. We can make some changes to that and get off the nitrogen and spring, lots of things we can do. But the main reason our confidence hasn't changed is there's no reason for it to change. We're being patient with the reservoir. This well is very stubborn, but we'll be patient and hopefully, we'll get the good result we're looking for. David?

It's not just stubborn. It's strong. If you look at how much it's flowing and how difficult it's been to get the drawdown as low as you'd expect, because the reservoir keeps flowing. And I've seen a number of questions, people -- maybe I wasn't clear enough when I said, during frac flowback, it's not a piston displacement. It's not that you get back all frac fluid and then it turns to reservoir fluid. It is that it mixes in the reservoir. So, we've been recovering during that 100,000 barrels, a significant portion of that is reservoir -- connate water in the reservoir that is mobilized by the increase in water saturation from the frac. So, we're getting back a mixture of frac water, formation water, oil, gas, and we just haven't got to the point at which it has cut to substantial oil. But coming back to the first part of the question you asked, how should shareholders read management commitment, because there are a number of similar questions that take that from a different angle, which management aren't buying lots of shares. People have said, if the share prices dropped, if management aren't buying shares, then surely, they're not confident. There are a couple of easy, clear technical points to make. The first is, it's a closed period in the 30 days prior to publishing any results. We expect to do that next week. But for the last 30 days, it doesn't matter what press releases we put out, how we plan to the market by regulation, they're not allowed to buy shares. Before that period started in any case, we have a share dealing policy that tries to ensure that we are not going to be judged with the benefit of hindsight to have done something where people say, well, they must have known. And so, we've had a close period for insiders during the period from when we started to drill this well through until -- through to today. And to pick up on something that, again, just so you're aware, if we're in substantive discussions that might lead to a farm-out, we would similarly be unable to trade in shares. And our policy is very clear. We are not going to allow management to trade on inside information. So, you can't read anything about commitment into whether or not management are buying, because there is no open period for them to be able to do so. And we're certainly not going to get into a game of every day, are we open or closed, because actually revealing that information may itself be revealing inside information. So I'm sorry, you'll have to bear with us in terms of the commitment to expectation in the future. I can tell you, I share every bit of Max's confidence that this is not -- we have no basis in the information to change our view of the likelihood of a successful outcome, but it was absolutely the prudent thing to do based on wintertime cost structure to pause and plan for a restart in the spring.

Okay. A couple more -- Erich, you're very popular. A couple more for you here. On Kodiak, when will you know where you're going to drill and how much it's going to cost to drill?

Okay. Yes. I think, David already talked around the cost side. So $35 million to $40 million, depending on really the scope and scale data acquisition. Just a reminder, I think I mentioned earlier that will require an ice road. So, if the ice road and an ice pad to have a limited period of time to be able to do testing, that was the benefit of Dubhe, obviously. But what will it take to get ready? So, seismic reprocessing. The first stage of the seismic reprocessing, probably the first 5 or 6 months, that will really give us a good sense of the seismic attributes of the area to clean up that really spotty area that I showed on the map earlier. And that's really the key components we want to identify the target. Really want to find a part that's contiguous relative to the rest of the reservoir that we've already produced successfully down-dip. And then later, the reprocessing will continue beyond that, but at least allows us to give us a good point for planning. We also already have core at the lab for this -- the special core analysis. So, this special core analysis, we expect the results in 1Q, and that will be essentially built into our petrophysics models and reservoir engineering models. So that will be lined up very well. And then we can kick off well planning. So well planning is not only the technical side, I will say this well is going to be very, very simple relative to what we've just achieved on Dubhe-1. It's a vertical well, it's shallower. So quite a bit easier from that perspective. But also that well planning does require the permits and the permits to put the ice roads, et cetera, and then to really start engaging with our supply chain to make sure we have the right, I guess, technical capability, but also the right financial position from our contractors. So, I think, it kind of gives a good sense. I mean, we want to be in a place where we have the planning to be able to do this next winter. So, assuming everything lines up, we could be seeing a well as early as next year.

Okay. I guess I can take these next two lightning round ones. I guess with an eye toward the GSA, someone is asking, is there any CO2 or helium in the Dubhe gas? I'm not aware of any CO2 in it. So, it's as expected there. Helium, only a very trace amount. The only reason we know that is when we drilled the pilot hole, we had instruments very, very carefully watching the gas shows as we drilled through and there was a tiny trace of helium, but we never anticipated any material quantities of helium in Ahpun. And there's one sort of disputing us here that says, if this well is so strong, why do you have to use nitrogen to lift it? These are normally pressured reservoirs. They're not overpressured reservoirs. This well did flow quite strongly without lift for quite some time, but it's producing almost entirely water. And so, as a result, nitrogen assists that. So it's still flow, but it makes to flow better. So it's not an indication of a weak well by any stretch of imagination, but it just assists flow. And there's another one I'll ask you, Erich, just popped up, which is, why only 10% load recovery in the last 3 weeks?

Somebody has done some quick math on the chart, I assume. I mean, essentially, it's decline. You can see we still have the chart there. The decline of the reservoir, as Max was kind of talking around the lift and whether the well is strong or not, we have a column of water in here. When you get the oil breakthrough that we showed that happened at Alkaid-2, you get a lighter column of oil versus water. So the oil itself is lighter, but you also get the associated gas. The gas rates jump up. So essentially, there's this thing -- I mean, in fact, it's hard to see on this scale, but quite often, as we're going through this. The minute we saw some of those ramp-ups of our formation gas, we would actually see the water rate, in this case, the fluid rate really would step up as well. The well was lifting itself. So, we're on a trend that if we continue, there is a chance that we could actually have the well start lifting itself from its formation gas downhole. So back to the original question of why 10%, it's declined. That's exactly why it's taken time and the reason why we want to do a pressure buildup now is because we want to -- we need to get that data. It was planned in the original plan, and we want to come back with a way to get that much more cost efficient and much more expediently. That's the intent.

Okay. I guess the -- we're running out of time. So, I -- the last question would be, what can you expect -- what can the shareholders expect in the next few months from us? So, we're taking this pause. We have a lot of analytic work to do. We have to plan for a restart and progress Kodiak. So we have a lot of work to do. We have the restart plan to build. And as that comes together, we'll certainly be conveying that as well as firming our plans for Kodiak. We're planning for spring activity, I suppose, I would say. Anything you want to add to that, David, from the Board perspective?

No, we will obviously have information coming in from a variety of sources. And just to be 100% clear, we will announce anything that we're required to announce. Aim is pretty clear on continuous disclosure obligations. And I just want to pick on one example of -- just to make sure there's no misunderstanding. We put out a press release this morning, because over the weekend, we took the decision to shut in the well. That was a material change. We needed to report that. And so we ended up having to put out a press release. We don't have the flexibility to decide and to schedule news to suit ourselves. So, as we get information, as we have insight that the objective is to make sure that to the greatest extent possible, shareholders understand what management is thinking so that they can then judge for themselves. And we've tried our best to make sure that you know what management is thinking by revealing the results of our analysis, and we will continue to do that. And certainly, as we move into the new year and we start planning for next operations, there'll be information ahead of that. In the short term, of course, the AGM, which we anticipate being in March, will be an opportunity to meet with and talk to shareholders face-to-face and to discuss further. The other thing is there are a lot of questions here that we just didn't have time to get to without it becoming too long and dragged out. As we've done in previous sessions, we will aggregate and try to answer as many in writing so that they are posted on the webinar website. Other than that, Max, back to you.

Okay. So I think we'll draw the Q&A to a close. I didn't see anything huge we didn't address. So thanks again, everyone, for listening. I know we're approaching the holiday season. A couple did comment that we're disrupting their holiday plans. I apologize for that. As we sit here today, this is not the result that we wanted at this stage, but it is a result we have. But what everyone should feel confident is we're not done with this yet. So we have plans to go from here, both on Ahpun and Kodiak. As David mentioned, our annual report will be issued next week. So, for people with questions about our statement of accounts and things like that in the AGM in the first quarter. So again, thank you for your time, everyone. Much appreciated, and thanks for the questions. Really good questions in there. Hopefully, we addressed them. And as David said, we'll work toward getting this published more formally in due course. So thank you, everyone. Back to you, Paul.

Fantastic. Thank you indeed for updating investors today. Can I please ask investors not to close the session to be automatically redirected to provide your feedback in order the team can better understand your views and expectations. This will only take a few moments to complete and it's greatly valued by the company. On behalf of the management team of Pantheon Resources plc, we'd like to thank you for attending today's presentation. That concludes today's session, and good afternoon to you.