Good afternoon, ladies and gentlemen. Welcome to the Pantheon Resources plc operational and funding strategy update. Throughout today's meeting, investors will be in listen only mode. Questions are encouraged, could be submitted at any time using the Q&A tab situated on the right-hand corner of your screen. Simply type in your question at any time and press Send. Given the significant attendance on today's call, the company will not be able to answer every question it receives during the meeting itself. However, the company can review all questions submitted today, and we'll publish those responses where it's appropriate to do so. Before we begin, we'd like to submit the following poll, and if you give that your kind attention, I'm sure the company would be most grateful. I'd now like to hand over to Executive Chairman David Hobbs. Good afternoon.
Thanks very much indeed, Mark, and thank you everyone for joining us today. We're gonna be going through three things. We're gonna be talking about the pathway to $5 barrel value recognition. We're gonna be talking about the reduction in the prospective funding gap to get to financial self-sufficiency, and we're going to be talking about near-term value catalysts. With that, the slides have been posted to our website, so you'll have an opportunity to review the disclaimer at your pleasure. Let's move to what has become a traditional first slide in most of our presentations. If you're new to Pantheon, this map is a simple overview of what we do and where we do it. It shows two world scale fields.
The first Ahpun discovered in 2015 but tested in 2019. That was the Alkaid Horizon, which turned out to be the smallest part of the field, around 5%. The majority was discovered in 2020 with flow tests in 2021, and it's expected on stream in 2028, which is lightning speed for a new field development in Alaska rather than just a satellite to an existing field. The second giant field, Kodiak, was discovered in 2020, but only properly encountered in the 2021 field at West Well. That field is expected on stream by the end of the decade. Again, lightning fast for a field independently assessed at 1.2 billion barrels, with significant growth potential when compared to other North Slope fields in terms of timetables such as Willow and Pikka-Horseshoe.
Many of you already know the company, and you'll know that over the years, we've tended to skip through this map, succumb to the temptation 'cause it's telling us something that we already know. If we compare what it looks like this year, to what it looked like last year, there are some really important differences. We've added substantial additional acreage. We've had independent validation of both the volumes and the values of the oil. We've recognized gas resources for the first time, and those gas resources are a path to funding the oil development, which is where the real value lies in the longer term.
Today we're gonna take you through the progress of the last 12 months, explain how that fits into the strategy we outlined a year ago for achieving our goal of value recognition in the $5-$10 per barrel of ANS crude, that in that range, based on the reserves that we expect to be able to book by the end of 2028. We'll be achieving this strategy by securing FID on Ahpun and then on Kodiak, with Ahpun to be generating positive net cash flows, so that we can become financially self-sufficient. Nothing that we haven't told you before in that regard. Let's look at the scorecard for the last 12 months and see how we've done executing the strategy we laid out.
In the past 12 months, we've secured resource validation through independent expert reports on all the resources being brought forward for development. The contingent resources, the sum of Netherland, Sewell & Associates, Cawley, Gillespie & Associates and Lee Keeling and Associates, is just shy of 1.6 billion barrels in the best case, and just over 6 trillion cu ft of natural gas. The prospective resources added through the 2023 lease sale are more than 600 million barrels in the eastern portion of the Ahpun field, which we expect to be able to drill and prove during the course of the coming year.
Of course, in that same lease sale, we secured what has added around 250 million barrels to Kodiak, taking us up to the 1.2 billion barrels there. That lease sale increased our total estate by nearly some 65,000 acres, so bringing us to nearly 260,000 acres. That now covers everything we consider to be prospective in the Ahpun and Kodiak fields, and economically accessible. We've added gas resources to the map because we've secured the start of a long-term relationship with the state of Alaska through AGDC to provide in-state gas for the next 20-40 years.
That gas transaction has helped us reduce the prospective funding requirement from what was expected to be up to $350 million a year ago to potentially as little as $60 million to get to FID on Ahpun, and $85 million if we end up having to drill an additional Ahpun appraisal well along the way. The company's understanding of the assets has moved forward significantly as we've optimized the development working with SLB, formerly Schlumberger, on the detailed modeling. We've engaged with the Alaska Department of Natural Resources and the Alaska Oil and Gas Conservation Commission as well.
One thing that clear and for the benefit of the long-term relationship, we're not gonna be sandbagging the state of Alaska to try and get approval for anything other than the resources that we have. There would be a risk to the long-term ability to expand if we tried to pretend it was a small field and then revealed from behind the curtain the much larger field. We will be finishing the appraisal of the Ahpun field to submit the full field development plan whether it's for 400 million barrels or 1 billion barrels if the eastern Topsets are oil-bearing, as we expect based on seismic analysis. The scale of that leads us to a path for.
It leads us to a path for environmental and regulatory approvals by 2027. We talked back in June, back in that June press release on the gas deal. We talked about two to three years for an environmental impact statement. We're talking about production in 2028. Yeah. Sorry, FID 2027, production 2028. In terms of sort of some of the less exciting things, but nonetheless, very important professionalization of the company. We've upgraded the governance, shortly reaching a point where a majority of the board will be independent directors. We've got committee chairs with the requisite skills and experience.
As we move to a U.S. listing, the conventional composition of a board means that you'd only have from the executive, you'd only have the CEO and potentially the executive chairman, if that was a separate role. So that will cement the majority independent directors on the board. We are strengthening the management, technical management, particularly Tony Beilman coming on board. We've seen the benefit of that in the trouble-free recompletion of the Alkaid-2 well to demonstrate the new frack design, which the success of that has underpinned most of the work done by SLB and internally on expected well performance in the upper end Topsets.
We've also strengthened legal and financial oversight in appointing Pat Galvin now as General Counsel for the group, Josh McIntyre as Group Financial Controller. We've brought Phil Patman on board, who's driven the IPO process forward significantly, including working with Josh and Justin on the restatement of accounts, the U.S. GAAP, on the controls and documentation of processes to become Sarbanes-Oxley compliant. Generally strengthening the organization's infrastructure so that it is able to match the task of developing a multi-billion barrel development rather than just from time to time exploration activities. We've validated the resources.
We had the initial Kodiak report in August last year, but now the updated report to incorporate the new acreage, we've had Cawley, Gillespie & Associates who do, amongst others, Hilcorp's work in Alaska, and Lee Keeling and Associates had obviously previously looked at the Alkaid zone. Not only creating volumetric estimates of contingent resources, but also an economic evaluation, because that's a key step in the development planning process. Once we have a fully appraised interest. Something's gone wrong with the internet connection. Has it? Are we back?
We can still hear you, David.
There was flashing across my screen that it was paused. We will have a development plan for Kodiak once we've completed the appraisal of that, and we'll be able to assess the economics at that time. If we think about one of the consequences of trying to run the independent expert reports in parallel, in order to shorten the timeframe, was that we've now had three different independent firms reviewing the geotechnical story, which certainly has helped increase our confidence that it's been thoroughly peer-reviewed. Our own internal estimates for the development economics show that they're strongly economic projects.
The individual well economics that we've published before, based on type curves for each area of the field, provide better than 100% rates of return. Importantly, profit to investment ratio is above two. That's a threshold for the point at which drilling new development wells becomes liquidity enhancing because each new well supports a debt capacity at least as large as the cost of drilling it. The key importance of those independent expert reports, and part of the reason for wanting to accelerate them was that we needed to demonstrate that it wasn't just us saying that we had economically viable oil resources with associated gas resources, but that we needed to demonstrate that to move those discussions forward.
Those have provided a critical underpinning, both in terms of, if you remember, one of the contingencies that you need to satisfy to move from contingent resources to reserves, is an assessment of economic viability as well as export routes as well as markets for products, and finally then FID and development consents. That's the reason that we've started off down this route, and getting them complete has allowed a number of other things that are ongoing to be done. If we look at the gas, the gas is a path to funding the oil. It's a pretty important part of the puzzle.
What I think is not immediately recognized to people who've become jaded by the years or even decades of history of there being a gas project being talked about. Our low-cost supply, effectively zero marginal cost of supply gas, with a short lead time 'cause it doesn't require significant capital equipment to be built, changes the game for the Alaska gas project. It allows a phase one, independent of whether there is a subsequent LNG development, independent of whether there's a CCS plant, up in Deadhorse. It allows the development to go forward and meet the growing demand for natural gas as the Cook Inlet output begins to decline. At a materially lower cost than the alternative of importing LNG, or paying for a substantially larger project, including gas treatment.
It's really transformed the economics of that project. We're now fully aligned with the state in terms of being determined to move it forward. As that moves forward, and we turn the gas sales precedent agreement into the fully termed gas sales agreement, carrying over the terms that have been agreed in principle, that you can see in this slide, we estimate that on normal commercial lending terms, it'll support a debt of at least $250 million. As we mentioned in the original release, we have a number of options working with the state, where if the state can reduce the cost of accessing that level of funding, then we will reduce the cost of the gas.
I can't breach confidentiality to tell you the detailed specifics of that, but there are a number of different discussions going on with the state about how we access the most secure, lowest cost funding at the same time as delivering the lowest cost gas to the state of Alaska. There is some potential for CapEx saving from not having to drill as many disposal wells. That's a relatively minor impact on the overall NPV simply because we will still be injecting gas. At full production, we'll be producing more than 1 billion cu ft of gas a day. That will still require gas reinjection.
Of course, if the pipeline is shut down for any reason by operational interruption, we need to be able to reinject the gas because we certainly don't wanna be shutting down the oil because of a downtime on the pipeline. Nonetheless, it's definitely a positive in the right direction. We said that we would provide an update. You know, we gave you two dates that we talked about.
We said we would provide an interim update at the end of the first quarter, and we did when we talked about the general picture, and that we were leaning towards the offtake or financing rather than vendor financing because we were, you know, on the cusp of agreeing the deal with the state of Alaska through AGDC. We said we'd outline the full funding strategy and tell you what the picture looked like at the end of the second quarter, and that's what we're doing now.
I don't think we've ever said that we would sign definitive agreements with money in the bank today, and we've taken steps to ensure we've got the runway, financially to avoid counterparties being able to leverage any weakness as we bring the initiatives that are currently underway and that we'll describe, to a close. Bluntly, we'll do the right things in the right order and only worry about the short-term daily, fluctuations of the stock price to the extent it influences long-term choices the company has to make. Our goal is to make sure we've always got multiple choices, so that we don't rely upon the stock price or any individual counterparty being able to leverage us.
The steps we've taken so far, as I say, we've brought that prospective requirement for $350 million down to no more than $60 million-$85 million. We have done a lot of the preparation for a U.S. listing to be completed in the middle of around the middle of next year. We're currently juggling a number of different discussions, whether it's structured instruments, industry type transactions, whether it's a farm out swap or whatever it may be, and then looking at debt-based and equity alternatives. Obviously we've got the U.S. listing I mentioned.
The strategy is always to make sure we've got plan B, C, and D, so that we're never forced to take a bad option, that we're always able to take the best possible option. I'd illustrate, you know, how that has shown itself in the past. We had established, if you like, a tradition of making the amortization payments on the convertible bond in stock. That had led to predictability that had allowed the stock price to drift as we moved into the quarterly amortization period.
By placing the stock into tight hands so that it wasn't guaranteed to be available and therefore to be sold into, we created a situation where, in fact, we've made the last two payments in equity, but the price didn't drift into the equivalent price at which we've issued that equity has been higher than otherwise it might have been, and it's been higher than it was a year earlier. We've avoided substantial element of dilution from reducing the number of shares having to be issued. We will continue to do whatever it takes to avoid any greater dilution than is necessary. You know, I'm speaking as a shareholder, Justin and Jay are substantial shareholders.
We have an interest in avoiding dilution, and it's what we live and breathe every day. The other thing, again looking forward, is illustrative of what we've done in the past. You know, just over a year ago, the general market narrative was there's too much gas, it's a liability, and it's potentially going to weigh this down, and reduce the viability. We managed to turn that into an asset, and to support a reduction in dilution by so doing. Similarly with the helium, it's not something that ever appeared before because until we had a valid path to market for it was a valueless resource. Today, helium is a much more strategic product.
You know, the discussions we had about vendor versus offtaker financing. Offtaker financing in the long run will most certainly also include oil offtaker VPPs or the equivalent. The time frames for VPP funding are typically when production is imminent or already underway. With gas, there's the infrastructure to be built, so people are much more comfortable about structuring contracts that allow pre-funding two, three years ahead of actual gas deliveries. Similarly, you know, with helium, it's a strategic resource where the ability to access what could be a substantial helium resource. You know, we've shown you in the past, the numbers were between 0.5% and 1.5% of the gas in Kodiak.
As Netherland Sewell has shown, we've got associated gas of about 5.4 trillion cu ft, which implies somewhere, you know, in a mid-case range, around 50 billion cu ft of helium. That is no small quantity, and therefore potentially an asset that we can leverage in a transaction to bring forward financing that reduces the equity requirement. As I said, playing the options to bring to conclusion, but filling a $60 million-$85 million residual funding requirement in the way that relies on equity least and preserves the value for our existing shareholders to the greatest extent possible. If I move on to you know, what do we think the path is going forward in the short and medium term?
Today the company is valued at around $300 million. That's twenty cents a barrel in round numbers. Taking the independent assessments of Ahpun by Cawley Gillespie and Lee Keeling shows $2 billion or about $5 per barrel on the just shy of 400 million barrels there. That's equivalent today to $2 per share. You can see the potential as we begin to de-risk or as we continue to de-risk, because I think we've done a lot of de-risking over the last 12 months. The company is definitively in a better position with a better understanding of the resource more engaged in the individual steps along the way. Our priority is obviously in the short term executing the funding strategy.
That is what will allow us to get to the point where we can access post FID funding. We've got clear visibility on the development plan and the steps necessary to be taken. We're seeking to raise the necessary funds to reach FID, which will include covering a well on the eastern Topsets Megrez. That will establish whether the top sets there are oil productive as we expect. Not forgetting there is always a geological risk, but we've been 100% successful where we've drilled on the basis of the analysis of our 3D proprietary seismic, working with eSeis.
We'll be completing the appraisal process for Ahpun, which may involve, as part of the closing on the Alaska pipeline and on the Ahpun pipeline, a Talitha -B well, which would be to confirm gas deliverability. AGDC will be undertaking their FEED along with their pipeline partner, Enbridge. In the meantime, we'll be working on the U.S. listing, and if we execute our strategy of always having additional options at hand to create competitive tension, we'll have funded ourselves ahead of the IPO such that anything we do in the IPO is a matter of company choice rather than financial necessity. Those steps will take us through to FID on Ahpun , as I say, it's a two- to three-year period.
In the best case, sometime in 2026, and in the worst case, sometime in 2027, and through into production, which is a matter of months, but certainly within a year of that FID. Somewhere along the timeline, you know, moving up that value staircase, a lot of the value is the de-risking to a point where the success of the development program becomes inevitable in the eyes of the market. Once it becomes inevitable, we think that we'll be sitting nearer the $5 a barrel than the $0.20 per barrel. I can't imagine that we won't crystallize that value if we continue to deliver in the way we have in the last 12 months.
That's the reason why we are confident in the ability to deliver the overall strategy that we set out a year ago of targeting sustainable market recognition of $5-$10 per barrel. With that, Mark, I'll turn it over to you for further Q&A.
That's great, David. Thank you very much indeed. Ladies and gentlemen, please do continue to submit your questions using the Q&A tab situated on the right-hand corner of your screen. Just while David and the team review your questions submitted already, I just like to remind you that a recording of this presentation along with a copy of the slides and the published Q&A can be accessed via your Investor Meet Company dashboard. David, as you know, you received a significant number of questions ahead of today's presentation. You've also received a number throughout. If I may, just hand back to you to read out those questions where it's appropriate to do so, and I'll pick up from you at the end.
Yeah. Well, absolutely. Thanks, Mark, and we'll run through those. The first one was about our goal was stated in terms of 1C, 1P numbers. Jay, do you want to just talk about what the numbers we've had are and provide some context there?
Yes. Cawley Gillespie and Lee Keeling did not provide 1C and 3C numbers. Netherland and Sewell actually did provide us with the range. The Netherland and Sewell April report, which included the additional acreage and the 250 million barrels that David alluded to, has about 375 million barrels of ANS crude, 1C and 2.2 TCF of gas. Now, I would also like to point out that the 3C numbers are 2.84 billion barrels and 11.75 TCF of gas. Kodiak is a huge field. It's gonna get bigger and better.
Yeah. Just to be clear, that's the reason that there's more work to do on the appraisal of Kodiak to narrow that range, which we would expect would be as likely to increase the bottom end as to come down.
Exactly.
Um-
Sorry, David or Jay, perhaps somebody could explain the difference between 1C, 2C, and 3C, just for those that don't understand.
Yeah. That's the 10%, 50%, and 90% probability numbers.
It's the C is the contingent resource. Once you've removed the contingencies, which will include FID, then you'll be looking at P numbers rather than C numbers. So proved plus probable. So a 2C is a mid-case conventional contingent resource. A 2P number is proved plus probable reserve. With regards to a U.S. listing, non-U.S. resident or non-U.S. citizens are exposed to a 40% estate tax. Just to put people's minds at rest, we've always said, and I know Justin has answered a number of individual shareholders who've asked the question, we intend to maintain a U.K. listing for as long as it makes sense for the company.
One of the things that wouldn't make sense for the company is to suddenly create a barrier to investors from anywhere to be holding the shares. U.K. shareholders have a particular set of tax circumstances. Singaporean shareholders have another different set of tax circumstances. American shareholders have them. We're aiming and have taken tax advice to try and make sure that we don't unnecessarily disadvantage anyone. Next question was, well, it presumes there's a flexibility to proceed with a smaller scale project prior to the natural gas pipeline. There is an opportunity to proceed with an oil project that doesn't require the gas pipeline. In fact, that's our base case. All of our planning is done on the basis there won't be a gas pipeline.
The total resource base we have to consider because there are two elements, I mean, at least two, but two major elements to a regulatory approval. One is the footprint, you know, the surface footprint, and the local air quality footprint, that sort of thing. There is the second part is an assessment of the downstream emissions impact. As soon as you get to a resource that is larger than a threshold level, you're into an EIS, which is that longer-term process. Just to be clear, and I know it's gonna come up as another question somewhere else, there is a jeopardy if you try and squeeze a large development in under an environmental assessment.
You don't get to credit that time against the process. You go back to the start of the process. The risk of trying to go down an environmental assessment. You would only do it if you were 100% confident that you were going to be able to live within that. That's the current state of work is to determine definitively whether we do or don't require an environmental impact statement. If we don't, then, of course, we'll go with the shorter process. If we do, we'll go with the EIS process, which in the best case is two years, in the worst case, three years, from now. Just to be clear, it would be unprecedented not to be granted the approval.
You know, the only instances where sensible proposals haven't been granted has been where they're in sensitive areas, particularly the NPRA, and where they interfere with settlements and where they interfere with endangered species. We're too far south for polar bears. Certainly no orcas coming up the rivers. They're too shallow. We are taking the path that guarantees the lowest risk, most secure path to development. Has the company been approached about selling an oil royalty on either or both fields or a natural gas royalty? It's the same answer to any questions on specifics. We're not gonna comment on specific transactions or provide a running commentary on it.
As I mentioned, there are a number of different transactions that we're in the process. We've got options to choose from, and we will make sure that we work with you know we end up with the one that's best for the company and for investors. Could the State of Alaska act as a guarantor and thus reduce the project's cost of financing? I think I've already sort of effectively dealt with that. The state can play a role in relation to the development, and we've built into the GSPA opportunities for the state to reduce the cost of accessing financing in return for a reduction in the gas price.
That includes a variety of different levers that they're in a position to pull. Next question was, I understand we need an EIS to develop our plot. Could this instead be done under the existing EA, while the EIS is in process? Well, firstly, there's no EA in existence. Even if we could go down an EA route, we would run the risk because of the scale of the development in total. Either we could risk not being able to expand beyond the permission granted by the EA, or we could end up having to go back to the start of the process. We're going to manage that risk to the best interest of the company.
We now see the significance of AGDC for post FID financing. What's the plan for Megrez and other expenses up until FID? We've basically covered that. We've got a clear scope and a strategy with that that we're now executing. When we have specific transactions to announce, then we will. It's not that there's gonna be one sweeping answer to the whole question. It's going to be a variety of pieces that in sum allow us to make sure that we're capitalized appropriately for the job at hand. Jay, will there be any sustained crude sales or compressed natural gas to help provide funding for development?
Well, in the near term, there will not be any significant. However, when we do drill Megrez or follow-up well at Talitha -B, we will be producing some level of crude, and we will sell those. It will not provide any significant funding. If we break even on those, given the rent that we have to pay to get into the Trans-Alaska Pipeline, I'll be very pleased.
Yeah. Thanks. I'm not even gonna pose the question. I'm just gonna say that I hope you won't hate me for saying whoever asked me. I was never a real Double Diamond Ale drinker, to start with, and so not being able to import it into the U.S., has not changed my life dramatically. Jay, do you still think that Pantheon's discoveries will be the largest on U.S. soil in the last few decades?
I still do believe that. If you think about, I know those of you who have watched our webinars know I would usually open by saying, you know, I joined ARCO in 1969 because of Prudhoe Bay, and DeGolyer and MacNaughton originally said there's 10 billion barrels of oil in place, and the recovery is gonna be 3 billion. Now you know, the recovery is gonna be bigger than the original oil in place.
Yeah.
Alkaid, Netherland Sewell has given us 1.2 billion barrels.
Yeah.
SLB said there was 1.7. We believe that there was over 2. How big is it gonna be with the addition of the yet to be drilled up-dip portion of that? We go over to the east and the eastern Topsets. This is gonna be a huge oil field. It is going to be a huge. Well, there are two giant oil fields, but together, I clearly believe that it'll be easily largest, depending on how you define West Texas. But it's significant.
That's the 60.
About 100 years ago, so I think I'm safe.
Yeah. No, exactly. I define West Texas as the western portion of Texas, so that's easy. Why is the share price seeming to perform so poorly with lots of good news coming out? Suggestions on the back of a postcard, please, to us if you know. Our job is really just to focus on doing the right things in the right order at an industrial level. In due course, you know, the share price will reflect the success or otherwise of those activities. When will we list on a major U.S. market platform? The answer already we've given. The target is focused on the middle of next year. Is there a likelihood of a joint venture with 88 Energy?
There are no plans for that. Does Great Bear Petroleum have an independent expert report for their oil shale or shale oil potential? I'm not aware of anything that's current. There may have been. I'm sure at some point Great Bear did some work on that, but it's not. There's nothing that we're particularly focused on, and I'm not aware of any specific report. Are there any hydrocarbon accumulations within Pantheon's acreage not being reported or included in the IERs that could become commercially viable if the gas line's built? Jay, do you wanna just...
Well, yeah. Regardless of whether the gas line is built, we have the Kuparuk and the Slope Fan. The Slope Fan we tested light oil in it. The Kuparuk we had some oil shows, but that was a failed test. We were trying to do open hole. Those are two that could be potentially very significant additions to our portfolio.
They'll be, you know, appraised whether they want to be by the development so. Justin, can you talk a little bit about process and timeframe of activity towards a U.S. listing? We've mentioned some of it, but do you wanna just provide a little extra color?
Yeah. Look, I mean, briefly, it's a lot more complex than doing a listing here in London, particularly with all the Sarbanes-Oxley requirements. There's just a long list of procedures we've got to go through. Everything from top to bottom of the organization, we need to restate our financials into GAAP. We need to get this year and previous years' financial statements audited under the U.S. standards. We need to implement a whole bunch of protocols from top to bottom within the organization. We've got Sarbanes-Oxley advisors. There's a bunch of legal restructuring and tax restructuring to do. We're working through that process. We'll make our submissions early next year, hopefully, and aim for the middle of next year for listing.
It's just a long list of procedural steps we've got to work through.
Yeah. We're well underway with that.
We are indeed.
Yeah. Question says the FID for Aphun was moved to 2028. Why did it move, and where will the funding come prior to FID? Firstly, it hasn't been moved to 2028. Production is 2028. We were talking originally about production in 2026. An FID, as I say, is typically a two to three-year process. And if we think about you know how complex is our development compared to some others? Well, it starts out by you know we've been gathering air quality data for more than a year now. We've got a small footprint when compared to the two major developments that have recently been permitted.
Not least, you know, we've had the good luck that instead of having to build an airport and logistics laydown and all that sort of thing as they have, someone built Deadhorse and an airport and a road already that runs to our assets. We're piggybacking off an enormous legacy of existing infrastructure. In terms of the air quality component, you know, we're anticipating going to a zero emissions development around 2030. Again, as we've said consistently throughout. In terms of the downstream emissions profile, it's ANS crude, so we already know what the footprint of that is in terms of what it displaces within the U.S. refining slate, particularly West Coast refining.
The problem within the regulatory process is it's not about knowing the answer in advance. It's about actually going through the process and doing it in a rigorous way. That's what we've got the right engineering and environmental consultants on working with Pat to deliver that. We're anticipating no process hiccups on that. What is the process and how soon can Pantheon access State of Alaska funding? Well, look, I think there are a lot of people who'd like to see the State of Alaska as a direct stakeholder in the project. The Permanent Fund obviously is not investing significantly, or particularly not in oil projects, but not particularly investing in Alaska risk projects.
AIDEA, the state entity, I think does provide industrial support. We've contracted through the GSPA with AGDC. We anticipate that with the state fully engaged with us through that state corporation, we'll have a shared interest in moving forward to secure the lowest cost, most secure financing for the development. The first step of that is you know, when we conclude, subject to all the risks associated with it, but when we conclude a take or pay agreement on the gas, that will allow us access to substantial funding. Do we have any evidence to support our confidence that AGDC will get its funding and move forward?
Yes, there's a lot of stuff that gives us confidence, and some of it AGDC has released, which has been in its testimony to the legislature. They've had independent experts assessing their project and its commerciality. They've got Goldman Sachs are working on the funding of it. And on the basis of what we've seen, you know, there's progress towards securing the backstop for the initial $50 million that Enbridge will be spending on the FEED confirmation. In terms of the actual pipeline, you've got the 65% federal loan guarantees under the IRA. You've got then the take-or-pay contracts of the shippers in the pipeline that will support a mezzanine layer and ultimately an equity proportion.
This will be an attractive infrastructure development. Almost ironically, breaking the pipeline out of the overall larger development makes it much easier to envisage the larger development because you're not trying to get $45 billion from multiple stakeholders all to the start line at the same time. You're simply trying to get a much more constrained set of stakeholders, most of whom are within the state of Alaska's control, or in their orbit to come together. We are confident, but we also expect, as we showed in the value staircase, that getting the FEED funded will reduce perceived risk amongst our shareholders.
Similarly, getting the FID on the phase one project will substantially reduce the risk in the eyes of our shareholders, and we see those as being as much a catalyst for improved value recognition as any of the things that we're doing. Can we comment on the scope, location, likelihood of a farm-in deal for the next drill? As I said earlier, we're not gonna provide a running commentary on every conversation we have. We will announce when we have a deal. We will announce when something that we thought was gonna happen doesn't happen. We've told you a year ago that we would share good news and bad news as soon as we had it and treat them both the same. We'll continue to live by that.
How many wells will Pantheon require to fulfill the AGDC contract? If you do the math, we think it's about 5,000 cu ft of gas per barrel of separated liquids. That is, on the basis that separated liquids are about half of the well stream of ANS crude per well. You can guess that to meet the initial requirements will require about 60,000 barrels a day of total production. On the basis of the type curves that we've had and assessed and independently validated, that's a level we expect to hit by the time of first deliveries in 2029 or 2030. We don't anticipate a problem on that.
In terms of numbers of wells, it slightly depends on when gas delivery becomes a requirement, because we will have been reinjecting gas from the start of first production, so we'll have a gas bank to feed in. Then in terms of the decline rates of wells, new wells are being added, but you're not getting the initial rate of every well a year later. It really depends on timing. When is the latest that Megrez can be drilled as a summer well? Can it be drilled as a winter well? Jay, do you wanna just talk a little bit about operational planning?
Well, we're very fortunate on Megrez 'cause, as most people know, we're gonna drill that from the west side of the Dalton Highway to the east. We had the option of doing it on ice or on gravel. It looks like we're gonna do it on gravel now, which really gives us the ability to drill it as a late fall well, a winter well, or a spring well next year. What we'll do is we will trade off when we drill it versus the cost of a drilling rig. Obviously, drilling rigs are more expensive to operate in the winter. We're in the process of doing that right now. Fortunately, as David said, we're lucky to be along the Dalton Highway.
It gives us a lot of optionality that others do not have.
Okay. Thanks, Jay. Given that it was promised to have funding in place by the end of Q2 2024, what's the delay? I think I've addressed that we expect to conclude the funding required over the course of the period up to FID in a timeframe that's consistent with the need. You know, we're not gonna put $100 million on the balance sheet today and then spend it over three years. That's just not you know, it's not a sensible use of capital. Let me put to bed the idea that there's one magic reveal of all of the funding so that we never need to raise funds ever again.
What we've said is, we would lay out a strategy for having the least dilutive possible funding, potentially to a point where the amount of non-equity funding would be larger than the total amount of funding required. That doesn't mean that there won't be requirements for equity at some point. We want to make sure that it's on a basis where it's at our discretion to the greatest extent possible. Over the course of the next several months, we'll be announcing transactions as they close that chip away at that total number. Having brought the total number down to a manageable level, it's opened up all sorts of options for us that we didn't have a year ago.
That's the direction of travel. The Alkaid -2 well had a 500 barrels per day total liquids rate. The SLB type curves look very different. Jay, can you talk a little bit about what we think the type curve for an Alkaid development well might look like and for a Topsets development well, why the difference and why it is that we're intending to kick off in the Topsets as high deliverability wells?
Yeah, the Alkaid two was a 5,000-foot lateral. The frack we put on it was a slick water frack, but it wasn't a limited entry frack. We learned subsequently, and with the work that Tony has done, that we over-perforated it. We also used coarser grain sand than we used in our recompletion. That 500 barrel a day well we believe will go to a 1,500 barrel a day well when we drill a 10,000-foot lateral, possibly even a little more than that. Complete it with the much improved frack, those wells will be 1.5-1.7 million barrel EUR wells.
Our Topsets wells and our Kodiak wells are in the, let's say, 3.5-4 million-barrel EUR wells with IPs 2,000 or 2,000+ barrels a day. The eastern Topsets, we believe, will be much better wells than that simply because they're shallower. They had a lower depth of burial and we've seen what the Topsets have yielded in other areas around our acreage. We have a wide range. All of them, as David has said, are economic from 1.5-4.5 or greater million-barrel EUR wells with well over 1,500 barrels a day IPs.
Thanks. How big a challenge is building the supply chain needed to develop the assets considering the lack of oilfield service support to support widespread fracking in Alaska? The first thing, Jay, before I hand it over to you, is there's an awful lot of fracking goes on in Alaska. There's pumping units up there that are fully employed. Part of the reason that we needed on the original Alkaid two job to source frack equipment from all over the world was because the existing frack equipment was deployed. Jay, over to you.
Yes, it will be a challenge to get hopefully additional service providers and high pressure pumping equipment to the North Slope. Fortunately, we have time to do that. There are two main providers now. It'd be nice to get a third provider. We're working diligently to talk to providers both that are currently there and who are not there about adding additional horsepower on the North Slope. As we've said, we'd like to go emissions free, and that would mean potentially having an electric pumping fleet, a high pressure pumping fleet on the North Slope. We're doing all of those things in advance.
It's a huge job, but we know what's required, and we're doing that in advance, and we'll build on the little steps as we've all said, to get to that point. I know that it's easy to say it, but we're actually doing the work right now.
That's all part of putting together the plan that with appropriate lead time you can get there. The toughest piece long-term is going to be constraining costs and protecting ourselves from predation, because one of the places that people in Alaska most readily recruit from is other Alaskan companies. We you know need to be smart about how we retain and incentivize the team that and the groups that we build to stay with the project. What is the likely percentage that the gas pipe gets built? Are your eggs in one basket? I think we've sort of addressed that, but it's not a zero risk today.
As we go through those steps, going forward, the risk will reduce. What gives us great confidence is knowing that LNG imports are substantially more expensive than building the pipeline and using our gas. We know that the subsidy implied in the gas price we're offering compared to what had previously been proposed over the life of the project is between $3 billion and $6 billion to Alaska. We know that Alaska is going to have a vested interest in trying to secure that benefit for consumers and residents of Alaska.
David, may I just add something?
Yeah.
Our original plan did not envision a gas pipeline, so that is our original plan, that we would reinject all of the gas. All our eggs are not in that basket.
No, I see. Although it's right now it looms large in the overall financing package. If it didn't go ahead, there are still options for offtaker financing through the oil route and other stuff. It's, you know, there's no doubt at all it has a very positive impact on this project if it goes forward. Do we think that the Ahpun East extension will be conventional? If Bob Rosenthal were on this call, he'd be jumping around saying, "You know, it's absolutely guaranteed," and he'd say you know about three more times as well. The key point here is, when we use the term conventional, what we're talking about is completed in a way that is not an unconventional completion.
Because the strict definition of conventional would really be coming from a source rock or not from a regular porous reservoir. Of course, the Permian Basin now is treated as part of the unconventional because the approach to developing and producing it is the same as the Bakken Shale or the Haynesville Shale or the Barnett Shale or the Eagle Ford Shale. If I rephrase the question, do we think that it's going to have porosities and permeabilities that allow us to use deviated wells with longitudinal fracs, you know, two or three stages, rather than lateral wells with 50 stages? The answer is yes. What do we expect from the Ahpun East extension?
We expect oil and lots of it, but until we drill it, you can't guarantee. Will Pantheon become a U.S.-domiciled public company as part of a U.S. listing? Highly likely so, but just so you're clear, it may not matter whether we change the top company to be a U.S. company or not. If more than 50% of the shareholders are U.S.-based, then it's already become a U.S.-domiciled company. If the mind and management and location of operations are all in the U.S., then it's a U.S. domiciled company, regardless of, in terms of how it's treated. The answer is we're all almost certain to go with a U.S. issuer on a U.S. exchange, as part of the U.S. listing process.
It's not quite as simple as it being solely within our gift to decide that. The EWAs for the Cawley and Gillespie report appears lower than the company estimates. Jay, can you discuss the main drivers of that difference?
Well, yes. One is an independent expert puts out a report that banks will rely on for reserve-backed lending. It's naturally going to be more conservative just as a result of that. They did an extraordinary amount of work. We're happy with it. And you know, they just used some parameters that were a little bit less than our parameters both in
Jay, it's also for a different scope, as well, in the sense that our numbers were based on the full wine-racking. Do you wanna-
Well, yeah, we did. Yeah. It was the full wine-racking, which would add over 80 million barrels as opposed to the Cawley Gillespie of 280 +. In the original, we had 404 million barrels. With the wine-racking and the Cawley Gillespie numbers, it's around 364 or thereabout. We're not very far off when you include the wine-racking, but it's only marginally less.
For the benefit of those to whom the term wine-racking isn't immediately familiar, infill wells at different levels, so offset like a wine rack. There's some fairly sophisticated modeling of the parent-child interference between the base wells and the infill wells. That was gonna be a lengthy procedure, and we just said, "Yep.
That's exactly the work that SLB is now doing with their huge model.
Yeah.
SLB is gonna give us a model that'll show exactly what that interference is to optimize that development.
I think there's a question about how we see the future of the oil industry in Alaska. The answer is a lot of investment going into a lot of resource, and Alaska is gonna be, you know, a happening place, for the next decade or so, for sure. From a modeling standpoint, peak production for Ahpun. The development of Ahpun will be integrated with initially the highest return wells, and then obviously you work down your portfolio of wells towards the economic cutoff. I wouldn't differentiate between the Ahpun topsets and the Alkaid Zone within Ahpun as just a small subzone.
We anticipate that total production for Ahpun, just the western portion on its own, would top out at around 100,000 barrels a day. If we have Ahpun East successfully appraised, then we'll grow from there. In terms of the profile beyond that initial rise to 100,000 barrels a day, whether it's coming from Ahpun East wells or it's coming from Kodiak wells, we see an overall development growing to as much as 300,000 barrels a day maximum rate, which could be retained for a very long time when you've got a resource of the size that we're talking about. In terms of guidance on specifics, as we get nearer to FID, we'll be updating guidance on that.
Right. There's a question about the difference between market expectations and whatever else. I think we've covered that. Just a point about one of the questions. The U.S. IPO or the U.S. listing is one step along the way. It's not the only source of potential capital support for the project. I think there's a number of questions that are conflating a financing strategy with executed deals. The strategy that we've laid out is predominantly relying upon reserve-backed lending for post-FID resources and a combination of industry transactions, structured finance and equity and debt to cover the pre-FID.
That's the strategy that we're now executing, and we will announce specific transactions as they become announceable because AIM has a continuous disclosure rule. Any hint of an ASX listing for Pantheon? No. Being confident of the contingent resources, is getting a loan an option to resolve short-term financing? Oh, yes, sorry. There are providers of debt who would lend against the overall package, but it may not be the most attractive option. We're running multiple different tracks in parallel to create the competitive tension and to make sure that we're in a position to choose the best option for the company.
In terms of FID, how much do you expect to raise in a U.S. listing, and when do you expect to have that? We can't talk about a prospective fundraise until such time as we're doing a fundraise. That's not one that I can address specifically. Would the sale to AGDC negatively impact oil recoveries? As I recall, gas injection allows maintaining reservoir pressure. The answer is that we will have plenty of gas to reinject, over and above what we'd be selling to AGDC. That actually in the Talitha reservoir, the wells aren't communicating with each other in any case, to any great extent.
The pressure support you get from the gas is actually expansion in the reservoir rather than from reinjecting gas. We don't think that reinjecting gas is going to make a great deal of difference to recovery. But that's obviously there's a point at which in the best quality reservoirs you'll want to reinject gas to replace pore space because you have in just the same way as you'll want to do water flood in the best quality reservoirs. There's not a single answer for the whole thing.
Yeah. We've only assumed primary recovery, so obviously when we start looking at secondary and/or tertiary recovery then that would come into play. Right now it's all primary recovery.
Yeah. There's no part of what's being proposed that would reduce the numbers for primary recovery from what we've currently described. What is the plan if AGDC doesn't get its FID? I see. Would we scale back the Ahpun development? No, the Ahpun development is based on the resources in it. The current development is assuming that we never sell to AGDC. The scale of the development is based on the resources that have been discovered, and the fact that we've got substantially more than just the 75 million barrels that we could point to as developable resources over a year ago. To a point now where we've got appraisal and independent reports on a nearly 400 million barrel development. The
Why haven't we got a plan to retire the convertible bond given the destructive impact of its terms on the company's share price? I think we talked in the last webinar. Justin talked, I think, quite passionately about the terms of the convertible bond. I think one of the things that's changed, if you notice, in the last year, we've had much less price weakness running into the convertible bond amortizations. That's partly 'cause we introduced jeopardy by placing shares into the hands of long-term holders to give us the option to pay in cash. We will continue to do what's in the best interests of shareholders.
If we could replace the convertible bond with financing that was less dilutive to shareholders as part of the funding pre-FID, then of course we would. Because our goal is to do whatever's in the best interest of shareholders. In terms of, is it part of our base case? Is it part of our base strategy for pre-FID funding? Our base strategy is that we're not retiring that bond. As I said, our strategy is to simply fill the incremental need, the residual need that's left there. Can we provide indicative timelines? Again, we're not gonna give specific timelines for specific steps along the way.
You can rest assured that the length of time it takes and the complexity of dealing with $60 million-$85 million over a two-year timeframe is a different order of magnitude than trying to assemble $350 million when we were a GBP 100 million company, compared to $60 million-$80 million when we're a $300 million company. Why were vendor financing talks mothballed? I mentioned earlier that we chose to proceed with the option that provides the best possible outcome for shareholders. When it became clear that offtaker financing would provide a less value dilutive approach than vendor financing, there's no point in proceeding with vendor financing if we've secured the other.
If we need to, at some point, go back to other long-term financing discussions, of course, we would do so, but for the time being, we don't see. Development wells. We've previously said we think the long-term cost of development wells is around $15 million. We showed the waterfall chart coming down to that. We think the first few wells will be more expensive because there's always a learning curve and shakeout of starting up a new operation. Whether they'll be horizontal or vertical, they'll be horizontal, in most of the accumulation.
In the better parts that we anticipate in the eastern Topsets and updip in Kodiak, they'll likely be highly deviated wells to expose a large section of the reservoir and then frack longitudinally. The fracks will be along the wellbore rather than orthogonal to the wellbore in those places. Those will probably be cheaper wells than the $15 million that we're talking about, not least because they use much less sand. I said I'd post a photograph of worn out shoe leather. I have a confession to make. I lied about leather. The soles of the shoes I use for comfort are actually polyurethane, and I totally forgot to take a picture of the soles that disintegrated and I sent to be repaired. They said they were so badly disintegrated they couldn't repair.
I will not be so forgetful next time. I will photograph the next pair of shoes that I destroy. What I can tell you is, yes, we have gone to see an awful lot of investors, potential investors, institutions amongst others. We will continue to do so, because success in the long run is a numbers game here. Interim funding, would it cover a Megrez as well? Yes, we've been specific. The GBP 60 million includes a Megrez as well. The 85 is if we have to add a Talitha B well. When is Alaska Gas FEED likely to start? The answer is, for sure, it's going to start within the next six months.
Because if you recall, the AGDC management asked the legislature to fund them to a point where if they couldn't get a FEED started by the end of the year, they would propose winding up AGDC. When will you hear from us next? At a minimum, we intend to update you on a quarterly basis. If there's anything substantial in the meantime, then you know that we'll provide a webinar to discuss and provide an opportunity for questions. Will we keep the AIM listing after the U.S. IPO? We've answered that already. Can we elaborate on negotiation of potential helium project? Yes. I think I did talk about it a little bit during the presentation, but just to reiterate.
Until there is a viable gas offtake that brings the gas containing helium down to a coastal location, where there is general gas processing to strip out the methane, the helium has no value. In the event that there is an LNG project, the value of the helium, if there were 50 Bcf of helium, at $600-$800 per thousand cu ft, that's $30 billion-$40 billion worth of revenue. You can imagine that feeding that into an LNG project is a very attractive addition to that project. That's the reason that we secured the rights to the helium in the gas processing agreement, secured the right to have the helium transported down to the coastal location.
The negotiation is now with the state on the terms on which helium would be developed and whether to incorporate it into an LNG project, whether it's a standalone project, whether it's a joint venture, including the state and us and someone else, et cetera, et cetera. I can't get more specific right now because those negotiations are only just starting. If we can create an asset from the helium that we can deploy to avoid equity dilution by joint venturing that asset, then that in just the same way as we did with the natural gas. That would be, you know, a sensible move for investors. Can I comment on Mangrove's position? As far as I'm aware, unless something's changed, it's unchanged.
The zone of interest production. The reservoir turned out to be tight because of its depth. Alkaid Deep. Right, I see there. We originally talked about Alkaid and Alkaid Deep as being two separate things, partly because we hadn't drilled down into the deeper portion. We have drilled down into the deeper portion. What we see is that Alkaid Deep and Alkaid just look like part of the same system. Jay, correct me if I'm wrong.
No, that's correct, David. They look like identical in terms of porosity and permeability.
Yeah. They are poorer quality than the Topsets because they've had a larger Dmax, and that's, you know, not a surprise. I'm absolutely sure that when we get to drilling zone of interest, Alkaid zone development wells, that's the point at which we'll optimize to maximize the recovery from the entire Alkaid zone, whether it's called zone of interest or Alkaid Deep or whatever. We've called it the Alkaid zone because it's that sort of slump block that is separately the 75-125 million barrels. Have you estimated the total dilution once floated in the U.S. market after raising any other capital?
We have an estimate, but I'm not sure that we are in a position for legal and regulatory reasons to share a forecast of that nature. It's certainly substantially less than it would have been if we had achieved 100% of the funding requirement using equity alone a year ago. That's what we told you we were gonna work on, was bringing non-equity and non-dilutive sources of financing to maximize the retained value to our existing shareholders. 'Cause I'm one and there are others as well. Does the GBP 85 million include convertible bond repayments? No. The GBP 85 million is new capital required beyond what we've already got available to us. Is there a plan to increase the institutional share base? The answer is absolutely.
We are talking to people and trying to determine what is the configuration that maximizes the attractiveness to long-term institutional shareholders. Of course, one of the things that's just happened in the last 24 hours is that the Tamboran IPO on the NYSE went ahead. That's a company which in some small regard resembles ours in that it's a pre-production asset that relies upon substantial infrastructure to get it to market in the event. In Australia. Northern Territory, Justin, is that right?
Northwest and Western Australia and the Northern Territory. Correct.
It's clear that there are investors for that kind of thing on the NYSE. A lot of the things that will make us more attractive to institutions are having a properly laid out plan for getting to revenue and having the right governance, having the right independent oversight, having the right systems, et cetera. We're doing that. There's a question about whether a JV with a big player would give us more credibility. The answer is undoubtedly that it would give more credibility to have a large player in there, but on what terms? Would it give the shareholders more reward?
I'm quite prepared to have people write nasty things about me in the X verse or the Twitter verse or whatever, if it's the cost of doing the right thing for shareholders and delivering the highest possible value. You know, I'm currently in a position you know where I think we are making substantial progress, and that I think we're making progress that'll deliver value in excess of what we would be able to retain if we simply sold out cheap. There's a question about a SPAC. The answer is, it's irrelevant to us whether you know the exact structure.
What I would say is that there are many complexities associated with SPACs specifically, that would probably make it a harder sell in terms of the degree of dilution than a direct listing along the way. With that, I think, Mark, we're done on the questions. We've answered all of them. So we've made you a liar about saying there are too many people to answer all the questions. I'll let you say what you need to say at the end before some wrap up notes.
Thanks for that, David. Once again, thank you very much indeed for your time this afternoon. Ladies and gentlemen, if I could please ask you not to close the sessions, we'll now automatically redirect you for the opportunity to provide your feedback in order that the company can better understand your views and expectations. This may take a few moments to complete, but I'm sure it'll be greatly valued by the company. On behalf of the management team at Pantheon Resources plc, I'd like to thank you for attending today's presentation and good afternoon to you all.