Pantheon Resources Plc (PANR) Earnings Call Transcript & Summary

Good afternoon, ladies and gentlemen. Welcome to the Pantheon Resources plc Operational and Funding Strategy Update. [Operator Instructions] Given the significant attendance on today's call, the company will not be able to answer every question received in 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 will 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 going to be going through 3 things. We're going to be talking about the pathway to $5 barrel value recognition. We're going to 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. So 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. And if you're new to Pantheon, this map is a simple overview of what we do and where we do it. It shows 2 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 as just a satellite to an existing field. The second giant field Kodiak was discovered in 2020, but only properly encountered in the 2021 Theta West well. That field is expected on stream by the end of the decade. And 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 timetable such as Willow and Pikka-Horseshoe. But 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 because it's telling us something that we already know. But 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. And so today, we're going to 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 to $10 per barrel of ANS crude 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 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. But 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, Cawley, Gillespie and Lee Keeling & Associates is just shy of 1.6 billion barrels in the best case and just over 6 trillion cubic feet 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. And 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. And 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 to 40 years. And 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. And we've engaged with the Department of Natural Resources in Alaska and the Alaska Oil and Gas Conservation Commission as well. And one thing that's clear and for the benefit of the long-term relationship, we're not going to 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 fields. So 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. And the scale of that leads us to a path for -- 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 2 to 3 years for an environmental impact statement. And so we're talking about production in 2028 -- so yes -- sorry, FID, '27, production '28. In terms of sort of some of the less exciting things, but nonetheless very important, professionalization of the company. So 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 frac design, which the success of that has underpinned most of the work done by SLB and internally on expected well performance in the upper Ahpun Topsets. But we've also strengthened legal and financial oversight, appointing Pat Galvin now as General Counsel for the group, Josh McIntyre as Group Financial Controller. We brought Phil Patman on board, who has driven the IPO process forward significantly, including working with Josh and Justin on the restatement of accounts to U.S. GAAP, on the controls and documentation of processes to become Sarbanes Oxley compliant and 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 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 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 -- once we have a fully appraised -- Internet -- something has gone wrong with the Internet connection. Has it? Are we back?

We can still hear you, David.

Okay. I'm sorry. There was flashing across my screen that it was paused. So 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. But if we think about one of the consequences of trying to run the independent expert reports in parallel in order to shorten the time frame was that we've now had 3 different independent firms reviewing the geotechnical story, which is -- 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 and 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. And importantly, profit-to-investment ratio is above 2%. And that's a threshold for the point at which drilling new development wells becomes liquidity-enhancing, because each new well supports the debt capacity, at least as large as the cost of drilling it. Now, 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. And so those have provided a critical underpinning both in terms of, if you remember, one of the contingencies around moving from -- or 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 consent. And we have -- 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. And 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 0 marginal cost of supply gas with a short lead time because it doesn't require significant capital equipment to be built, changes the game for the Alaska gas project. It allows a Phase 1 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. And at a materially lower cost than the alternative of importing LNG or paying for substantially larger -- a substantially larger project, including gas treatment. So 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. And 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 will support a debt of at least $250 million. And 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 dispose -- to drill as many disposal wells. But 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 cubic feet of gas a day. That will still require gas reinjection. And 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 want to be shutting down the oil because of a downtime on the pipeline. But nonetheless, it's definitely a positive in the right direction. We said that we would provide an update. We gave you 2 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 erring towards the offtaker financing rather than vendor financing because we were on the cusp of agreeing the deal with the state of Alaska through AGDC. The -- 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 in 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. So the steps we've taken so far, as I say, we brought that prospective requirement for $350 million down to no more than $60 million to $85 million. And 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. And 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 on equity alternatives. Obviously, we've got the U.S. listing I mentioned. But 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. And I'd illustrate how has that shown itself in the past. We used to establish, 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. And 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 2 payments in equity, but the price didn't drift into the bank. So the price at which -- 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. And we will continue to do whatever it takes to avoid any greater dilution than is necessary. 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 that, again, looking forward, illustrative of what we've done in the past, a year ago, the -- or 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, it was a valueless resource. But today, and helium is a much more strategic product, discussions we had about vendor versus offtaker financing -- offtaker financing in the long run, we'll almost certainly also include oil offtake VPPs or the equivalent. But 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 prefunding 2, 3 years ahead of actual gas deliveries. And similarly, with helium, it's a strategic resource, where the ability to access what could be a substantial helium resource. 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 cubic feet, which implies somewhere in a mid-case range, around 50 billion cubic feet 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. So, as I said, playing the options to bring to conclusion, but filling a $60 million to $80 million -- $85 million residual funding requirement in the way that relies on equity leased and preserves the value for our existing shareholders to the greatest extent possible. If I move on to 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 $0.20 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 for 400 million barrels there. That's equivalent today to $2 per share. So you can see the potential as we begin to derisk or as we continue to derisk because I think we've done a lot of derisking 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. And 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've -- 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 and that will establish whether the topsets 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 Talitha B well, which would be to confirm gas deliverability. And 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. So those steps will take us through to FID on Ahpun, as say, it's a 2 to 3-year period so 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. And somewhere along the time -- somewhere along that -- moving up that value staircase, a lot of the value is the derisking to a point where the success of the development program becomes inevitable in the eyes of the market. And 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 crystalize that value if we continue to deliver in the way we have in the last 12 months. And 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 to $10 per barrel. With that, Mark, I'll turn it over to you for the Q&A.

[Operator Instructions] But just while David and the team review your questions submitted already, I'd just like to remind you that a recording this presentation, along with a copy of the slides and the published Q&A can be accessed via your InvestorMeetCompany dashboard. David, as you know, you received a significant number of questions ahead of today's presentation. You've also received a number throughout. So 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.

Yes. 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 Sewell actually did provide us with the range. And the Netherland 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. So Kodiak is a huge field. It's going to get better and better.

Yes. And 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…

David or Jay, perhaps somebody could explain the difference between 1C, 2C and 3C just for those that don't understand?

Yes, that's the 10%, 50% and 90% probability numbers.

Yes. and the C is the contingent resource. Once you remove the contingencies, which will include FID, then you'll be looking at P numbers rather than C numbers, so proof plus probable. So 2C is a mid-case conventional -- contingent resource. 2P number is a 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. And 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, is there a -- 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. But the total resource base, we have to consider, because there are 2 elements, I mean, at least 2, but 2 major elements to regulatory approval. One is the footprint, the surface footprint and the local air quality footprint, that sort of thing. And then there is -- the second part is an assessment of the downstream emissions impact. And 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 going to 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. And so the risk of trying to go down an environmental assessment until you would only do it if you were 100% confident that you were going to be able to live within that. And that's -- the current state of work is to determine definitively whether we do or don't require an environmental impact statement. And if we don't, then, of course, we'll go with the shorter process. If we do, then we'll go with the EIS process, which in the best case is 2 years, in the worst case 3 years from now. But just to be clear, it would be unprecedented not to be granted the approval. The only instances where sensible proposals haven't been granted has been where they're in sensitive areas, particularly the NPRA ANWR where they interfere with settlements and where they interfere with endangered species. And we're too far south for polar bears, certainly no orcas coming up the rivers, they're too shallow. So 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 going to comment on specific transactions or provide a running commentary on it. But the -- 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 -- 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, 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. And 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 Ahpun. Could this instead be done under the existing EA while the EIS is in process? Well, firstly, there's no EA in existence. But 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. So 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? Well, that's -- we basically covered that. We've got a clear scope and a strategy that we're now executing. And when we have specific transactions to announce, then we will. It's not that there's going to 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. But 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.

Thanks. I'm not even going to pose the question. I'm just going to 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. And if you think about -- I know those of you who have watched our webinars know, I would usually open by saying, I joined ARCO in '69 because of Prudhoe Bay and DeGolyer and MacNaughton originally said, there's 10 billion barrels of oil in place and the recovery is going to be 3 billion. And now the recovery is going to be bigger than the original oil in place. Kodiak, Netherland Sewell has given us 1.2 billion barrels. SLB said there was 1.7 billion. We believe that there was over 2 billion. How big is it going to be with the addition of the yet to be drilled updip portion of that. Then we go over to the East and the Eastern Topsets. This is going to be a huge oilfield. It is going to be a huge, huge -- well there are 2 giant oil fields. But together, I clearly believe that it will be easily largest, depending on how you define West Texas. But it's significant. [indiscernible] 100 years ago. So I think I'm safe.

Yes. No, exactly. And 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. And in due course, 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. 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 is built? Jay, do you want to just...

Well, yes, 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. But those 2 could be potentially very, very significant additions to our portfolio.

And they'll be appraised whether they want to be by the development. Justin, can you talk a little bit about process and time frame of activity towards a U.S. listing? We've mentioned some of it. But do you want to just provide a little extra color?

Yes, look -- I mean, briefly, there's a -- it's a lot more complex than doing a listing here in London, particularly with all the Sarbanes Oxley requirements. And 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 year's 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 advisers. There's a bunch of legal restructuring and tax restructuring to do. So 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. So it's just a long list of procedural steps we've got to work through.

Yes. But we're well underway with that.

We are indeed.

Question says the FID for Ahpun was moved to 2028. Why did it move and where will the funding come prior to FID? So firstly, it hasn't been moved to 2028. Production is 2028. We were talking originally about production in '26. The FID, as I say, is typically a 2-, 3-year process. And if we think about how complex is our development compared to some others. Well, it starts out by -- we've been gathering air quality data for more than a year now. We've got a small footprint when compared to the 2 major developments that have recently been permitted, not least -- we've had the good luck that instead of having to build an airport and logistics lay down and all that sort of thing as they have someone built Deadhorse and an airport and a road already that runs to our assets. So, we're piggybacking off of an enormous legacy of existing infrastructure. In terms of the air quality component, we're anticipating going to a 0 emissions development around 2030, again, as we've said consistently throughout. And 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, particularly West Coast refining. So, 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. And that's what we've got the right engineering and environmental consultants on working with Pat to deliver that. And 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 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 all projects, but not particularly investing in Alaska Risk projects. ADA, the state entity, I think, does provide industrial support. But we've contracted through the GSPA with AGDC. We anticipate that with the state fully engaged with us through that state corporation that we will be -- we'll have a shared interest in moving forward to secure the lowest cost, most secure financing for the development. And the first step of that is 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 projects and its commerciality. They've got, Goldman Sachs are working on the funding of it. And on the basis of what we've seen, there's progress towards securing the backstop for the initial $50 million that Enbridge will be spending on the FEED confirmation. But then in terms of the actual pipeline, you've got the 65% federal loan guarantees under the IRA. You've got then the central pay contracts of the shippers in the pipeline that will support a mezzanine layer and ultimately, an equity proportion. And this will be an attractive infrastructure development. And 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 to -- or in their orbit to come together. So, 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 1 project will substantially reduce the risk in the eyes of our shelves. 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 going to 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 going to 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 and 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 barrels per -- sorry, 5,000 cubic feet of gas per barrel of separator liquids. So 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. And 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. So, we don't anticipate a problem on that. But in terms of numbers of wells, it slightly depends on when gas delivery becomes a requirement because we would have been reinjecting gas from the start of first production. So, we'll have a gas bank to feed in. And 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. So, 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 want to just talk a little bit about operational front?

Well, we're very fortunate on Megrez because as most people know, we're going to drill that from the west side of the Dalton Highway going to the East. And we had the option of doing it on ice or on gravel. It looks like we're going to 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. And what we'll do is we will trade off when we drill it versus the cost of a drilling rig and obviously, drilling rigs are more expensive to operate in the winter. So, we're in the process of doing that right now. So 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. So, 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, that we expect to conclude the funding required over the course of the period up to FID in a time frame that's consistent with the need. We're not going to put $100 million on the balance sheet today and then spend it over 3 years. That's just not -- it's not a sensible use of capital. So, 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 said is we would lay out a strategy for having the least dilutive possible funding potentially to a point where it would be larger than -- the amount of non-equity funding would be larger than the total amount of funding required. But that doesn't mean that there won't be requirements for equity at some point. But we want to make sure that it's on a basis where it's at our discretion to the greatest extent possible. And so we will, over the course of the next several months, we'll be announcing transactions as they close that chip away at that total number. But 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 and 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. So 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 topset development well? Why the difference and why it is that we're intending to kick off in the topsets as high deliverability wells?

So yes, the Alkaid-2 was a 5,000-foot lateral. The frac we put on it was a slick water frac, but it wasn't a limited entry frac. We learned subsequently and with the work that Tony has done, we over-perforated it. We also used coarser-grain sand than we used in our recompletion. So 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 and complete it with the much improved frac. Those wells will be 1.5 million to 1.7 million barrel EUR wells. Our topset wells and our Kodiak wells are in the, let's say, 3.5 million to 4 million barrel EUR wells with IPs 2,000 or 2,000-plus 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. So, we have a wide range, all of them, as David has said, economic from 1.5 up to 4.5 or greater million barrel EUR wells with well over 1,500 barrel a day IPs.

Thanks. And 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? But 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-2 to source frac equipment from all over the world was because the existing frac equipment was deployed. But Jay, over to you, again.

So yes, it will be a challenge to get, hopefully, additional service providers and pumping high-pressure pumping equipment to the North Slope. Fortunately, we have time to do that. And there are 2 main providers now. It would 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. And as we've said, we'd like to go emissions free and that would mean potentially having an electric pumping fleet, high-pressure pumping fleet on the North Slope. And so 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, actually doing the work right now.

Yes. And so 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. And so we need to be smart about how we retain and incentivize the team 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 1 basket? I think we've sort of addressed that. But it's not a 0 risk today. But as we go through those steps going forward, the risk will reduce. But 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.

And David, I'll just add something.

Yes.

Our original plan was -- did not envision a gas pipeline. So that is our original plan that we would reinject all of the gas. So, all our eggs are not in that basket.

No, obviously. Although right now, it looms large in the overall financing package. But it's -- if it didn't go ahead, there are still options for offtake financing through the oil route and other stuff. But it's -- there's no doubt all it has a very positive impact on this project if it goes forward. Do we think that the Ahpun's extension will be conventional? If Bob Rosenthal were on this call, he'd be jumping around saying, it's absolutely guaranteed via and he'd say you know about 3 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 or 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. So, 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, 2 or 3 stages rather than lateral wells with 50 stages? The answer is yes. What do we expect from the Ahpun's extension? We expect oil and lots of it. But until we drill it you can't guarantee. Will Pantheon become a U.S. domiciled company as part of the 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, if the -- then it's already become a U.S. domiciled company. If the mine and management and location of operations are all in the U.S., then it's a U.S. domiciled company regardless of what the -- in terms of how it's treated. So, the answer is we're almost certain to go with a U.S. issuer on a U.S. exchange as part of the U.S. listing process. But there are -- it's not quite as simple as it being solely within our gift to decide that. The EURs for the Cawley and Gillespie report -- Cawley and Gillespie report appears lower than the company estimates. Jay, can you discuss the main drivers of that difference?

Yes. One is an independent expert puts out a report that banks will rely on for reserve back lending. So, 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 they just use some parameters that were a little bit less than our parameters, both in...

But 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 want to...

Yes. So, it was the full wine racking, which would add over 80 million barrels as opposed to the Cawley Gillespie of 280-plus. So, in the original, we had 404 million barrels with the wine racking and the Cawley Gillespie numbers, it's around 364 or thereabouts. So, we're not very far off when you include the wine racking, but it's only marginally less.

And 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. And there's some fairly sophisticated modeling of the parent-child interference between the base wells and the infill wells and that was going to be a lengthy procedure we just said. Yeah.

And that's exactly the work that SLB is now doing with their huge model. So, SLB is going to give us the model that will show exactly what that interference is to optimize that development.

Yes. Okay. So, I think there's a question about how do we see the future of the oil industry in Alaska. The answer is a lot of investment going into a lot of resource and that Alaska is going to be happening place for the next decade or so for sure. From a modeling standpoint, peak production for Ahpun. So, we are -- 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 cut off. So, I wouldn't differentiate between the Ahpun topsets and the Alkaid zone within Ahpun as just a small sub zone. We anticipate that total production for Ahpun just the Western portion on its own would top out around 100,000 barrels a day. If we have Ahpun East successfully appraised, then we'll grow from there. But 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. So in terms of guidance on specifics, as we get nearer to FID, we'll be updating guidance on that. There's question about the difference between market expectations and whatever else. I think we've covered that. But 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 from the project. So, I think there's a number of questions that are completing a financing strategy with executed deals. The strategy that we've laid out is predominantly relying upon reserve bank lending for post-FID resources and a combination of industry transaction, structured finance and equity and debt to cover the pre-FID. And we are 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 -- yes, sorry, is getting a loan an option to resolve short-term financing? There are providers of debt who would lend against the overall package, but it may not be the most attractive option. So, we are running multiple different tracks in parallel to create the competitive tension and to make sure that we are in a position to choose the best option for the company. In terms of FID, how do you expect to raise? How much do you expect to raise in the U.S. listing? And when do you expect to have that? We can't talk about prospective fund raise until such time as we're doing a fund raise. 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 the -- over and above what we'd be selling to AGDC. That actually in the tighter reservoir, the wells aren't communicating with each other in any case to any great extent. And so the pressures of what you get from the gas is actually the 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 poor space because you have in just the same way as you want to do water flood in the best quality reservoirs. So, there's not a single answer for the whole thing.

Yes. But we've only assumed primary recovery. So obviously, when we started looking at secondary and/or tertiary recovery, then that would come into play. But right now, it's all primary recovery.

Yes. There's no part of what's been 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? 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. So, 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 developed or resources over a year ago to a point now where we've got appraisal and independent reports on a nearly 400 million barrel development. So, why haven't we got a plan to retire the convertible bond given the disruptive impact of its terms on the company's share price? So, 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 amortization. That's partly because we introduced [ jeopardy ] by placing shares into the hands of long-term holders to give us the option to pay in cash. And we will continue to do what's in the best interest 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 is in the best interest of shareholders. But 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. And as I said, our strategy is to simply fill the incremental need, the residual need that's left there. Can we provide indicative time lines? Again, we're not going to give specific time lines for specific steps along the way, but we will -- you can rest assured that the length of time it takes and the complexity of dealing with $60 million to $85 million over a 2-year time frame is a different order of magnitude than trying to assemble $350 million when we were a GBP 100 million company compared to $60 million to $80 million when we're a $300 million company. Whey were vendor financing talks mothballed? I mentioned earlier, that we chose to proceed with the option that provides the best possible outcome for shareholders. And when it became clear the offtake of financing would provide a less value-dilutive approach than vendor financing. There's no point in proceeding with vendor financing if we 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. I said apparently that -- hang on, sorry, something has jumped. Sorry, development wells. So, 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 shake out of starting up a new operation. Whether they'll be horizontal or vertical, there'll be horizontal in most of the accumulation. In the better parts that we anticipate in the Eastern topsets and an up-dip in Kodiak, there'll likely be highly deviated wells to expose a large section of the reservoir and then frac longitudinally. So, the fracs will be along the wellbore rather than orthogonal to the wellbore in those places. And 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. And 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 and they said, we're so badly disintegrated they couldn't repair. But I will not be so forgetful next time. I will photograph 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, and we will continue to do so because success in the long run is a numbers game here. Interim funding, would it cover Megrez well? Yes, we've been specific. The $60 million includes Megrez as well. The $85 million is if we have to add Talitha-A well. When is Alkaid gas feed likely to start? The answer is, for sure, it's going to start within the next 6 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. But if there's anything substantial in the meantime, then 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 potential helium project? Yes. So, I think I did talk about it a little bit during the presentation, but just to reiterate. Until there is a valid 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. But in the event that there is an LNG project, the value of the helium, if there were 50 Bcf of helium at $600 to $800 per 1,000 cubic feet, that's $30 billion to $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 precedent agreement or [indiscernible]. 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 stand-alone project, whether it's a joint venture, including the state and us and someone else, et cetera, et cetera. So, I can't get more specific right now because those negotiations are only just starting. But 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 a sensible move for investors. Can I comment on Mangrove's position? As far as I'm aware, unless something has changed, it's unchanged. The zone of interest production of the reservoir turned out to be tight because of its debt. Alkaid Deep, all right, I see there. So, we originally talked about Alkaid and Alkaid Deep as being 2 separate things, partly because we haven'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. And they look like identical in terms of porosity and permeability.

Yes. But they are poorer quality than the topsets because they've had a larger Dmax and that's not a surprise. But I'm absolutely sure that when we get to drilling zone of interest, Alkaid 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 whatever. We've called it the Alkaid zone because it's that sort of slump block that is separately the 75 million to 125 million barrels. Have you estimated the total dilution once floated in the U.S. market and 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 our forecast of that nature. But 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. And that's what we told you we're going to work on was bringing non-equity and non-dilutive sources of financing to maximize the retained value to our existing shareholders because I'm one, and there are others as well. Does the $85 million include convertible bond repayment? No, the $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 preproduction asset that relies upon substantial infrastructure to get it to market in the event in Australia, Northern Territories, Justin, is that right?

Northwest and Western Australia and the Northern Territory, correct?

And so it's clear that there are investors for that kind of thing on the NYSE. But 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. So, 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 right now say things about me in the Xverse or the Twitterverse or whatever. If it's the cost of doing the right thing for shareholders and delivering the highest possible value, I'm currently in a position where I think we are making substantial progress. And then I think we're making progress that will 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 the exact structure. But what I would say is that there are many complexities associated with SPAC, 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. And I'll let you say what you need to say at the end before just some wrap-up.

Thanks for that, David. Once again, thank you very much for your time this afternoon. Ladies and gentlemen, if I could please ask you not to close the session. We're now automatically redirect you for the opportunity to provide your feedback in order the company can better understand your views and expectations. This only will take a few moment to complete, but I'm sure it will be greatly valued by the company. On behalf of the management team of Pantheon Resources Plc, I'd like to thank you for attending today's presentation and good afternoon to you all.