Central Petroleum Limited (CTP) Earnings Call Transcript & Summary

Okay. Let's begin. Good Friday morning, everyone. I'm Leon Devaney, CEO and Managing Director of Central Petroleum. I'm joined today by Damian Galvin, our CFO. Today's presentation will cover our financial results for the March 2024 quarter and provide an update on our other business activities. You'll see on your screen an opportunity to lodge questions online throughout the presentation today. We'll answer them at the end of the presentation. Let's get started by handing it over to Damian to discuss last quarter's results.

Thanks, Leon. Firstly, let's have a look at the results for the March quarter, which admittedly was one of our most difficult for some time. Volumes were significantly impacted by the suspension of the operation of the Northern Gas Pipeline, which went offline in mid-February. And so the March quarter volumes at just over 1 petajoule equivalent, were down 13% from the December quarter. And it's pretty clear on the chart at the bottom left of this slide that the last quarter was certainly our lowest for some time. Our aggregate revenues, however, as shown on the far right, were down just 1% at $8.2 million for the quarter. We were able to achieve higher prices across the portfolio, which almost offset the lower volumes. The middle chart illustrates the increase in the actual realized sales price up to almost $8 per gigajoule equivalent for the March quarter. So it was up 13% from the December quarter as some of those older lower-priced contracts rolled-off and they're replaced by new higher-priced contracts. We also had higher oil prices in the March quarter. So it wasn't a good quarter for us overall, but the outlook is good for a number of reasons. Firstly, the gas, which we were unable to sell to our East Coast customers for much of the March quarter, has from mid-April been supplied into the Northern Territory. And so we're currently selling everything we can produce from Mereenie and Palm Valley. Secondly, we're seeing higher contract pricing as we roll-off maturing legacy contracts over the next 12 months. And thirdly, the gas that we presold a number of years ago to fund development work was all fully delivered by the end of December. So we're now starting to see this additional cash flow come through from 1 January, although that wasn't obvious in the last quarter's numbers due to the pipeline closure. Just to close out on what the impact was from the closure of the Northern Gas Pipeline this year, this chart here is a pretty good illustration. And these are gross joint venture numbers. You can see that the earlier disruptions we had back in September, November. And then you can see this more prolonged outage, which started midway through February and continues through to this day. The impact, however, of the current outage only extended through until we were able to recontract that gas into the Northern Territory in late April, and you can see our supply jumping at that time. And since that time, we've been sending 100% of our production from Mereenie and Palm Valley into that new as available contract that we have with Power and Water Corporation, and that could see us supplying up to 8.6 petajoules of gas through the end of 2024. Now we estimate that due to the pipeline outages this financial year, our revenues are down probably about $4 million from our budget, which had anticipated the higher realized gas prices. But the worst appears to be behind us now and the future is looking pretty good. So we'll hear more from Leon shortly on that market outlook. The further good news is that our balance sheet is as strong as it's been for some time. And that gives us a lot of flexibility for growth opportunities and also the headroom to absorb some of those revenue impacts that we've seen in the last 6 to 12 months. At 31 March, we had $24 million worth of cash available, which is pretty much the same as our loan balance. So -- and net debt is effectively nil. We do need to still mitigate the NGP risk. However, on the basis, we can manage that, we've got $24 million of cash available that we can use towards the exploration and development drilling that we want to progress with our various joint ventures. The improving cash flow outlook, it's assisted not only by the higher gas prices, but also from our declining debt service. And we've done a lot of work in recent years in reducing our debt balances. So the chart at the bottom right shows the impact of the debt service that we had to absorb each year. Importantly, as I mentioned earlier, as of the end of last December, we had fully delivered all of the presold gas. And so that will boost our free cash flows going forward by more than $6 million a year starting from 1 January, as those gas volumes are freed up for delivery to new customers at significantly higher prices. The next major milestone will be the final delivery under our gas balancing agreement, under which we've been returning previously overlifted gas at the rate of 2 terajoules per day. We've got less than 2 years remaining before that gas is fully repaid. So by mid-2026 our free cash flows will be boosted by another $5 million a year at today's prices. Our bank facility still has over 12 months to run, but with the higher gas prices that we've been achieving and the prospect of locking in longer-term contracts through the expression of interest process that's currently underway, we'll be exploring the opportunity to extend and restructure the loan facility to provide longer-term certainty and flexibility to accelerate development drilling and also the timing for future shareholder distributions. You may also have seen that our largest partner, Mereenie, has this week completed the sale of its 50% interest to New Zealand Oil and Gas and Horizon Oil for up to $103 million. It's worth noting that the valuation multiples implied by that transaction are some 60% higher than the value that the stock market is currently placing on Central's equivalent 2P reserves, so an interesting benchmark. So while the March quarter wasn't our best, there's some very positive signs for the future. And with that, I'll hand you back to Leon.

Okay. Thanks, Damian. As you mentioned, the outage of the NGP had a visible impact on our sales in the last quarter. But we've done a good job so far mitigating that impact by remarketing our East Coast gas contracts into the NT, which got us back to full production in late April. So well done to the marketing team on that. We have been advised that the NGP could restart in July. However, I think the NGP will continue to be unavailable through the end of this year, at which point it may restart if the new Blacktip well has a strong result. This risk is something we are actively managing over the course of this year. But as I discussed later, we expect to mitigate this risk through our EOI process. Okay. Moving on to the NT gas market. I have been highlighting for some time the uncertainty in the NT gas market, particularly the price volatility over the next 12 months as market participants try to determine whether the NT's traditional sources of gas will be sufficient to meet demand. Those market conditions continue to exist with both near- and long-term market fundamentals in the NT highly uncertain. The bottom line is that the NT's traditional base gas supply could fall short of demand, leading to significantly higher prices in the near and longer term. Darwin LNG tail gas is currently running at about 15 TJs per day. That is the orange section in the chart on this slide. We don't have much visibility on how long that field will last, but we do expect that it could reach the end of its life sometime this year. Once that field closes, supply will be tighter in the NT until the new Blacktip well is drilled, which we understand will be around the end of this year. The last well at Blacktip didn't appear to perform as expected. So there really continues to be uncertainty about this well, providing sufficient supply for the NT next year and beyond. There are a couple of Beetaloo wells being drilled around the end of this year, which I understand will be the first tests of a development scale fracked well. We expect the results from this drilling activity both at Blacktip and Beetaloo to start becoming visible from Q1 next year, at which point the NT's longer-term gas markets may start to come into focus one way or another. Okay. You would have seen this slide previously. This slide illustrates the various NT gas market scenarios that we could experience. Under a high NT supply scenario, surplus NT gas can be exported to the East Coast. Until recently, these are the market conditions that have typically prevailed since the NGP opened in 2019. In a low-NT gas supply scenario, the gas from the new wells at Blacktip and the Beetaloo are not sufficient for the NT's demand. So the NT market would need to rely on alternative sources like diverting LNG from Darwin or reversing the NGP to import gas from the East Coast. These are both obviously expensive options in all likelihood. So that scenario will probably see a lot of pressure on gas prices. And obviously, that flows through to things like electricity prices and other costs of living in the Northern Territory. All right. Looking at our EOI process. Last month, we did announce an EOI or expression of interest, for the sale of up to 40 TJs per day of gas from the Mereenie gas field. This is a major supply opportunity for us. It could rewrite our cash flow forecast, accelerate our timing for distributions and crystallize a significant investment in drilling new wells and increasing our production capacity. So it's an important process for us. You'll see the ramping up of those volumes that is -- reflects our older contracts coming off over those years. One objective from our EOI is to mitigate the risk that our gas fields are turned down if the NGP goes off-line. That's obviously something that we experienced earlier this year. Another objective of the EOI is to lock in gas prices and revenues that provide the economic incentive and financial capacity for us to drill new wells with our priority being 2 wells at Mereenie, which could be drilled this year. We also want to drill 2 wells at Palm Valley, which will require about 12 months of lead time to get those underway. But the sooner we can start, the sooner we can get them online. And potentially, we'd like to also drill a couple of Stairway appraisal wells, which could unlock a significant volume of 2C resources at Mereenie. Obviously, this additional gas volume would be, I think, very welcome into a tight market, whether it's the Northern Territory or the East Coast, which has its own fundamentals that suggests that new gas supply is desperately needed. The EOI process is progressing well. I think we're in good shape to achieve these objectives. We have firm gas supply backed by existing proven reserves and a long track record of reliable delivery from Mereenie. So our guess should be of interest and appeal to customers that want certainty in price and supply. I've been asked about the impact of our EOI on the NT gas market. Clearly, securing the customer on the East Coast would increase the risk of shortfalls in the NT simply because it's NT gas that previously had been focused on Northern Territory customers with surplus going to the East Coast. If that volume is indeed exported out of the NT, it certainly will have potentially an impact on the NT gas market going forward. Having said that, it is incumbent on Central and its joint venture partners to ensure we secure the best available sales results for our gas. As I just mentioned, though, one of our objectives in the EOI process was to mitigate the risk of our fields being impacted by NGP outages. We can accomplish this in 2 ways. First, by selling our gas to NT customers that would obviously reduce our reliance on the NGP; or second, by selling our gas to East Coast customers to ensure that the NGP has a sufficient volume for continuous firm operation. In essence, by selling into the East Coast, we can control our own destiny and make sure that, that pathway to market remains open and is open on a firm, reliable basis. I think if the NT government shows the commitment to our proven fields in this EOI process that they've showed to new potential basins like the Beetaloo, there could be a path where our gas stays in the NT. Alternatively, if our gas is sold to East Coast customers, we'll be able to ensure that the NGP is open and available to transport our gas to a market. But that would obviously mean that an already highly uncertain NT gas market will become even more volatile and risky for its energy users. Moving on to sub-salt prospects. We've been working hard looking for a farm-out partner and closing a farm-out agreement for our sub-salt permits, particularly in the southern portion of our permits in a joint venture with Santos. And obviously, the focus there is to get the farm-out close so that we can get drilling and explore those exciting opportunities. There's been a lot of activity in the space. We have essentially now removed Peak from the JV, which obviously clears the deck for a new partner to come in. The EP125 permit, or Mount Kitty has received a 12-month permit extension from 6 June 2024. This allows us time to complete a farm-out and commence drilling. Once we have a new farm-out arrangement, we should see sub-salt drilling commence within 12 months. The EP125 JV has already begun addressing long lead items so that drilling can commence as quickly as possible on that completion. Our target at this time is to close a farm-out arrangement in the near term so that the JV can commence drilling at Mount Kitty in particular, potentially this year, but certainly as soon as possible. Mount Kitty is likely to be the first prospect given its maturity. We'd expect, obviously, because of its testing to date, has already indicated a world-class concentration of helium, and we've certainly seen interest from third parties on that prospect in particular as well as Dukas, drilling a well at Dukas and Mahler to then follow drilling at Mount Kitty. Fortunately, in terms of our efforts for finding a farm-out partner, helium and gas prices in Australia remained strong and certainly support these major investments in sub-salt activity at Mount Kitty and Dukas in particular. Both of those prospects are potential company makers for Central. We've also been working to find a farm-out partner for Zevon with the focus to get drilling done there as quickly as possible as well. That progress has been slower. We think Zevon is a very exciting prospect, but we haven't made a lot of progress in terms of finding a partner and advancing the opportunity to drill in the near term. Our focus has mostly been around the more mature sub-salt prospects at Mount Kitty and Dukas. I think, progress in finding a farm-out partner in Mount Kitty, Dukas in those more mature prospects will generate opportunities for a farm-out to complete at Zevon and ultimately get drilling underway at that permit. Okay. Let's take a look at helium recovery at Mereenie. We've made some really good progress on that project. The project is intended to strip out some of the existing helium that we have in our sales gas stream and sell it into the Australian helium market. The proposed project has expanded. It now includes a helium liquefaction unit alongside a helium membrane separator. Helium liquefaction is very specialized with helium liquefaction equipment concentrated within a few major global helium players. Liquified helium can be sold for premium spec applications, and therefore, it commands a much higher price compared to gaseous helium given its level of purity. To address the change in the project scope, our partner, Twin Bridges, has teamed up with a major helium supplier in the Australian market who is highly experienced in producing liquefied helium and marketing that product to the specific set of helium users that require a highly purified liquefied helium product. Given the size and added complexity of the current HRU project, the delivery model is now essentially a turnkey structure where Twin Bridges and their partner would build, own and operate the expanded HRU project, combined with an offtake for the liquefied helium product. The Mereenie JV would toll existing sales gas through the HRU plant with the sales gas, obviously, less the helium component, then sold by the Mereenie joint venture into the gas market. And we don't expect any reduction in gas volume or gas revenue as a result of the helium extraction. The delivery model, in particular, reduces the risk to the Mereenie JV and dramatically reduces the capital cost that we would need to contribute. FEED for the expanded HRU project is now underway. High-level commercial terms have been agreed and drafting for binding project agreements have begun. We're obviously working towards a FID. We're hoping it can happen over the next few months and certainly this year so that we can get into building the HRU project and get it online as soon as possible. The HRU project should be a critical strategic project in Australia, given there is now no domestic production of this critical gas. This is not a quick and easy project. The team we are working with are the best in the business and the expanded helium project not only appears strong on an economic basis, but it will be a win-win for project participants and Australia's helium consumers. Taking a look at some of the other activities. We previously announced an agreement with Arafura to supply gas to their rare earth project in the Northern Territory. That project appears to be tracking well. I understand they've recently received significant support from the government by way of a cornerstone debt facility, and the project has been identified by the government as a critical strategic project. We have not yet been advised that the project has completed their CPs under our gas supply agreement. So we'll obviously continue to keep the market updated on that as it progresses. From an NT market perspective, the Arafura project would increase the NT's gas demand by around 20%. That obviously would place some further pressure on the NT gas market over the longer term, impacting electricity generation as well as commercial and industrial users. I think that certainly supports our intent and interest in drilling additional wells because we think there's going to be a need for that, both in the NT and in the East Coast market more generally. Finally, let me wrap up by recognizing the great safety record we have been maintaining. Our TRIFR has been 0 for most of the past year, which is a testament to our operations team on site and here in Brisbane. I'd like to say well done to that team, and certainly encourage everyone to continue to have that focus on safety as we enter the second half of the year, particularly as activity starts to build along the lines of the projects I've talked about during this presentation. At this point, I think we can open the webinar up to questions.

[Audio Gap] for the business should be safe production, dividends, share buybacks. Why are we still talking about exploration spending? Shouldn't we focus on production?

Yes. Thank you for that question. I certainly agree, safety is obviously our priority. And as we've talked about, following the strategic review, maximizing cash flow has been a critical objective that we've been working towards. We do still want to preserve growth within the business. We think that's important. And we think there's certainly projects and activities that justify that investment. There's really 2 buckets to that. I think we've got a set of development wells and appraisal wells that are clearly aligned with our objective of maximizing cash flow. Those are at lower risk. We can generate additional production, increase our field capacity, increase our sales. And that obviously flows through to some of the market pricing that we'll see through this EOI process, which we think could be very attractive. So those investments, I think, are consistent with trying to accelerate dividends back to shareholders. When we do look at more of the exploration and appraisal activities and examples of that, obviously, are sub-salt drilling and potentially the Stairway appraisal, we do look at focusing on those activities where we think there's the opportunity to get some strong interest from third parties, try to utilize third-party investment to minimize our capital contribution and risk. We think those are growth activities that are, in particular, worth that additional investment and certainly something we want to progress, particularly in this climate. And if we do see the EOI process showing price signals that support that. So ultimately, it's really about a bit of a balance. What we have done, though, is focus our exploration on those that are more near term where we can use third-party money.

Okay. Question here, around the Northern Gas Pipeline. Is the Northern Gas Pipeline rather unreliable?

The pipeline itself, I think, is reliable. I think the aspect of the pipeline that is unusual for pipelines across the East Coast of Australia is simply the low flow issue. We typically don't see that. If that wasn't there, we wouldn't have the reliability issues we've seen over the past few years. I understand there's certainly -- quite a bit of work to address that issue. I don't think it's going to be something that's long term. I think the -- certainly the Northern Territory government. Gemini, who owns that pipeline, I think there's all -- there's quite an alignment between stakeholders in the gas market to resolve those issues so that we have a fully functioning and very reliable NGP. From our perspective, and this is one of the objectives of the EOI I spoke of, we would like to take those matters into our own hands and have the ability to control our destiny with regards to transport on the NGP. Hence, the EOI allows us to sort of minimum volume that we need to keep that pipeline open. If we sell to the East Coast, we'll be selling on the basis that, that NGP is a firm reliable pipeline because we've got the volume to put through it that it requires. So I think we've got a good strategy to deal with that risk, and it's certainly a focus for us this year.

Thanks, Leon. There's a couple of questions here around dividends and distributions. Can we start giving something back to shareholders as a small dividend, say, [ $0.005 ] per share? There's another question here around why do a buyback, $11 million could buy back 20% of the company. So I think -- I know Leon has touched on it already. I think certainly, it's a clear strategy from the one coming out of the strategic review was that we need to start bringing -- giving some value back and money back to shareholders as distributions or dividends. And I think the key building blocks for that are, one, increasing cash flows, and we're seeing that already, as we mentioned in the presentation, we're seeing higher gas prices quite significantly, and that's moving forward as well. And then also, we're starting to pay down some of that debt service. So the presale gas has gone, so that increases cash flow going forward. And within 2 years, we'll be finished with the [ overlift ] gas as well. So the increase in cash flow is a very important component. Certainty of gas cash flow is another one and the expression of interest process that we're running at the moment, hopefully, will end up with some long-term gas contracts that will give us a lot of certainty around cash flow going forward and certainly around the Northern Gas Pipeline dynamics, which have interrupted us recently. Restructuring the debt facility is another thing we're looking at. It's, again, trying to extend that further perhaps and sculpting the remaining debt payments so that there's more cash upfront for shareholders because up until now a lot of our cash has been prioritized towards paying down various forms of debt, but we're starting to come out from under that shadow. And then exploration, on the other hand, has to be funded to some extent. We're obviously funding that where we can from third parties, but we're very mindful of it. There's a big group of our shareholders who have a very keen desire to see some of these quite -- well, we think are quite valuable areas with helium and natural gas as well to see those investigated fully to walk away from them would be potentially quite detrimental to the overall value of the company. So that's the sort of tightrope we've got to walk. But I think the building blocks are all there, the desire from the Board is there. And I think sometime in the next year or 2, we'll be in a position to start giving a bit more guidance on when and how we can get money back to shareholders.

Yes. I'll just add a couple to that. Obviously, we do have a joint venture with Santos on EP125, Mount Kitty. There is a commitment to drill that well. We are very interested in ensuring that we participate in that drilling until we find a farm-out partner, and we've been able to reduce our cost exposure to that well. We do want to have some cash in buffer so that if we need to we can fund our share and keep pace in that. Certainly, that drilling activity, as I mentioned earlier, is progressing rapidly. So that is one of the things that we do want to ensure that we've got some capacity for. Again, our plan is to farm it out to reduce that exposure. The other is the NGP. The NGP still is at risk for the balance of this year. Damian talked about some of the financial impacts, having a buffer as we weather through that uncertainty for the balance of this year and until we can get essentially control over the firmness and availability of the NGP through our EOI process, if that's the path we go. We want to be able to manage and have a bit of buffer around that financial uncertainty. So there's quite a few reasons. But again, I think those are going to shape out over the course of this year and give us some good visibility once we get a debt refi as to what our forward cash flows are combined with the EOI process, which will hopefully lock in some attractive long-term gas supply agreements at fixed prices.

Okay. So another question here, Leon. You have talked about the risk of Northern Territory becoming short gas, which may lift prices higher. If this occurs, what are the risks of government or the regulator interference in capping prices?

That's an interesting topic to touch on. I think the lessons we've learned is that the -- that intervention, which obviously has happened on the East Coast and does translate into the Northern Territory, we've seen what that is. There's obviously a price cap associated with some of those price controls. There's quite a bit of pressure on the Queensland LNG producers to provide supply into the East Coast where it is short. So far, that focus has been on the Queensland LNG producers. I think, obviously, they were later to the market. The Darwin LNG, obviously, were there previously and actually had a good reserve base and probably didn't contribute to any of the shortfalls that we see on the East Coast to the extent that we saw coming out of the Queensland LNG proponents. There's exclusions under that price cap. And I think the step to actually regulate or look at domestic reservation, I think, is a step that I think will be under much more scrutiny going forward. When you look at the investment in exploration within the sector, it is underwhelming and certainly not what is needed to pull Australia's gas market out from a risk of being short and a risk of higher prices into something where we got a very functioning market for investing in exploration, investing in appraisal and bringing gas reserves through the maturity profile into production, which is really what this country needs to bring energy prices down and derisk gas, gas supply for customers across the East Coast.

Excellent. So another question. Has the amount owed by Peak Helium being recovered or written off? I think I can probably answer that one. We haven't been able to recover anything at this stage and probably won't. I think importantly, there wasn't a lot of exposure in the first place. Obviously, a lot of the work that was going to be funded by Peak was deferred until the farm-out had advanced and didn't get to that point. So the exposure is relatively small. But it has obviously delayed the program, but our chances of recovering that any monies is very low.

Yes. I'd add to that as well. A lot of the work that we had done with Peak under the farm-out during the duration that we understood it to still be on foot. As at Santos, is supportive and useful in terms of our efforts now to farm out again and get Mount Kitty drilled in particular. So it hasn't been a complete waste of time and money. We'll be able to benefit from that to the extent we're able to get a new partner in and resume drilling there.

Thanks, Leon. There's another question here. Can you update us on the Zevon 2D seismic survey, please? The 2023 annual report flagged this to be completed in 2023. There haven't been any updates.

Yes. So that program actually went really well. We looked at a much lower cost seismic methodology, essentially using drop weights, much lower environmental impact and a much lower cost for undertaking seismic in that part of the basin. The costs were significantly reduced. That's a great outcome. It certainly allows us to reapproach farm-out partners that are interested in Zevon with, I guess, a lower cost entry to come in and be able to explore, provide additional seismic and, I guess, leverage off any success we have with Zevon going forward. Those results are in. We're going through the interpretation process of it. We are looking at reinterpreting some of the older seismic in accordance with that. And that has obviously some impacts on drilling location, permit application or certainly approval applications. And we are going to be reproaching interested parties and trying to farm that out. I think really the catalyst for Zevon farm-out will be closing something in the southern part of the basin and getting Mount Kitty drilled, for example, I think that will be a real good catalyst and generate quite a bit of excitement for sub-salt in that northwestern part of the basin that we're interested in progressing as well.

Okay. A couple of questions, Leon, around the Northern Gas Pipeline. Does the Northern Territory government have any regulatory power to restrict or prevent gas exports via the NGP?

We're certainly interested in that. And one of the things that we want to ensure is that if we sell to the East Coast customers and we have a volume that's committed to the East Coast, that's sufficient to keep the NGP open. We want to make sure that a backhaul arrangement or importing East Coast gas into the NT doesn't impact that. We're comfortable with the regulations and the arrangements that we're seeing to date that, that will not be a risk for us. In most circumstances, certainly, if there's emergency scenarios, groups like the AER can step in, but those are actually quite rare and pretty draconian, and then there needs to be a real problem in the NT that can't be solved from a commercial perspective. So we're comfortable that once we sign and commit sufficient volumes to the NGP, that will be essentially firm service and not substantially different from any other firm transport service throughout the East Coast. So we're comfortable with that. For us, it's important, we're not going to be too excited to be selling gas where we think there's a potential of it being shut in. And vice versa, customers on the other side, given that they've seen the outages in the NGP, are very focused. They're buying this gas in support of very substantial capital projects, and they need that certainty of supply. And so this is an issue for the whole market, and we're comfortable where it's coming at this point.

Okay. Another one. Would 40 terajoules a day of NGP sales guarantee the operation of the NGP? What's the minimum required volume to get pipeline operator to keep the line open?

Yes. Thanks for that question. That's something we spent quite a bit of time on in our half yearly webinar. We put up a few charts showing that. From our perspective, our understanding, and this is all visible in the Gas Bulletin Board as well. The number that we see as being the threshold is 20 TJs a day of export gas into the East Coast. One of the reasons we've packaged up and maximized the volume that we're putting out under the COI, which is up to 40 TJs a day, is to ensure that we have the ability to sell gas to East Coast customers that exceeds that 20 TJs. When you look at the first few years, we don't have that number, but I would highlight that we already have about 14 TJs or 15 TJs a day in 2025 to East Coast customers that we've announced previously. Those are sitting there waiting and all they need is the NGP to be open. If we can allocate another [ 5 TJs ] to an East Coast customer, that gets us to that magic 20 TJs a day threshold, and the NGP should become a firm operational service for us.

Yes. Okay. A couple of questions around the EOI process that's underway. First one, regarding the EOI, can you just confirm that once confirmed, that first gas would be at the end of this year?

Yes. So we put gas out for uncontracted volumes for the balance of 2024. That's an unusual block. It is typical for large customers to be buying their gas 6, 9, 12 months in advance of when they need it. Partial year gas volumes might have some interest, and we've certainly put it out there. And the intent there is that if we can move away from the as-available arrangements we've got with PwC and find a customer to take it on a firm basis, we're happy to do that. That's out there. Our real firm gas sales and our expectation on a lot of traditional interest in term gas supply will start 1 Jan 2025, and continue for several years in accordance with the profile that we put up earlier. So that's really how we're approaching it. I think 2025 is certainly a lot of interest. At that point, you will have the Blacktip well drilled by the end of the year. We won't know the results of that. It would have to come in extremely strong to satisfy the NT market, particularly if the LNG volumes fall away. 2026, I think, is still a year of high risk and volatility for the NT in that you'll have Blacktip that could be declining at that point. I think the Beetaloo volumes, although they've said 2026 as a target for commencement, I think that's an extremely aggressive schedule. I'd expect that to slip potentially into 2027. And again, those fields are unproven. They're not backed by proven reserves at this point. So there is some risk in that supply even being available at those time frames.

Yes. Question, Leon. Is the outcome of the EOI for gas a precursor for the JV to drill 2 new infill wells at Mereenie?

I wouldn't go so far as to say that. I think the objectives, as I've stated, for the EOI are to ensure that we've managed the risk that our fields can be turned down as a result of the NGP. And I've also highlighted an objective is to secure market prices that we see as providing that economic incentive and financial capacity for these wells. We think those objectives can be met with EOI. But I think there's other avenues that we could move forward with that are on maybe outside of the EOI process that would allow us to drill, for example, the development wells. There's opportunities with some of our existing customers and some other outlets for the gas that could be sufficient for us to call fit for the development wells. Again, those are low-risk, accretive to our cash flows. and have a very strong economic return for us. So there's something we're keen to get going as soon as possible if we can. So I certainly think that EOI is a great opportunity to make that happen within the schedule of the EOI, but I think there's other avenues and other options we can look at if that doesn't work out to still call fit and get those wells drilled.

Okay. Question here. Could you clarify the impacts of the EOI on our reserves and resources? Will it lead to a possible reserve upgrade or maturation of 2C into 2P reserves?

Yes, it depends on the components of that. And for the EOI in particular, the development wells are essentially going to be wells that transfer proved undeveloped reserves that are already in our reserve numbers. It will move it from proved undeveloped into proved developed. Proved developed is a key component for us in terms of our financial arrangements with our debt facility so that could open up additional debt funding. When we look at things like the Stairway for example, that's a different approach and a different outcome. What we're looking there is to turn 2C contingent resources into 2P resources. And that reserve upgrade could happen if we are successful in drilling those appraisal wells and get good results with some testing and some time flowing those wells. We'd certainly expect that to add to our reserve base on a proven and probable basis. So depending on what we're doing and what we're drilling, it will have an impact on our reserves. And with the Stairway that could be quite substantial. Palm Valley, obviously, similarly to what we've done in the past couple of rounds on drilling, that field has a substantial 2C reserve component. Simply because of the nature of the formation, it's not conventional where you can get 2P reserves across the whole area that are undeveloped for Palm Valley because it's a naturally fractured field, then we rely on those fracturing. The way it's -- the way NSAI has been looking at that field and ascribing reserves is we get reserves once we drill and we produce and demonstrate the gas is there, and we've been able to do that in the last 2 Palm Valley wells that we've drilled. That's been a great result. We've moved 2C to 2P and gotten 1P reserve upgrades as a result of all that. We'd expect that in additional wells that we drill there. Those will be moving 2C contingent resources into the proven probable reserve space. So again, a solid uplift for that field if we are successful.

Yes. Is there any news on reopening of the Northern Gas Pipeline?

So our official notice at this point is it could reopen by July. It had originally said June. That has slipped 1 month. My personal view is I think there's a significant risk that, that pipeline could remain closed for the balance of this year. I say that because really the only things that are going to change the dynamic of that volume going through the NGP is going to be a new well at Blacktip, and that's not going to happen until the end of the year. If that's very successful, there could be additional gas. It could be surplus gas in the NT. NGP could open from that point. The wells being drilled at the Beetaloo, even though they've targeted 2026, I don't think that time line is realistic. I think it might move into the 2027 year. And again, even then the -- this will be the first time that actually commercially fracked well to demonstrate the commercial liability of that field. And as you can imagine, there's some risk around not just the timing, but ultimately, the production that we're able to get from that field going forward. So I think for the balance of this year, we do have some risk that the NGP remains closed. It's one of the reasons we're favoring keeping some of the cash that we do have as a buffer to manage through that if that does become problematic for us. We're hopeful it's not. But the EOI process, I highlight again, that objective is to ensure that from 1 January 2025, we either ensure that the NGP is open on a firm basis and we don't have that risk or we're able to sell into the NT market and reduce that exposure to NGP outages going forward.

Okay. A couple of questions here, just around, I guess, corporate things. I'll read this one. I'll read both of them out and maybe we can address them together. Can you also kindly provide a view on the joint offer agreement established by former Board member, Troy Harry, noting that this represents 19% of issued capital and potentially a takeover parcel given the undervaluation of the share price to book value. That's one question. Another one here. Are you looking at a cornerstone investor with a 20% stake available at $0.08?

Okay. That's a good topic to raise, and thank you for doing that. I think there's quite a bit of interest from shareholders about that. A lot of you would have seen that announcement. I think it was back in May when that was released. A few major shareholders, a group of them, have combined with Troy Harr running a process to offer a block of Central shares. The total of that block is about 19% of the outstanding shares in Central. So it's fairly significant. That process is ongoing, as I understand. I don't have any direct insight into that process or how it's going. What I would say, though, is that the decision to offer that block of shares is not a reflection of our business fundamentals or certainly our strategy. Our focus remains, at this point, to deliver on the objectives that are highlighted in the presentation and in particular, those milestones for 2024 which is really obviously designed around balancing that opportunity for growth but also maximizing cash flow and trying to accelerate dividends. So that is our focus, but I recognize that, that block sale is out there, and that process is underway.

Okay. Thanks, Leon. So I think we've got one more here around liquid helium. Could the helium liquefaction plant be scaled up to accommodate any discovery or production test at Mount Kitty or Dukas?

It could. I think, probably a more obvious solution is, there's a very substantial helium liquefaction kit that was in Darwin for the Darwin LNG. That is, as I understand, still in the Northern Territory. And there's certainly a potential for that kit to be applied to much bigger discoveries of helium. So the liquefaction plant we're talking about at Mereenie is significantly smaller than what you would see for Dukas or Mount Kitty just in terms of sheer volume. Our percentages at Mereenie are about 0.25%. And one of the reasons that's economic is because we've got an existing field of making money off hydrocarbons. All that needs to happen for that HRU to extract the helium is run it through a membrane process and then liquefy it. The volumes we're talking about for helium are much, much smaller than you would be talking about for, say, Mount Kitty with a much larger percent of the gas stream being helium at that point. So I don't know that it would be the plant itself for Mereenie for liquefaction would be, so to speak, expanded. What I do understand, though, is there's quite a bit of interest in further growth in that HRU at Mereenie to include gas coming out of Palm Valley, which also has a helium stream and even potentially out of Dingo. So both of those have attractive helium components, which, under this HRU process, could be economic. And certainly, that's an area that I think they might expand into or the HRU project team might be looking at as a next step. So hopefully, that answers that question.

Yes. So I think we've covered quite a lot of topics here today, Leon. There's no other questions. So I think we've done pretty well.

Great. Well, on that note, I think we'll be closing the webinar. I just wanted to thank everyone for your attendance today. Obviously, we've got, as I put up on the presentation, some very clear and substantial targets that we want to achieve and close out for the balance of 2024, a mix of some growth -- smart growth investments and activities, again, using third parties where we can, but also a real focus on maximizing cash flows. That includes debt restructuring. This EOI process is obviously critical. We've been working on our cost structure to make sure it's fit for purpose given what we're doing going forward. And again, we've been turning the corner on our repayments for debt and liabilities over the past few years. That will start to free up cash flows as well. So we have a lot to look forward to. We have a lot to do. To me, that's our scorecard. And the team at Central is entirely focused on getting those across the line and having success in delivering that and ultimately, allowing that value to be recognized in the share price going forward.

Thank you.

Great.