Central Petroleum Limited (CTP) Earnings Call Transcript & Summary

Good morning. Welcome to Central Petroleum's half year update for the year ending 2021. A lot has been happening, so we will go through -- today, we're going to go through our half year reports. I'm joined here by Damian Galvin, our CFO...

Good morning.

Who is going to bring our financials to life in an exciting way. And I understand he's got a very interesting drone footage video clip of our fields to show, so that should be certainly worth hanging on to watch. Overall, today, I think the theme that I want to get out or communicate is we had a very solid performance in the second half of calendar year 2020. And that year was remarkable in that the markets had a very substantial downturn, particularly domestic gas markets. That impacted us along with our peer group. We came out of that. And I think our second -- or recent 6-month annual report or half yearly report demonstrates this good performance. I put that down to 2 things. First, we've had solid operating assets that performed well through the year, and also our term contracting synergies proved very effective. So the combination of those 2 have given us a very good, solid, steady performance through a difficult calendar year 2020. We've continued our very good record on HS&E, which is great to report. Market confidence is improving. We see that both in our customers; and we're starting to see an uptick in as-available sales, which I think is an improvement off of what we possibly saw in 2020 or anticipated last year. So that's all positive as well. And it does really set us up for our next phase of growth, which we'll go into later in this presentation. 2021 is going to be incredibly busy. We anticipate probably the most active drilling program in a year that I certainly know of at Central, and that should be very exciting for our shareholders. We've got 2 development wells, 3 appraisal wells and up to 4 exploration wells that we're looking to get drilled this calendar year. And that spread, I think, is -- or certainly reflects the spread of opportunities that this company has both in terms of project delivery, appraisal and more exploration activity, which we'll talk about later as well. And again this is all on top of a very busy 2019, which we saw 4 exploration wells at Range come in and had some very successful results from that. So essentially that's an overview of what we're going to be talking about today. I'll turn to the first page, which is our half year highlights, again steady underlying sales, positive cash flows despite very challenging market conditions. And I think that set us up well for emerging and coming out of this, to hit the ground running and pursue our growth initiatives. We've got a strong cash position of over $38 million. Obviously, some of that has been earmarked for a couple of growth activities, including Mereenie development wells and our Range CSG pilot. We signed a new gas supply agreement, very important. That has allowed us to essentially fund the Mereenie development wells, which will then result in an expected increase in capacity at that field, which is important for us moving forward. We've extended the debt facility to September 2022. That facility is obviously a very efficient form of capital for us, so extending it makes a lot of sense, but it also strategically ties in with the opportunity at Range, where about that time we would anticipate being able to in 2022 being able to package up both Range financing as well as any refinancing under this existing facility. So that works well on that schedule as well. We've got the Range CSG project restarted. We'll talk a little bit about that. That's incredibly exciting. And obviously that's going to be a major milestone in terms of converting those 2C into 2P but also allowing us to pursue and progress the balance of final investment decision activities this year. So we'll talk a bit more about that later. And finally, we announced an MOU with the -- with AGIG for an Amadeus to Moomba Gas Pipeline. I'll give an update on that later as well, but that pipeline, if you look longer term, is really an opportunity for this company to have another step change in its financials and ability to explore and bring to market new supplies from the Northern Territory. At this point, I'm going to hand it over to Damian Galvin. He's going to go through our half year results.

Thanks, Leon. Well, I think, when we went into -- well, when you look back at 2020, if you ask people what words they'd use to describe the year, you'd probably get a mix of expletives and some fairly downbeat comments, depending which part of the world you're in for the year, but I think Leon has probably touched on it. If you were describing Central's 6 months, you may not use the word spectacular perhaps, but you'd -- certainly words like solid, steady, dependable would come to mind. And I think, looking back, it's not about outcome given the market conditions that we saw at the start of last year. And as Leon has mentioned, we are obviously seeing those conditions start to strengthen and gradually claw back towards to a relatively healthy position going forward. I think, the theme, if you were comparing our numbers for the last 6 months with previous periods, it's a fairly simple theme. We're generally pretty comparable to what we did in the first half of calendar year 2020, but then obviously, if you go back to that pre-COVID pre-market downturn period in December '19, we're down probably some 20%, 25% across most of our metrics. And I think that's probably pretty consistent with what we're seeing from a lot of the other producers in the market at the moment as their results are coming out. For example, we have sales volumes 5.1 petajoules equivalent for the 6 months, which is pretty consistent with the June half year, but it was down 28% on December '19. Revenues at $29 million were -- fared a little better. We were down just 19% on December '19. We did have a number of lower-priced contracts roll off. And we took up some higher-priced ones, which gave us the benefit of higher pricing from 2020 onwards. Look, EBITDAX. If people are not familiar with that measurement: That's the typical EBITDA but with exploration costs also excluded. That's what we tend to use as our underlying measure of how we're performing; and generally because we expense our exploration costs, which is a little bit different to a lot of similar-sized companies who tend to capitalize them. So it can really impact your bottom line with some lumpy results. So the EBITDAX number, $13 million for the half year, again down 25% on December '19, but it was up -- actually up about 51% on the previous half year, in June, largely because June -- and that is after you strip out of those June numbers these -- the $7.7 million profit we made on transferring that 50% of the Range project. And that sort of impact, I guess, when you look at that comparison, it was -- the difference really comes down to the fact that in that June half year we did have some higher costs. We paid back, I think, a much higher, maybe even a double, repayment of our overlifted gas in that March quarter. And also we did have some restructuring costs, et cetera as we adjusted our business through the COVID shutdowns. And we weren't able to capitalize quite as many of our staff costs as what we had planned because we had deferred some of those capital projects. But overall, [ we have the ] net profit of $2.5 million. And I think, if we look back and said that would be where we're at these 6 months, we would have been reasonably happy with that. It's obviously down a little bit on the December '19 numbers, but it was up on June. So I think, looking forward, if you look at a full year, we're probably going -- probably not going to be able to poke our head into the black because we do have a big chunk of exploration work at the Range project coming up in the next few months. So that may impact that bottom line, but the EBITDAX number, I think, hopefully, will improve as we go forward now. I think the most pleasing number is our cash, obviously, at $38 million, almost $40 million, in the bank. It's one of our highest cash balances for a long, long time; and net debt obviously one of our lowest. That does have the benefit of the proceeds from that pre-sold gas agreement that we concluded during the half year. And those funds are going to be invested obviously in the Mereenie -- the new wells at Mereenie that we're drilling in coming months. So I think, by the time we get to June, obviously those cash balances will have come down a little bit as we invest in the Range project and those Mereenie wells. I might just touch quickly on the production numbers just to understand how we got to where we are. You can see that, that chart, I think, explains it pretty well. You can see at the start of 2019 we had that big jump upwards as the Northern Gas Pipeline came online. And we held that level up for 2 half years, so basically all the way through calendar year '19. We had average sales of 7.4 petajoules per half year, but unfortunately and obviously, we came into that market downturn when COVID hit in early last year. And we've now held those levels pretty solid and steady for the last 2 halves. And those levels really are getting pretty close to our firm contracted take-or-pay levels. So they couldn't have dropped much further. And they really provided a very stable base of cash flow for us during that period, so now it's how do we get back to those sort of production levels that we saw in 2019. So one will be market. We're already seeing the recovery in the domestic gas market. In the last couple of months, we've been producing very close to our capacity, so we hope to see that continuing going forward. The -- and the other, I guess, aim now is to try and improve the field capacity levels back to where they were back in 2019. And to do that, we've obviously got the 2 production wells planned and 4 recompletions coming up in the next few months. And that should get us back, towards the back end of this calendar year, hopefully, towards those levels that we saw [ previously. We probably won't see that ], the benefit of that, in these coming 6 months, of those wells. She won't be online until midyear. This is where the video comes in, but I'll -- a bit of an explanation on what's happened at the field. So Mereenie, that's the production plant there, big tanks or the oil tanks where we store the oil prior to transport. Mereenie was market constrained during the half year, as I said. We produced about 28.5 terajoules a day on average. That's 100% to the JV. That was up about 10% on June. And the capacity there was about 32 terajoules per day at the end of December. Palm Valley, 9.6 terajoules per day, which was down about 10% on the previous half. And that was largely due to the Palm Valley 13 well coming off its peaks, but it continues to outperform and gives us great confidence for that Palm Valley area going forward. Dingo, our other field, it supplies the Owen Springs Power Station. Its production was down a bit, averaged 2.8 terajoules a day, which was down 18% on the previous half. It is contracted, though, at 4.4 terajoules a day. So we do get the difference in take-or-pay payments. And we did receive about $3 million in January make -- as payment for that overall shortfall through 2020. I'll just scratch below a couple of the numbers quickly. The sales prices overall at $5.66 per gigajoule equivalent was up largely due to us rolling into those higher-priced contracts, and we're seeing markets recovering across the board. Operating costs at around $2.80, up slightly. That's largely due to us having some fixed costs that we were spreading across those lower volumes. So we're making $3 a gigajoule in margin there, and if you take off depreciation, it's still a healthy contribution to our bottom line. And certainly, on a cash basis, those cash flows are really obviously sustaining our business. It's covering all of our operating costs, all of our corporate costs and our debt repayments, so it's certainly the engine room of this company going forward. Finance costs, $2.5 million. They keep coming down, obviously, as our debt is paid down. And also we're benefiting from the low interest rate environment at the moment. Exploration costs, $1.4 million. There wasn't a lot of field activity during the half year, but there was a lot done behind the scenes as the guys made preparations for our upcoming exploration program. There was a lot of work done on permitting, well designs, procurement, tendering. So those programs are close to being ready to launch in the back end of this calendar year. Obviously, going forward, in these next 6 months, we've got the Range pilot being drilled. That, even it's an appraisal activity, we will class those exploration. So that will see a big increase in exploration costs prior to June this year. Corporate costs at $1.8 million, the lowest they've been for some time. Obviously, we had that spike in early part of last year as we saw the -- some restructuring costs. And also we were unable to capitalize quite as many of our staff costs, but we're now seeing the benefits of those cost reduction initiatives flowing through into the bottom line. So I think overall, when we went into that great lockdown of 2020 back in March last year, we had that aim to conserve our cash, preserve these growth opportunities so that we could launch back into them when conditions stabilized. I think we're at that point now. And when I look at that $40 million of cash in the bank, I think we're really well positioned to launch into these value-accretive activities for '21. So I'll hand back to Leon now, and he can take us through what that might look like.

Great. Thank you, Damian. It's a good segue into what we're looking at over the course of this calendar year. Essentially we're in a very strong position to now come out of 2020 and focus on growth, and we do have quite a significant set of strategies for growth that we are looking to implement in this calendar year. The first one is we are targeting increase in production capacity through 2 development wells at Mereenie. As Damian mentioned, that field is currently producing at around 32 TJs a day. Those wells are targeting increasing that capacity up to 45, which is really sort of a plateau that we're going to be trying to maintain. Obviously, investing in those during 2020 when the market was very weak didn't make a lot of sense, but it is definitely looking like very value accretive to get those in the wells. So we've been progressing those and those are on track. Range pilot, we've announced the restart to that. Everything is plugging away well. I'll talk more a bit about Range a bit later, but that's obviously going to be an exciting catalyst for the project, as you get gas to service and derisk some of the technical aspects of the field that we're going to be looking to develop over the next couple of years. We've got the 2021 exploration program. Again that's up to 4 wells. We've talked quite a bit about that. And there are some charts in a little bit that we'll go through, but essentially it's looking at over half of the Tcf of potential recoverable gas. That's what we're targeting through those 4 wells. We've picked those because they are lower-risk and higher-value opportunities that tend to leverage off of brownfield infrastructure so it can be brought on to market quicker and cheaper. So that's exciting. And we do have our longer-term exploration, in particular Dukas and Zevon or probably the big ticket items that we have over the next few years that we're going to be continuing to progress. I'll obviously give an update on both of those in a little, but that's the summary of the outlook. So again obviously a very busy year for Central as we move forward. All right, okay, quickly on the Mereenie development wells. As I mentioned, we're looking to get 2 in there. Those are -- remain on track. Timing for those, we've got recompletions that essentially are kicking off in April, May. The development wells would then come in, in June, July. And obviously that sets us up for improved sales in the second half of this calendar year, which the intent obviously is to get back toward that 2019 performance level. We'll flip through at this point and talk very quickly on Range. I won't spend too much on this slide. This has been around for a while and I think most shareholders recognize the potential value of this project to Central. We had some great exploration results in 2019. And our 2C certified resources of 135 net to Central is obviously very substantial relative to our existing reserve base. And we have mentioned before those are the highest classification of 2C, those development pending. So really, as we work through the pilot but also the balance of FID activity, that will then allow us to convert those numbers into 2P. And you can see how significant that will be for the company as we go through this derisking and advancing the project over the next couple of years. This is a map that shows where our pilot program is intended to go or where it is going. Currently the update on that is we have got approvals in place for the pilot wells. Rig has been contracted. We released an announcement about that. Water tank and civil works are underway and on schedule. And again, we are targeting April for drilling. This would allow testing from, say, May. And we're looking for about 3 to 6 months of testing to get a good read or technical information on that pilot program. So that's the schedule. It's on track, and that's going to be really exciting to get drilling in really a couple of months. You'll see there that the location is somewhat in the central area between Range 2 and Range 3. We've got those wells spaced at about 200 meters, which is closer than what you would do on a development basis, but because there's not a lot of production or dewatering occurring around the perimeter or within the permit, that allows us to get a technical result quicker than if we had spaced them at full development spacings. All right, the exploration program. I've talked to this quite a few times. We're looking at up to 4 wells. On a unrisked basis, it's well over half the Tcf that we are chasing in terms of recoverable gas and quite a substantial amount of oil at Mamlambo if we do drill that. Preparations are going well. We've got well designs, permitting very advanced. And we are ordering long-lead items at this point just to be able to maintain that schedule. And again, that schedule, we are trying to get those wells drilled in August, September and October, which will allow us to really get that substantial amount of drilling done this calendar year, which I think is exciting. I'll talk a little bit about the farm-out process, which is our strategy to fund that exploration program. And I think that's coming up, but to follow up: We have been progressing this for a number of months and have been putting in some resources and some capital to ensure that the long-lead items can allow us to maintain that drilling this calendar year. So that's on track and progressing well. This map shows really the activities on that exploration program. Obviously, A through D is the exploration program itself. Those are drill-ready prospects that we're going after. That's the targeting 593 of what we're calling lower-risk gas simply because they're in or near fields or have -- or targeting zones that have been commercially or otherwise producing in other parts of the basin. So that's exciting. I think, the top 2 in looking at those: Palm Valley Deep is really exciting. It's a substantial exploration target at 123 petajoules, but we also have the benefit of being able to sidetrack that and get a production well very similar to what PV13 has done. And that well obviously has exceeded our expectations and been a very good outcome for us, so we're hoping PV12 has a similar kick, which obviously is going to be very helpful for the company's cash flows and financial performance going forward, but we do piggyback off that and be able to get a -- be able to test that a target formation which hasn't been tested to date. The other one is Orange. It's a very large structure, several formations that we're going to be targeting all the way down to the deep zones. And it's got a target of 400-ish petajoules, and so that's something we're obviously pretty keen to take a crack at. That would be a -- quite a substantial game changer if that were to come good. And then the other 2, obviously those are exciting and something that are drill ready that we're looking to progress as well. So that's a bit of an overview for the exploration program. We do have the multi-Tcf sub-salt target plays. We've got really 2 identified. Obviously, Dukas is much more advanced in terms of seismic and partial well drilled into the [ salt seal ] but suspended. And we have in our EP 115 [ a permit ], Zevon, which we think is actually really exciting for a number of reasons that we're going to be turning our focus to and -- or have been turning our focus to progressing this year and trying to get that in a drill-ready state at some point possibly next year. So moving on, a quick update. And I know there's quite a bit of interest in this particular slide. I'll start with the farm-down -- or farm-out process of our producing assets. That process has been going on for an extended period. It was obviously kicked off in very weak market conditions. And the key for us was to ensure that we had a party that saw through the -- what we saw as temporary market conditions and longer-term supply demand fundamentals, and we ultimately found a party that was able to do that. And if you look at the purpose of that format, it was really to accelerate this exploration work that we wanted to do. We put a previous price tag of 45 million to 50 million for all of that work, and obviously that's a significant amount for a company like Central. It's something we could fund over time through our cash flows, but if we're looking to accelerate and bring forward exploration activity in the basin, this looked like a potentially attractive method to do that other than the equity markets, which we don't think are going to be pricing these assets to the extent that the industry might be pricing. In doing the farm-out, we've identified really sort of 3 critical criteria. We need a credible joint venture party. That's important for us in terms of both ability to keep pace; add value technically; and also be able to fund exploration, appraisal and development throughout the basin. So that's an important part of the checklist. Alignment is key. And I think that's something I'll talk a little bit about in the next update on Dukas, but alignment between joint venture partners is really important to us and it is something that we're very focused on. And the last thing we want to do is do a deal that either slows down or complicates our exploration activities throughout the Amadeus basin or appraisal activities. And the final one being value accretive. We don't need to farm-down. We are not in a distressed situation where we are unable to fund our activities and a certain amount of organic growth through our cash flows. What this is, is if it -- if we do find a transaction that's value accretive, we will bring it forward. We've got a preferred bidder. We've been working with them for a number of months on final due diligence and really mopping up details of the commercial and legal terms around a farm-out. The deal is not done at this point, and we think there's light at the end of the tunnel. It's something that we're still committed to and working hard toward, but I want to make clear that this deal is not done at this point. And my expectation is, if we are not able to get this across the line by the end of this quarter, there's probably a bust somewhere within the transaction. So I don't think this is going to drag out too much further. Parties have had a long time to work through it. I'm hopeful that it will eventuate and get closed, but it's important to highlight that these deals are not done until they're signed, yes, on the dotted line. And we're not desperate sellers, so we want to make sure that whatever farm-out matches the criteria that we set forward when we embarked on this very substantial transaction for the company. I'll move on to Dukas. Obviously, we put out a release providing an update to the market. The short of it is that, after suspension in 2019, the joint venture has gone back. We've done quite a bit of work both in terms of the required rig and well design for very high-pressure deep drilling and exploration. And in addition to that, essentially what's happened is, as you drill Dukas-1, you're able to then match stats and reconcile it with the existing seismic in that area and then use that interpretation to reinterpret the balance of seismic throughout the permit. That is not an easy task. This is an incredibly complex prospect. It's got faults. It's got thrusting. It's got salt which is incredibly hard to deal with on a seismic basis. So all of that has been happening in the background. As we announced last year, our target was to have the joint venture make a decision on how we approach drilling Dukas. And we've identified a couple of options from redrill to a completely new well somewhere else. And the hope was that, that would be put forward to the JV by the end of this -- by the end of 2020, and we'd be off running and targeting sort of mid-year 2022 for a drilling start date. At this point, there has been no proposal put forward. What we've been told from Santos, the operator, is that they require further technical work. We haven't been given any guidance on how long that will take or what that is, so obviously that's problematic. And I will say a couple of things: One, Central supports the original suspension of the well. It was clear that, that was a necessity. It was completely unexpected and not something that anyone would normally invest to prepare for. It was quite surprising development. So we supported that. And we do support the reinterpretation and technical work that is required to reinterpret our seismic. Our team is doing the exact same thing and seeing the complexities that Santos is seeing. It has probably raised as many questions as it's answered, so there is quite a bit of valid technical, particularly for a incredibly complex target such as Dukas and the amounts that we're looking at in terms of getting a new well drilled in there. Where my point of frustration is -- and I can assure everybody that I and the management team and in particular the exploration team as well are very frustrated with the pace at Dukas. It's a pace -- and in particular, it's the fact that it's been 18 months, about, since the suspension of the well. In our minds, that's plenty of time to get that technical work done and come up with a decision. Personally what I'd like to have happened is, sooner rather than later, Santos making decision on if and how they're going to progress. So either move forward and let's get going with this well and prospect, or step out of the way and let Central move forward. A couple of things I want to highlight. We're a minority nonoperator. We do not control the timing. We cannot force Santos to do things unilaterally. To put it in perspective: Santos have spent tens of millions of dollars in EP 112. Central has spent in the order of $2 million since 2006, so they have a significantly larger investment in terms of dollars and resources going into this permit. So to assume that Central is going to be able to force Santos to do something that's not in the commercial interest is -- just is fantasy. And we have to play within the parameters of the farm-out agreement that we have. And really, at this point, we've got very limited options other than working with them constructively to advance and accelerate a proposal and get this thing going, but there are a couple of backstops worth highlighting. The first is, in July of this year, Santos will need to make a decision on our free carry, if they're going to free carry us. And if they do, that's an interesting bit of information in terms of how we're moving forward. If they don't, obviously they drop back from 70% to 55% and we go up from 30% to 45%. And the fact that they would give up 15% interest in a permit that they've spent so much money on without any compensation for that, I think, would be telling as well. So we'll wait and see what happens in the middle here. Obviously, we're trying to get a decision and outcome ASAP and we're pushing very hard for that, be assured, but that's the next sort of contractual milestone that we have for progress on Dukas. The other is that there is a permit commitment that requires reentry or a new well in 112 prior to the end of 2022. And so that's really sort of 6 months after when we're hoping to get Dukas drilled. In any event, that requires them to actually put forward budgets and plans that allow for that to be possible. So really I think, through the course of this calendar year, whether it's July or shortly thereafter, we will be in a position to get clarity on what Santos is doing and be able to force the issue a bit more, but as we sit today, very limited opportunities for us to force Santos, as frustrating as it is to force them to do something that they don't have to do contractually and commercially. Obviously, they have a significant amount of resources invested already that they aren't going to give up unless there's a valid reason to do it and timing requires them to do so at that point. So essentially that's the update on Dukas. It is disappointing. What we're doing about it is obviously we'll continue to press on it, but in the background we have taken all of the information and learnings from Dukas and have been working on progressing our Zevon prospect, which we actually like very much. We think there's a couple of advantages. One is probably half the depth, and the second is it's a much simpler target geologically. There's not the same level of faulting and thrusts and complexities that we see at Dukas, so it could be a much less-complex play to go after and obviously much shallower. Dukas was approaching 4 kilometers. That's a deep well through hard rock. So Zevon is in the 2-kilometer range. Obviously that makes things much easier to drill and manage. And we'll have more on Zevon and how we're progressing it over the course of the next few months as that moves forward. Final one, Amadeus to -- gas pipeline we announced in back end of 2020. Where we're at on that, we have -- as mentioned, we are seeking to get third parties to participate as foundation customers for that pipeline. We've got about 200 petajoules uncontracted. And if we were to get maybe something in the order of another 100 petajoules of foundation contracts, foundation volumes through the AMGP, I think we'd start getting to a point where FID is very possible. At this point, we've been working hard with third parties on that. There are some technical and pipeline constraints associated with it. It is progressing but slowly. We're going to continue to work it. There is nothing in the immediate term I see in terms of having that closed. We're going to keep running that because, I think, that's a very good outcome if we can aggregate that volume and get this pipeline cross on a FID basis very quickly, but in parallel to it, we are obviously keen to accelerate and progress and get our exploration program drilled. And if you look at the targets that we're going after and the volumes we're going after in our exploration program, certainly some moderate success out of that could bridge the gap and be a catalyst for FID at some point for the Moomba pipeline. Obviously, when you drill it, you don't get reserves, so we wouldn't be signing up for foundation volumes at that point in time this year. What would happen is a positive exploration well at any of the targets will then lead very quickly into an appraisal program that would be designed to provide confidence on the commerciality of that prospect. So that would happen, I guess, in 2022. And at that point, you'd be in a position to consider signing GTAs and underwriting and calling out FID for the AMGP, but AMGP obviously, longer term, is a real game changer for us. The cost savings to get it into the southeast coast market is substantial. And particularly if you look at our margins, it's -- it'll have a huge impact on profitability and opportunities in terms of diversifying where we sell our gas. So it's something we're really excited. We're going to continue to progress, but at this point, I want to make clear that we're not looking at having a FID called imminently. I think we're working a couple of angles, and it is a -- possibly a longer-term project. And when I say longer term, I mean in the next year or 2 in terms of getting that across the line and FID and get that going. Okay, I'm going to wrap up very quickly on this last slide, which I think is intended to really put into perspective what we're trying to do. The gray bars are essentially the number of wells that Central has drilled or participated as a joint venture partner in drilling since its inception in 2006. So you -- really you're sort of talking 14 years of activity at Central. What we're trying to do is highlighted in the orange. And in that first bar graph you'll see on the conventional side, we've got 2 wells at Mereenie that are development wells that are progressing and up to 4 exploration wells. And if all of that were completed this year, yes, you'd be looking at 6 out of a current base of 11. So you can see the -- how substantial 2021 is going to be relative to the activity that this company has had in the past 14 years. It is exciting. I think it's -- from a timing perspective, it makes sense because we do see in 2024 in particular markets being very robust. And these would obviously feed into that schedule. The chart on the right is our CSG activity. And what you'll see is historically that gray bar of 6, I think, largely in the Pedirka previously. In 2019, we did do our 4 exploration wells, which you'll see on top of that, so technically there's been 10 wells drilled to date, although 4 of those have been through the Range project. And then if you look at what we're trying to do with 3 wells in 2021, you can again see that it is a substantial increase in the number of wells relative to what this company has done historically in the past. So it's a big program. Obviously the exploration wells are somewhat dependent on capital in particular and therefore the farm-out process, so there's no assurances that all of these will get built. The Mereenie wells and the Range wells are fairly mature and funded, so we expect those to happen, but really the opportunity around the additional 4 exploration wells is exciting. And we're working hard right now to make that happen in this calendar year. So essentially that wraps up our formal presentation. And I think we're going to take it over to Q&A, if I'm not mistaken. Okay...

That's right, yes. We've got a couple of questions come through, Leon. So we have some [indiscernible]. You may have addressed a lot of these already, but I'll go through them, anyway.

First question. What is the approximate updated cost of the Range pilot program and also the approximate costs of the Mereenie recompletions and development wells?

Yes. So -- and I think we've talked about this. The amount of money we received, when was it, in 2020, fiscal year 2020, from the Range farm-out...

That's right, the $7.7 million.

$7.7 million. The FID project itself is intended to fit within that number. I think we've been able to reduce a few costs, and we might be in the $6 million to $7 million range net to Central. And so that sort of is a ballpark of the pilot program itself and what we're looking. That's all-in costs obviously. So that's the basis for us to have said, look, we've got the money from Incitec. We quarantined that. And given the improvement in the market that we saw certainly towards the end of 2020 and early 2021, we've been in a fortunate position to be able to commit those funds to the program and get that pilot project started. What was the other one, the Mereenie wells...

Mereenie wells, yes.

So the Mereenie development wells. If you look at sort of drilling more generally in that area, costs of between $13 million, $14 million, $15 million per well is -- tends to be a fairly good benchmark. We're doing 2 of those, so obviously our share will be half of that. So I guess something in the $13 million to $15 million range probably isn't a bad estimate at this point for all-in costs for those wells.

And that's with the recompletions as well probably squeezed in there.

Yes, that's correct. So the recompletions are included in that, obviously not as substantial costs, but those costs are included in there.

Yes. A question on the exploration program, [ really the ] exploration growth program and the potential commercial success. What sort of potential threshold volumes would be required to underpin AMGP? Can you answer that one, [ please ]?