Touchstone Exploration Inc. (TXP.L) Earnings Call Transcript & Summary

Good afternoon, and welcome to the Touchstone Exploration Investor Presentation. [Operator Instructions] The company may not be in a position to answer every question received during the meeting itself. However, the company can review questions submitted today and publish responses where it is appropriate to do so. Before we begin, I would like to submit the following poll. And I would now like to hand you over to CEO, Paul Baay. Good morning to you.

Thank you very much, and thanks for everybody joining us today. It's really a great time to give everybody an update as to where we're at. It's going to be sort of a combined update of the quarter, second quarter results as well as where we're at with the various projects and a little bit of a look forward as to what we see between now and the end of the year. It's obviously been pretty noisy in the last little while. So I'll try to go through that and clear a bunch of those things up as we go forward and then lay out what the exciting plan is we have between now and the end of the year. So just start with a quick little summary of Touchstone at a glance. We've got about 260 million shares outstanding, trade on both the Toronto and the London Exchange. So you see the Toronto listing number on there. For the 6 months ended to the end of June, it was -- it's a little bit of a messy quarter. I like to refer to it that way because we did the major acquisition of the Central Block facility that came in on May 16. So it shows up for a partial period in here. All the costs associated with it are in there. And because the way the deal was done, it's actually a look back to January. And so there's some very high costs that are associated with that and it doesn't really reflect truly the acquisition going forward. So that's why I refer to this quarter as being a little bit messy. You can see that the natural gas sales, funds flow from operations for the 6 months, just over $4 million and the operating netback of about $14. And we'll talk a little bit about how that's going to change and move up. And at the end of the quarter, we had about $6.3 million of cash. And then the net debt went up dramatically during that quarter because we dropped on the full amount for the Central Block acquisition of about $30 million. So in essence, it doubled in that quarter. So when I say it's a messy quarter, really, you had all these costs, you got the debt, you've got everything kind of dumped in for the Central Block acquisition, and we haven't had seen all the revenue for it yet. So I think what you'll see is couple of quarters, Q2, Q3 will probably still be a little bit messy as we get things sorted out there, talk about some cost savings we're doing, some onetime expenses. And then what you'll start to see in Q4 is a really nice clean look at what the go-forward rolling rate will be for Central Block as we go forward and talk about the reserves in here. These are the combined reserves of the company now, including the Central Block acquisition. So we talked a little bit about Trinidad and the opportunity in Trinidad, and I'm not going to go through each one of these. I think what we are finding, though, is this is actually becoming a pretty friendly jurisdiction, very encouraged by the new government that's come in. We've had a meeting with the minister and some of the things that we're seeing. I think that it will be interesting to see when the budget comes out in October, how they want to deal with our industry going forward. But certainly very encouraging things from the government on shortening the time line for approvals, and various other sort of initiatives that they're taking on. So we're excited from that point of view. I think the biggest change for us, though, is really the market access that's happened for us in Q2. We'll talk a little bit about that in some other maps here. But there's sort of 3 main business or 3 main buyers of natural gas in Trinidad. There's the chemical business, there's the LNG business and then there's the electricity. All the power on the island is generated by electricity. And we were sort of held hostage a little bit to the domestic market, which is the electrical market and the petrochemical market. And now what we're able to do is certainly between now and May of 2027, we get a little bit of the benefit of the LNG market. And then in May of 2027, we get this nice sort of clean part of our portfolio that will shift into the LNG world, which I think is pretty exciting and it will really be a nice balance to the portfolio in what we see. As far as the rest of the things go that we've got going on in Trinidad, I think all the equipment is there. There's certainly lots of demand for the product. And as I mentioned, the government seems to be very open for business. So we're excited to be there. And probably more important than anything, it's right off the coast of Venezuela, which makes it the updip end of the Venezuelan basin. And for those that might be new to the story, it probably is the richest hydrocarbon basin in the world. And so that's the right place to be from a geological point of view. Talk a little bit about the second quarter, and I talked about this being a little bit messy. And I think what -- probably the biggest thing was the drop in the Central Block that came in, in May of May 16. And so we really only end up with 45 days of production from Central Block in here. But there is a lot of costs, a lot of the closing costs, a lot of the onetime expenses are in here as well, and that's why you really see the much lower funds flow in the quarter. Now as we ramp up the production and we get those things cleaned up, you'll start to see, as I mentioned, a much cleaner quarter. Probably part of Q3 should be pretty clean, but Q4 certainly will. But give you one example would be at Central Block, there's a facility there that was put in place by the previous operator where the staff were 2 weeks on, 2 weeks off and they stayed there. And it's about USD 35,000 a month, and we just don't -- doesn't make sense, but it's going to cost us probably somewhere in the order of about $0.5 million to take it out. So it's those kind of onetime expenses that we're working through to make sure that we lower the operating costs as we go forward. As far as the volumes go, the average for Q2 is about 4,300. We put out in that release last week that it was about 5,100 for the month of June and July was about 5,300. So I think what everybody should be getting a little bit of comfort with, I certainly am, is that we're seeing some nice stable production from all of the properties when you combine them all together. So that's the point from looking at that. And again, you can see the net debt number basically doubled with the $30 million of debt that we took on to do the facility. The guidance that we put out, we changed this. And if you recall, we haven't put out any real revised guidance since December when we first announced that we were going to buy the Central Block deal. So quite old guidance. And in that previous guidance, we had a bunch of Cascadura wells coming on early in the year and then coming on a little bit later. And that's really the only difference here is that those Cascadura wells that were going to come on in February, early March are now going to come on in October. So that's why the production has been pushed out, and that's why the funds flow have been pushed out. And really, the reason for that is we wanted to focus on the Central Block acquisition. And as people that follow the story quite closely know, we had just a nightmare when we went in with a new mud system earlier this year to try to drill the first Cascadura wells, and it just didn't work. So we had to suspend operations since we've come back and now drilled one successful well. And as of today, we're over top of the other one and drilling that out as early as Wednesday. So I think there's some delays in here, but certainly, it hasn't been production based. It's been more production based on the drilling not coming on in what we've seen and the new guidance that you see here. So the production overview talked a little bit about this. And we continue to show this, but I think it's really important to look at it in the wedges that we see now. You basically see that legacy oil production across the bottom. You see Coho, which is that single well, which has almost been on for 3 years now. You see these initial wells coming on at Cascadura and then you see the steep decline. And now we're starting to see that level wedge at the back end of it. And the same thing with the central block, which has now been dropped in, in blue. And that's where I say we're running sort of that 5,300, 5,400 BOEs a day consistently every day now. A lot of that is depending on line pressure that comes in from the main line that we go into at Cascadura. We're seeing the wells really get bounced around on that. And as a result of that, what we've done is we've sped up the compression project that we originally had in the engineering program. We've actually sped that up now where the purchase order went out last week, and we've identified a unit in Houston that will work for us, and we're looking to bring that on in Q2 of next year. And that will just stabilize that production. And I'll talk a little bit more about that, but we'll really have 2 phase flows at Cascadura. We'll have the compressor phase flow. And then as we bring on the new wells where you see those big spikes in production, they'll go around the compressor and just go right into the facility. And then when their pressure drops down, we'll move them into the compression. So it's going to be that next stage for Cascadura and what we see. Talk a little bit about the asset overview. We've now got all these facilities in place. We basically own all the natural gas processing onshore in Trinidad. We've got our Coho operation, which actually processes the single well and then takes the gas down into Central Block, where then it goes -- gets sold from there. And then we've got Cascadura, which, as I mentioned, we're going to drop in the compressor. But basically, we have all the facilities built now, and it's just a matter of what I've been referring to for a couple of years now, drill to fill. And as we start to work out the kinks in our drilling program and we start to have that happen, you'll just see these volumes ramp up as we go forward. You're still going to see the steep declines in the Herrera wells. That's not going to go away. The whole idea here is to get all our money back during those steep declines. And then now that we'll have the compressor in both at Central Block and at Cascadura, you'll start to see this nice level, predictable flow of income coming out the back end of that. So facilities are in place. Talk a little bit about the marketing, and this was the big change for us at Central Block. You can see that new red arrow that basically takes our gas at Central Block out to the LNG facility before everything had to go up to point leases on that side. And the Central Block sales, although it goes to LNG from now until May of 2027, so just a little bit over a year, I guess, about 1.5 years. There's still a Henry Hub gas component within that contract. So you won't really see that really higher priced gas contract until May of 2027. I know there was some confusion around the Q2 numbers because the gas price looked low at Central Block, but we actually get paid 3 different checks for our production in the central block. One is we get the condensate that gets dropped out at the plant. So that's the first one we get. And then when the gas hits the LNG facility at Atlantic, they strip it again, and we get 2 checks there. We get one for the gas and then we get one for the propane, butanes and all the other -- the liquids that are in there. So you get kind of this combination. But on a per MMBtu when you combine the 2 of those, you'll see -- so it's going to be a different way of reporting for us. Everybody is going to have to kind of get used to it in what we do. The other thing is we only get paid at Point Fortin when the ships leave once they're loaded up. So the production will be a little chunkier as we move along, there'll be inventory as we move along. Production won't always match sales. So you might get some carryover. So there's some new things that will be coming out. And that's when I talk about Q2 being a little bit messy again. Q3, we get the rest of the costs sorted out. We'll start to get these inventories balanced. And then going into Q4, you'll really see, it will become pretty compelling why we wanted to see Central Block as part of our assets. And now I want to start talking about this next stage because the development drilling we got at Central Block, the development drilling that we've got at Cascadura, those are now underway. They're moving forward. We've got the locations at Cascadura. We've got approvals to start construction now at Central Block, which will happen here in the next week or 2 once the forestry is done with their jobs on stamping trees. So now we've got to kind of look beyond that a little bit as we fill up those plants. And we've really got 3 different prospects that we want to talk about and these are in the same formations in the Herrera. And the biggest one is Cipero, which sits just north of Cascadura, actually just north of Coho really. It's a beautiful big structure, sits right in that window. It's not very deep. It's about the same depth as what we drilled. So we're starting to scout out that location and looking at when we can do that as the funds flow start to come in next year, although we're going to use a big chunk of the funds flow for next year for paying down debt. We'd like to get that debt down significantly from where it is now, but the other piece will allow us to do development drilling and look at the exploration. Cipero will probably be the top of the list. Charuma, I'll talk a little bit more because it's a different type of play. And then Rio Claro is more of an oil play, a little bit shallower on the Rio Claro block, and we'll look at adding that to the portfolio as well. So for the first time, I think, in about 9 months, you'll start to hear me now talking about where do we go to that next stage as the development drilling continues along here. Really exciting what's happened in the last couple of -- well, literally in the last month here on the Cretaceous in Trinidad. We've been talking about it for a while. We think there's a great Cretaceous opportunity. Guyana offshore, it's now become the fourth or fifth largest producer, and that's of the Cretaceous. The big player there was Exxon. They did a bunch of work in Guyana. They're going to be over 1 million barrels a day there. Interestingly enough, in the last 2 weeks, they just stepped into Trinidad and did a private deal with the government and took on 7 offshore licenses for the Cretaceous up to the northeast part of the country. But I think what this should signal to everybody is the fact that the Cretaceous fairway heads right this way. And the fact that Exxon is willing to step up and make a commitment for both seismic and I think well in some very deep water should give everybody a little bit of encouragement that there's obviously an opportunity for Cretaceous. And when we look at Kraken, St. Croix and up north, which that's the Charuma, [ Cokos ] or Charuma, these are all big plays that we look for. I've been asked a lot of questions, are the gas or oil? I don't know what the target would be. If it would be like what Exxon has seen, it would be more of an oil, a lighter oil in what we've seen there. And we think it's the source rock for a lot of what we're drilling up holes. So this is pretty exciting. The first one, I think, that would likely be drilled here would be the Charuma. The St. Croix actually sits right below the Cipero Herrera anomaly, so we could do both of those. So once we get the drilling program figured out here, we get a little more confidence, we get a few more of these wells under our belt, then I think this opportunity becomes something that gets pushed much closer than it was a couple of months ago when we were looking at things. Social governance, those things have really not changed. It's remained very much a local workforce in Trinidad. We have brought in some more consultants lately, especially on the drilling front to help us sort of use best practices from around the world. But as we do that, we're always integrating our local content to sort of transfer that knowledge as we go. So between now and the end of the year, basically, what we've got is we've got 5 wells coming on stream. We'll have Cascadura-4 and -5, -4 that's drilling right now, 5 already drilled. We're going to speed up that process a little bit. We're going to end up perforating both of those wells using the drilling rig, save us a little bit of time, and we'll get those on right away. Then the rig will kind of sit off to the side there. Then while we get the Central Block ready and the Central Block well will be drilled between now and the end of the year. Right now, we're not forecasting it coming on until January. It may be able to compress that, but I think January is when people should sort of look at that coming on. And then we've got 2 wells that will be drilled on our oil properties, and that's as a result of a swap or a disposition. We're selling about 60 barrels a day of production. And the contractor we're selling it to will drill a couple of wells for us. So really no cost to us on those 2 wells, but we're able to get those funded, which are commitment wells. And then the other part is doing the design, the ordering for the compressor, which, quite frankly, will be the game changer for 2026. When we get that dropped in, we'll have very, very predictable production then coming from both Cascadura and from Central Block. And then we'll be able to get a nice steady sort of bottom wedge, if you want to call it that in the production graph. And then as we bring on new wells, we can bring them on as they decline, then we go from there. So actually a very busy year between now and the end of the year, and then we'll see those results and then give you some guidance on 2026. So I think that is where I'll leave it for now. And then maybe what we'll do is we'll hop over and take a few of the questions.

[Operator Instructions] I would like to remind you that a recording of this presentation along with the copy of the slides and the published Q&A can be accessed via investor dashboard. Paul, as you can see, we have received a number of questions throughout today's presentation. And if I may now hand back to you and kindly ask you to read out the questions where appropriate to do so, and I'll pick up from you at the end. Thank you.

Perfect. Appreciate that. Yes, I'll start out with the first one was what are the costs that could be removed from Central Block, for instance, reduced staff numbers, shifts, water disposal, synergies. Those are all good things. I think I talked about the living quarter, so we won't talk about that. Yes, we didn't bring any G&A costs over at all with Central Block. It was just staff in the field, 14 employees came over. But water hauling is a really good example. They were sending that to a third party. We've got a water disposal well. So we can certainly do that one happens fairly quickly. Some little things like they had a helicopter on standby. We don't need a helicopter on standby. They had a lot of top office costs that were getting pushed down in what we see. So the run rate right now is probably $350,000 to $500,000 a month. And there's a little bit of gap in there as we continue to clean that up. But that's probably down from $1.5 million a month already just in the way we've done it. So there's definitely some synergies. But there's some costs to doing those things like moving the facilities out, letting people go, doing all of that kind of thing. So that's why I say it's going to be a little messy in Q2 and Q3 as those costs work their way through the system. The next question is, has drilling at Cascadura-4 commenced? If not, when can we expect drilling? How long do you expect the drilling to take? When drilling is completed, how long will it take for tie-in Cascadura-4, -5? That's a great question. So we actually moved the rig from -- it walks on these big tracks. We moved it from Cascadura-5 over to Cascadura-4 on the weekend. Schlumberger has been in doing the mud, getting everything ready. Ironically, and I know this is going to sound strange, there was an air strike here in airline strike in Canada, Air Canada went on strike, which is the way a lot of the crew gets down. So they've been delayed a day, but they're arriving today. So our plan would be to probably drill out the packers and the plugs here starting on Wednesday. And we're targeting about 17 days from beginning to end on that. And then following that, the rig will then go and do the completion of those 2 wells. Depending on how fast we get approval, it may just walk over, do 5 and then come back and do 4. James is working on logistics of that and then have those on stream. Our target is to have those on stream in the month of October. So that's what we're looking at for the Cascadura wells. So that operation is going as fast as we can make it happen here. And again, it will be the same crew, same supervision, same mud system, everything else that we did on Cascadura-5, which came in slightly under budget from where we were. So a big win on that one. And then the rig will move just off to the side, and then we'll move it to Central Block. And this next question is, why was the realized gas price for Central Block low at $2.75 when it was expecting to be in the $4 to $5 range, which is a great question. I think I already answered it a little bit in that when we talk about that $4 to $5 price, it's really the price we get for the gas at the inlet to the Atlantic plant. But what we've now found is that we actually get -- it gets stripped again inside Atlantic. So if you look at the checks and what you're going to start to see is us reporting in probably MMBtus, which is kind of equivalent to the Mcf, and you'll see that roughly $3 to $4 range. I don't think it will get to $5, but we'll certainly see $3 to $4 range in -- for those contracts until May of 2027 or if we can get above 22 million cubic feet a day. So I should have mentioned that the contract only goes to 22 million cubic feet a day. And then the higher price contract is any volumes up above that. So that's one of the reasons. You will see the $5 and higher gas after May of 2027 when Henry Hub, the Henry Hub component comes out of the contract. So you'll start to see those ramp up. But Scott and I had a long discussion about how to report this because it's -- and obviously, the way to report it is, however, we have to under IFRS. But what we need to do is then bring it back to the shareholders and sort of give you a combined rate of what the MMBtus look like because it's basically what we're getting paid for the gas. And I should mention those numbers that you see are after all the processing costs, right? So there's no processing costs even when you see that $275. So it's actually still a much higher price than what we're seeing at Cascadura. The next one is the fall in Cascadura and Coho is not relenting and then there's a bunch of percentages on Cascadura and Coho. Gas wells decline, like that's the reality of the business we're in is they do decline. The slope of them will change. But if you -- the biggest thing to look at is look at the Central Block declines and then look at the Cascadura declines, same formation. The difference is when BG built that plant 20 years ago, they put compression right in at the front end. So they've been not subject to these line pressures that we have. Quite frankly, we thought we'd get a couple of years away without having to put in the compression. That's obviously been moved up now. But let's be clear, natural gas wells decline. It's not an infinite gas pool. So as you take gas out, you see those decline. What you want to see is see those drop off into lower sort of single-digit declines. And we're seeing that. And even if you look at Coho, I mean, it's been on a fairly long time, and you still see these nice declines, and that's what it's going to be, and that's the reality. That's also why you need to be drilling wells every year into these pools, the development wells to keep them going. So I appreciate the question. I think -- and you will see the declines change at Cascadura depending on the line pressure. So if we get a month of really high line pressure, let's say, above 700 pounds, it will appear like the wells are declining more, but they're really not based on bottom hole pressure. It's the surface pressure that makes it look like that from a production point of view. So we actually ran downhole production gauges in Cascadura 2, so we can actually see what's going on at the reservoir. And we will run downhole recorders in Cascadura-4 and -5 as well, and then we'll be able to see what the pressures look like downhole. But to give you an idea like when the pressure drops, if it's really high for 5 or 6 days and then it drops, we see those volumes come right back up. If it was pure decline, you wouldn't see those production go back up. So it may seem a little bit frustrating from a shareholder point of view, but it's the way the reservoir performs once we get these compressors in instead of seeing 650 to 700 pounds. The way Kevin and the team has this set up right now, the wells will see 300 pounds, and they'll just see 300 pounds every day. And it's also better for the wells to run at a steady rate. So I think Q2 of next year, you'll really see a much different production profile of the CAS, and that's basically going to run for the next 15 years, right, as we continue to add on to it. Next question is, we keep seeing hourly costs, the bridge, the pump, all those things. Yes, I mean, the bridge issue, I mean, I think we had some folks down there. I mean, you understand once you see the size of this, what the bridge issue is and everything like that, those things are going to happen. There's no -- you talk about the pump. I think you're probably speaking about the pump in CAS-3, that's -- ran the pump, pump standed up. We had to change off some equipment on the top end of it. Instead of going back in and wasting more money by putting it back on pump and having the same thing happen again, redesigned it, and that's going to happen here in the next couple of months. So it's part of the exploration game is as we see these new reservoirs, we have to figure out how to produce them. But I don't really think that, that one is an overexpenditure as much as it is just trying to understand the reservoir. And those will continue to happen, especially as we move to Cipero, Charuma and into Rio Claro, those blocks will look quite different. Although Cipero looks a lot like Cascadura in a technical term for sure. The extra funding by year-end, can you explain how we can fill that without further dilution? And what somebody is referring to here is the question is, in our last disclosure under our banking agreement, we have to raise about another $7.2 million of equity between now and the end of the year. And this was put in place when we did the Central Block acquisition. You can see the debt jumped up dramatically because the bank funded the full acquisition. But what they wanted to make sure and what we wanted to make sure was that we had enough funds to do the whole capital program as it rolled out. And that was the whole idea of getting the number and the bank and us agreed that, that was the number that we wanted to do as we went forward. The question is how much of that will we have to by the end of the year? And you probably saw in that last statement, we said or whatever we agreed to on the bank. So we'll be talking to them throughout. And it's really going to depend on how the wells come on. If Central Block keeps outperforming the curve the way the team has it right now, all of those things, we'll have a review with the bank between now and the next quarterly. And I hope all of those things that we've got, all that noise that you hear in there, whether it's the equity, whether it's the -- everything else that's going on, that's all going to be cleaned up by the end of the third quarter so that when we report the third quarter, middle of November, that will all be cleared up. And there are some other ways to deal with that -- those things. I mean there's waivers from the banks. There's change in numbers. There's higher production levels. There's all sorts of things. So we're looking at all those options. But obviously, with the issue we had with the default of the one equity holder, we had to fill that gap as quickly as we could to get back in the field, and that's what we did last week. How will you fund the $6 million required for the compressor? That's out of the capital. So that's in there. That's right in the numbers. That's in the forecast that you saw earlier. I think about $2.6 million of it gets paid this year. That's the deposit and everything else for them to do the unit. It's got some recylindering” on it. It's a 3-stage unit. We only need a 2-stage -- they're going to have changed out. So about $2.6 million of that $6 million is this year and then the rest will be in Q1 of next year. But that's based into the capital program. And to give you an idea, this compressor will basically add another well at -- it would be like adding another well at Cascadura. So -- but very low risk, right? Like it's not like drilling a well where things can go wrong, like the compressor will basically add it, but it adds another well for the next 15 years. So it's what I would refer to as a no-brainer to get us done and pretty happy that the team here was able to uncover a new unit in Houston. The lead times on compressors right now with everything going on in the world is 34 to 36 weeks. And obviously, we think we can do it here over the next 6 months. So really happy with what the team has put together there. You mentioned LNG price of $8, $9, $10 before. But after the cost, it's much lower, what's realistic? The LNG prices of $8, $9 and $10, that LNG pricing is actually higher than that today, if you were to look at the markets. And then you look at the $2 or $3 to back off of that to get what we get paid to run through. But the issue right now is that we're not getting paid pure LNG until March of 2027. Sorry, May of 2027. May of 2027 or when we get above the 22 million a day gas production, which if we're successful in drilling this well that we want to drill, we think it will come on at about 10 million a day at Central Block. That will take us to roughly 27 million, 28 million a day. And then you'll have $6 million of that gas that will be in the pure LNG market, and we'll get a snapshot to see what that looks like. Interestingly enough, the LNG plant went -- one of the trains went down here for 4 days last month. So for 4 days, we actually got a higher price contract. It will be interesting when we actually see what that price is here in Q3, what we actually got paid for those 4 days because that will be pretty reflective of what will get paid under the new contract or when we get over the 22 million a day. So we'll disclose that as soon as we see. But you don't know what that number is until the ship gets loaded and moved and all that. So it's going to take a little bit of time. But don't -- yes, don't abandon and don't think the story has changed as a result of what you saw in Q2. It hasn't changed. Everybody has just got to let us work through Q3 here, a lot of noise in Q2, including that gas price because of the netting off of the propane and butane. So yes, we got $275 for the gas, but then we also got a very large check for the propane and butanes, which when you combine them in the MMBtus, that's really the volume you're selling out of Central Block. So we need to disclose that a little bit better, and we'll put some more words around that going forward. How can you fulfill all your license obligations with our lack of cash flow on all these blocks? Well, the license obligations, the biggest ones are the 6-year ones that we just picked up at Charuma, Cipero and Rio, and we're only in year 1 of those. So I see those coming down the road without any trouble. And as far as on the licensing of the oil blocks, as you can see, we basically sold 60 barrels a day of production. We're going to get 3 wells drilled for us, and those wells should do 50 barrels a day to 100 barrels a day each. So that's -- I'd love to do those deals all day long if we could. So that's how we'll meet some of the obligations. And the deeper play, the Cretaceous play, although it's not really obligations, we do have some wells we want to drill in there. That's an obvious one where I think you might want to bring in a partner, and we'll look at putting a package together and see if there's some interest maybe on those Cretaceous plays and accelerate that drilling program on the Cretaceous, especially now that Exxon has moved into the country, I think it talks a little bit about a lot more eyes you're going to be on that opportunity. Next question, I think I've answered is what price are we getting from Central Block? Can you give us an exact figure? The answer is no, I can't give you an exact figure because I don't know until we see the sheets from Shell. So Shell Marketing buys the gas from us, they organize where they're going to sell it to. They put it into the market. And then when they sell it, we get paid. So that is going to go up and down based on the pricing. It's going to go up and down based on Henry Hub price. There's a small component in there that's also Brent oil price. So there's sort of 4 factors that move that price around. So no, I can't give you an exact price. But as we move to that May 2027 date, you get a lot more weighting into the LNG. So it will become more of a pure LNG price. When will the Cascadura contract be renegotiated? And how many wells do you expect to see on CAS in the next 3 years? I really like these questions that are starting to look out a little bit longer because I think that's important as we enter this -- finish this building plants and now moving into the production stage. I think it's exactly the right way to start looking at this asset base. The contract itself gets renegotiated in October of 2027 and go from there. However, there is a huge demand on the island for gas right now. They're short gas. So we are having discussions with them on that and seeing if they were to pay us more, we could drill more wells, they get more volume. That's the discussion that we're having right now. So there's kind of a side discussion with the official date is October of 2027. And when you look at CAS over the next 3 years, we actually see probably in the order of including this year. So if you take this as year 1, there'll be 2 wells drilled. And then we could see 4 wells drilled next year and 4 wells drilled the following year. So you basically have 10 wells in there. Two of them would probably be in that Central Block in the -- sorry, not Central Block in the B block of the Cascadura pool, which is kind of where these 2 are being drilled. And then what we've seen on the 3D now that we've reprocessed it and also what we've been able to learn from Central Block is there's likely going to be 2 wells to the west of the plant, which would be sort of a new area for us. But on the 3D, it looks like the obvious place to drill a couple of development wells. So as we drill more here, we'll fill in the blocks. But there's lots of room to drill 10 to 12 wells in here, especially when you look at the geophysics. So it will just be a matter of how we want to roll out the gas volumes. And ideally, what we'd like to do, the compressor is going to be good for about 60 million cubic feet a day at that 300 pounds. So really, what you do is you'll have this baseload of 60 million cubic feet a day. And then as you bring on new wells, they'll go around the compressor and then drop down and then they'll come into the compressor. So that's -- when I talk about it being more predictable, that would be the way you'd want to run this going forward. How is CAS-3 producing ATM? I think that maybe means at this time. But it's just flowing right now because we're waiting for the pump on that one. So it's -- I think the volume is 20, 25 barrels a day of oil. It's just flowing up 3.5-inch tubing on its own every day. So it's not really doing anything. The pump and the variable drive for the top of the pump because the pump was running too fast when we ran it last time. So we have to actually slow it down a little bit. So we're going to slow it down. But that process, I think, is going this week or next week, the service rig is going back on. So we should see some results of that again in Q3, Q4 as we go forward. But basically, it's been 0 operating costs on it. And if you saw an operating cost spike in Q2, that was because of all the costs around the Cascadura-3 running in the tubing, running the pump doing all of that. We put that through as an operating cost. So I'm really interested to see what that little well will do. I think it's pretty remarkable that it's still flowing up 3.5-inch tubing and still giving us oil. Like it's just -- you can't kill that well. So it will be really interesting to see that on pump. What percentage uplift, if any, would we see in the compressor online for CAS with consistent volumes. Two different questions there. One would be the first uptick, and we actually see about a 5 million a day uptick when we see it. But what it's going to do is it's going to -- you're going to see a 5 million a day volume uptick, but then you're going to see stability of everything else that's going on, right? So you get this -- you'll get a flat production. So instead of seeing the production going up and down, you basically be at the top number because that's the, let's say, mine pressure 650, you're now going to go to 300 psi. So it will be that number plus about 5 million a day, and that's the original -- that's what the model is kicking out right now in what we see. So if you do the numbers on that, roughly what we're getting paid at Cascadura, it's about a 1-year payout just on the incremental volumes, but you also have to think about the volumes we lose every day that we get high pressures. So it's a very, very economic project. And as I say, it will run for the next 15 years. Is the government willing to increase gas price for us earlier if we can commit to accelerated drilling. That's exactly the conversation that we're having with them. And I think it's -- we're going to find out how interested they are. The Trinidad government goes under a huge change every time a government changes, like all the Board members step off. So the national gas company, all the Board members step off. So you get a new Chairman, you get all these new Board members. And I think in fairness, they're a little reluctant to do anything really dramatic right off the get-go. They kind of want to figure out what's going on. So we know some people on the Board, and we're obviously having those discussions. But their first meeting is going to be an orientation meeting, which they had, and now they're going to start to look at things. So I think there's an opportunity there, but no guarantees on that for sure in what we see. The VAT, there's a question here says, why is the -- if they're so keen, why don't they give us a quicker VAT refunds? I totally agree. We just made a submission to the new Finance Minister. He had asked us to put a new submission and top of the list for us is get the VAT refunds in. We got roughly USD 3 million of VAT bonds. Those we're going to be able to sell. So we'll get those. But those have been 18 months waiting to get the cash for that. He surprised me a little bit in that he says he hates VAT. The problem is the collecting on the other side, so they get enough collection on the other side to pay the people that they need to pay refunds to. And -- the one couple of suggestions that came out of that meeting would be a 0 VAT for our industry. So we wouldn't -- we'd never be in sort of having to be repaid back. I think he found that interesting. The other one would be a net VAT, so you'd only pay the net amount of what you owed or what you received every month. And then the third component, which I think makes the most sense would be just offset your VAT against any other taxes that you owe, whether that's SPT or PPT. It's all the big same pool, and that would help. Right now, we have roughly -- we had about $7 million or $8 million of VAT refunds when you look at that Q2, if you include the VAT bonds. And that in itself is virtually 2 wells sent to us. So that was the example I used for the minister is how we could accelerate that. And very, very receptive asked us to put in a formal submission, which we did. And so we'll see where that goes. Budgets come out in October, September -- late September, early October in Trinidad. So -- and we've got another meeting scheduled, Scott and I are down, I think, first week of September. How deep will CB wells be when they're drilled? They're about 7,000 feet. We spent about $0.5 million redoing the 3D seismic at Central Block. And I got to tell you, there's some really exciting things, Gavin and the team, along with James. We think there's some really great development wells. We think there's a couple of sheets in here that aren't being properly drained. And if you looked at our Cascadura Deep and ST1 when we did that reperforation, we saw some pretty big rates coming out of there initially. There is a lot to do at Central Block. So pretty excited about that. So 7,000 feet. So if you think about that, that's really no different than what we've -- than what we're drilling at Cascadura. So we should be able to do them for about the same. One of the challenges is you're going to have zones that are depleted at Central Block and then hopefully some higher pressured zones. So there's going to be a little bit of engineering to work through those zones, but I think we've got the right team on that. Is there any scope for decommissioning cost per barrel for CB to be reduced in light of likely decommissioning date in 2040 being extended, how can we negotiate this? I don't really think we can negotiate it. This is somebody obviously pretty knowledgeable what's going on. There's a fee that we pay on every barrel for decommissioning, and that gets put into a fund. I actually think it's a great way to do it. It's a small amount. I think it's about $0.25 that goes in there, and then you have this fund at the end to take it away. And from an accounting point of view, I think it kind of -- it correctly reflects the liability that you inherently have when you acquire these assets. I mean there is an abandonment liability down the road. But if you've got money sitting in a government account that you can access, I think it's the right way to do it. So you don't end up with a bunch of abandoned orphan facilities at the end of the day. So that's -- I think that's the last question.