Touchstone Exploration (TSX:TXP) — Retail Investor Presentation

0:00 Good afternoon, ladies and gentlemen. Welcome to the TOUCHSTONE Investor Presentation. Throughout today's recorded meeting, attendees will be in listen only mode. Questions are encouraged. They can be submitted at any time just using the Q and A tab situated on the right hand corner of your screen. Please simply type in your questions at any time and press send. Before Before we begin, we'd like to submit the following poll, and I'm sure the company will be most grateful for your participation. I'd now like to hand over to the management team, Paul. Brian, good afternoon. Thanks very much. Appreciate the time and appreciate everybody tuning in today for our update. Look forward to giving you a good look back at the first half of the year as well as look forward to what we see in the latter half of 2026 and into 2027. So let me start out. First of all, it'll be myself and Brian Hollingshead, our executive VP of engineering and business development. We'll sort of split it up a little bit. And as the questions come in here, we'll also look at, getting the appropriate folks to answer those as we go.

0:54 Let me start out first of all and just take a really quick look back at the first half of twenty twenty six. For those that have been following the story for quite a long time, we definitely saw a change in the first half of of this year and really the results of some of the, decisions that we made in the last year. But what you start to see now is some strong cash flow. You know, in the first half of the year, we had almost 30,000,000 in petroleum and natural gas sales, about 69% of the natural gas weighting with some of those volumes going to the higher LNG market. And Brian will get into that a little bit more as he gets into some of the more detailed slides. We've seen the margin expand. So one of the other things we really focused on here is bringing down the operating costs, bringing down all of the costs and everything that we've looked at, and we're starting to see the benefit of that. We have about $9,000,000 in funds flow from operations, and I'll look a little deeper into that in the next slide here when we look at the second quarter as a stand alone. But you can really see a lot of that was driven by the higher gas sales, And a majority of that 9,000,000 was really in the second quarter.

1:55 About 4,500 BOEs a day, that production certainly flattened out quite a bit when you look at the last few months, and it'll start to increase as we bring on some new production through the Cascadura facility and some other things in the second half of the year. So one of the things that we wanted to look at doing was bring on that compressor that I talked about to increase production in the in the second half of twenty twenty six. But what we also did in, you know, the first half of this year was really, you know, really some key things. As I mentioned, the Cascadero facility, drilling the first well in seventeen or eighteen years at Carappel, and Brian will talk a little bit more about that and what our our plans are for that well. We then had two wells that we drilled in W D 8, and the business and development group sold a small asset last year, about 40 barrels a day, and we got three wells drilled, two that got drilled in the first half of the year and one that'll get drilled in the second half of the year. Basically, we drilled them for free.

2:52 So it was a really nice uptick, and those wells are doing north of a 100 barrels a day. So, you know, when you look at the economics of that swap, it certainly was very positive. And then we wanna continue to optimize, and we'll talk about the BRE and the Cascadura two wells and picking up some of those declines and some of the the what I'll call the low hanging fruit that we're looking at taking care of, and we'll look at some of those results. On the financial side, that's probably been the biggest focus for us. We, you know, we did a an equity raise about 10,200,000 in the first half of the year. We continued a little bit further as we went forward into the year in the annual meeting that we had. We also were able to convert the the debenture that we had into equity so that further reduced the the debt in July 2026.

3:38 The one challenge for us still is that VAT refund still sits at about $11,100,000. I know there's a a question that's already been submitted on that, so I'll probably go into a little bit more detail as we look at that. But but that kinda shows you the first half of the year of 2026. What I'd like to do though is talk a little bit about q two because it's really the first time we get a real snapshot of what 2027 looks like with the higher prices and lower operating costs. So you look at the natural gas sales of just over $17,000,000, up about 40% from q one, and it's a combination of two things. One was the higher prices as a result of us switching into the higher LNG contract, but also because of obviously the Middle Eastern war, which has inflated prices up. But the operating netbacks up almost 77% to just under $25.

4:28 Again, that's a result of the higher pricing, but also our lower expenses as we go. Funds flow from operations is seven point just over 7,000,000. So of that 9,000,000 in the first half, 7,000,000 of it came in this particular quarter. So it really, again, gives you that idea of of what you see as we get to these higher prices, higher volumes, lower expenses. And it also falls through to the earnings line. You know, we went from a loss of about $2,400,000 to almost $2,300,000 in positive income in the second half. The big change here was the LNG. We were able to sell some of our product to what we call train two three LNG prices. It's the first time we've ever seen the real benefit of the central black gas going to higher price. You can see we got just under $10 in MCF for those for that volume less the fees. So, again, gives you that little glimpse into what 2027 will look like as we switch into that contract on a full time basis.

5:27 Gave us higher gas prices, obviously, quarter over quarter. You can see the central block gas price was, you know, up 93% from q one. And, also, operating costs were down at central block, so it's really turned into a a great asset. I think everybody's starting to understand why we we worked as hard as we did to get that one done. Crude oil numbers are up and even up. You know, you look at it today, obviously, significantly higher than what we saw in q two. We look at the operating costs. We're we're we're doing a little analysis on this, but I think what you'll see going forward is starting to compare ourselves to the peer group. And when we look at that, you know, we're we're gonna be one of the lowest in the peer group as our operating costs as we go forward. And I think, you know, you'll see that probably the average is 14 or $15. So we're almost half of that average, which is, you know, should talk to the efficiency and the hard work that the team's done on that.

6:17 Capital expenditures were 1,500,000. So, you know, you look at 1,500,000 in capital expenditures, you look at 7 point just over 7,000,000 of funds flow, you're actually seeing free funds flow in that quarter that that we mainly use to pay down debt as we went forward. So really strong q two, and I, again, I think it's that little glimpse of what 2027 can look like. So what are we looking at as we go forward? You know, we've got bunch of development locations. We've got the exploration blocks in place. We now have this strategic market access as we refer to it here. So not only do we have a fixed price contract that's very predictable, we'll talk about the renegotiation on that in 2027, but we've also got access to access to the LNG markets as well as our condensate and our gas prices are all subject to these much higher Brent prices.

7:08 On the government relations side, I would say that the new government that's come in obviously has set up a very strong desire to increase production both in oil and gas and have been very helpful for us in what we've seen there. Establishment of the partners, you know, Heritage, we talked about it in our release on Monday, has worked along with us to reallocate how we sell the sorry, the oil at Central Block. So we're getting a much higher price for that that oil going forward. So I think our partnerships are are certainly working well together, and and everybody's aligned in what we're doing. On the community support side, we're very active in the in the Trinidadian environment to make things work. And I I think, again, that that consistent support we've shown in the community has given us that social license to keep doing what we're done.

7:56 As far as the jurisdiction goes, I I think we're again seeing that, you know, it's over a hundred years that oil and gas has been in Trinidad. So they want us to be there, we wanna be there. So it works out well. This is a map that everybody's seen, but I I think the only real takeaway for us is that we've we've now got 75,000 BOEs a day of capacity. And as I pointed out a little bit earlier, current production being around that 5,000 range, we've got, you know, way more capacity than we have the ability to you know, we don't need to build anything new. Any new hydrocarbon we bring on oil or gas will go into our existing facilities and go to all these different markets that we see. So it's a bit of a unique opportunity, I think, when you look at it internationally around the world.

8:42 I'm gonna turn it over to Brian, and he can walk you through some of the operational update and the work program. Thanks, Paul. So this first slide, think, it's really impactful. It it speaks to why we did the Shell deal. You know, with the Central Block acquisition, we got a gas plant, a producing field. We also got two critical LNG contracts, which, marries nice with our fixed contract at Artoire. You can see on the slide there, we've we've put all three up. We'll start at the the bottom. So that's the Artoire fixed price. It's about $2.33 in MMBtu. It's up for renegotiation next year, October, and we're already starting those discussions. It is notable. It is the lowest gas price we can tell, you know, onshore domestically, so we'll look for that to go up. The next curve up is the train four contract. So that's the train we sell to currently until May 2027. Past May 2027, that contract actually expires, and the higher price contract, it's called train two three there, That one will kick in for all of the central block production.

9:44 You can see with the crisis in The Middle East, we've seen prices really ramp up lately. I think it's even higher today when I look. So that bodes well, and we've seen that pricing start to reflect in our quarterlies. You can see from 2025 to q one to q two twenty twenty six, we've started to see the impact of those those sales to LNG. In June, July so part of the train four contract is if there's maintenance on that train that we get to divert temporarily to the higher price contract. And we actually did that in June and July. And like Paul said, we got a glimpse at what pricing looks like on that train, and prices were about 10 to $11 after fees. So that that's an all in price after fees that we get on that LNG. Yeah. I think the only thing you mentioned on that is we also get, you know, three streams out of central block.

10:29 We get the condensate that gets knocked out of the plant, which is basically Brent less about 15% now. And then we also get the NGLs that get knocked out at At Atlantic. At Atlantic. So sort of these three phases that that we get, which is really great. So, you know, looking at our production production wedges and where they go, this is production since 2025. It's been relatively stable following the Central Block acquisition and the compression at Cascadero, which I'll speak to. But, I mean, looking at our our asset classes and where they go, our our Brent oil, or our oil production at the bottom is about a thousand to 1,100 barrels a day, pretty consistent low decline production. We sell that at Brent less 15% as Paul Paul spoke to there. The central block production, which is yellow, so that goes pure LNG.

11:15 That goes to train four or train two, three as the case may be. And and after May 2027, that'll all go to that higher price contract. The little dips you're seeing in there, that's just planned maintenance at the plant. So we we routinely, every six months, do some maintenance on the compressors. The red line, that's Cascadura. So, obviously, central block has compression, and you can see how stable and flat it is. Cascadura did not until July. So we had that installed in July, and we've seen improving run times on the unit the last few months from about 54% to 70%. And September so far, we've been over 90%. We'll look for production on that wedge to really stabilize here go forward with corporate production in and around 5,000. K. Looking at the capital program. So in the first half, we we had a busy first half. We brought c r three online at Central Block, like Paul said, our first well in roughly fifteen, seventeen years.

12:10 We drilled two wells on our oil blocks on W D 8. It's notable those were actually paid for. The drilling costs were paid for by, the Turn Creek contractor because we sold them the FISOBAD block. So we're we're looking to add production without spending much money. That was the goal this year. In June, we installed we actually shipped, installed, commissioned the Cascadero booster compressor, and that was that was a big project for TOUCHSTONE and the country. This is a big unit. It was disassembled. It was shipped to port and then to site and put back together. And then we had that Baraka East Street completion, which, we went for some bypass pay that BG, the previous operator, had not perforated, and we saw a good result. We took that well from about point 3,000,000 cubic feet per day to over two plus increased liquids, which actually blended the gravity down of the total central block condensate, and that resulted in improved price contract where we're getting about the Brent less 15% on that stream as well. So kind of a double benefit on that on that job.

13:09 By our math, it paid out in about ten days with these high LNG prices, so really solid. Looking to the second half, we're gonna continue with our recompletion work program across Central And Artoir, looking for low cost optimizations that we can do in the field. We're also gonna drill two w d four wells. The rig is on-site. It's probably gonna spud this weekend, early next week. One of those wells is also paid for by the turnkey contractor similar to the W D 8 wells. Looking forward to 2027, the key here is gonna be accessing those higher priced contracts. May, we have the higher priced LNG. October, we're looking for the increased domestic price. So we're gonna really tailor our work program to hit those price ramps as they come in in 2027. Thanks, Brian.

13:58 So let me just kinda walk you through, and then we'll open it up to a bunch of questions that we see here. But I think the key takeaways now are we've got all this capacity in place, oil and gas, whether it's our Coho facility, Central Block, Cascadura, or W D 8, W D 4, C 01, you know, even you know, we've got disposal well. We've got all of those things in place now, to keep the costs down, but also just bring revenue up. So we're gonna really have compressed that time frame of when we can drill wells and bring them on stream. As far as the drilling inventory goes, you know, one of the nice things that sort of having been a little bit of a slow period here while we got things sorted, we've built a great inventory of development locations. We've got locations that we'll talk about at Central Block. I know there's some questions on that.

14:46 We've got development wells at Cascadura, and then we've got the oil development wells. But as Brian pointed out, the key here is what we wanna do is time these wells so that they come on stream into the higher price contracts. So, basically, between now and q one of next year, the focus will be on central block. Q two, q three of next year will be on the Cascadero facilities. And then in the background of all of that, we'll continue to to optimize and drill up the oil wells as we go along. On the exploration side, you know, one of the one of the questions is when do we get around to that? And I think that is it it it really is gonna be determined on two things. One is how strong these prices stay for how long, and two, the VAT refunds. And I know there's a question on that in what we look at here. So I'll wait and answer that as as part of that question.

15:34 The other thing that we have is a huge inventory of land, which I really you know, I call it the opportunity for us. We've got a 137,000 net exploration acres, and we've got some great projects. But even success on those exploration acres, we don't need to build new gas plants. All we will need to do is pipeline to one of our existing facilities. So, you know, it it it changes everything on the island for us. And then the premium pricing upside. Two contracts, as Brian pointed out, the central block one that happens in May, the Orotois one, which we'll we'll start having discussions right away here with NGC, but it would come into place. I think it's on the, like, ninth or tenth of October of Yeah. Of 2027, something around there. It'd be five years to the date of when we started to flow gas actually out of the Coho facility.

16:20 So it just there's a price renegotiation every five years. So that's what that's around. But I I I hope the big takeaway today is, especially that chart Brian showed, is those higher prices that we see when we flip into those contracts as we go forward. So what do we you know, what's the investment case? Definitely top of the list is that gas price upside that we see, the production growth without having to add any more facilities. You know, we've got this this inventory of deeper wells as well as the exploration acreage plus the development wells. We've got all the owned and operated infrastructure. And I think, you know, we talk about it being owned, but I think it's also key that we operate it all. You know, we can move some folks around. We can lower the operating costs. It's really, really important to us. The deleveraging, you know, Scott and and the team have really been focusing on making sure that whether it was the equity financing we've done or the free cash flow from q two, then what we're really doing is focusing on deleveraging and cleaning up the balance sheet. So where's the value opportunity here?

17:21 You know, it's it's pretty simple. Think when you look at how badly the stock has been, you know, depressed as a result of a number of things, maybe not going exactly the way we had wanted them to. The opportunity now is to come out of that with this base that we've built of the assets, whether they be the land, whether it be the drilling inventory, whether it be the plants, all the way through to the gas marketing that we have. And then on top of that, in a country that wants us to be there and really needs the gas, it, you know, it kinda goes all the way down. On the ESG side, we continue to focus on that. You know, the number one thing for us is obviously safety. And I think when you look at our reputation in the community down there, I think we've got a pretty high profile. So it you know, it's worked out really well. So that is the summary of the presentation. And what I would suggest we do now is we'll we'll flip to the pad here, and I'll take a look at some of the questions, and then we'll go from there. The first question that we have is, what is your thinking regarding potential to pay a dividend in the future?

18:21 I mean, ideally, yes, we'd love to pay a dividend in the future, but, you know, let's deal with the elephant in the room here. We gotta clean up the balance sheet first. So free cash flow here will be to clean up the balance sheet before we even look at any of those kind of things. And, you know, the the when I say the cleaning up of the balance sheet, what we're looking to do is try to get to one to one and a half times debt to cash flow. And with the kind of prices that we're now seeing and if you look at the numbers in in q q two alone, we're not very far from that. So I think, you know, the team's certainly working towards that for sure. So question here about, is your attendance at the Venezuela Summit primarily relationship building, or is TXP actively evaluating specific, commercial opportunities in Venezuela? I'm always amazed that people know my travel schedule, but it is a it is a great maybe makes me a little uncomfortable. But, no, I sit on the board of the energy chamber in Trinidad, and I have for a while. I think it's given us good visibility in Trinidad.

19:18 And part of this Venezuela conference, I'm really just wearing a hat from the energy chamber in in Trinidad to go down there. I mean, it's gonna be interest it's gonna be fascinating to see what's going on down there. But when you when you sit through the presentation that we just presented to you, think it becomes very clear. We have more than enough things to do in Trinidad. And when you look at the contracts, you look at the land position we have, the underutilized facilities, you know, that's where our focus is right now. Next question. Can you clarify when the current gas sales arrangements next become eligible for renegotiation or repricing? And whether you believe the prices TXP currently receives adequately reflect today's much tighter Trinidad gas market? I'm gonna turn that over to Brian, if you would wanna take that. Yep. Sure, Paul.

20:03 I think I think we touched on that in the presentation. So LNG is is May 2027. That's when the contract flips over. You know, we have heard from Atlantic LNG that in March, they might do some train for maintenance. So there's an opportunity potentially there for us to flip to the higher price in March instead of May, but we'll with May for the contract. The the domestic is October, as I said. And and, yes, we agree. We think it is quite low, when you look at publicly traded companies and what their selling prices are domestically in Trinidad. So I think that that gives us some leverage when we go into negotiations to look for for a higher domestic price, either fixed or potentially linked to to petrochemicals downstream. We'll see how that negotiation goes.

20:49 Yeah. I think if we the only example that we can really look at is the EOG team. They, they went in to renegotiate with NGC, they got it nine month done it about nine months before the renegotiation time. So, you know, we'll start to have those those conversations certainly as we go. But the other part of that question was is, you know, where are we in gas pricing versus the rest of the world? And I think the real unique thing that we're we're trying to get across is that TOUCHSTONE is probably one of the only producers that actually gets paid LNG price. Like, we're not getting the gas bought by Shell and then pushed through a facility. We're actually getting the LNG price. So it is pretty reflective of the worldwide price when we look at it. When should we expect TOUCHSTONE to go into positive free FCF or free cash flow after heavy investment period? Last quarter of this year likely?

21:39 You know, I again, as I point out, like, even in q two, we were already there. Now we are gonna ramp up some of those some of those expenditures as we go, but but you can see I think what you're gonna see is quarter by quarter depending on what we wanna do and and the debt repayments. Like, I you know, mid next year, we've paid off the first of the two term loans with RBL. So, you know, you start to free up a bunch of cash to do other things. But, again, my best to answer that question is we basically were in q two. Next question is, when do you expect tax free from government? Why are they delaying the refunds? Second part of the question, I know I think the reason they're delaying the refunds is because they're just using that finance government operations.

22:28 When do we expect the refunds? We really have no idea, and I don't think Scott or the finance team with KL have are even suggesting that they're gonna get those back. However, they usually deal with them in the October budget. And so in October, we'll wait and see what comes down in the Trinidad budget. We may get some more clarity. It's usually around the third week of October. So stand by that and see. It would be be great if we got some positive news out of that. And, you know, there's been discussion maybe that they'll do it as an offset to royalties or taxes or could issue some more bonds. Either way, I don't think we care. We just would love to get our hands on that so we can go forward. Is the Braca Well still planned? And if so, when do you expect to spud it? So the Braca Well is another one of the central block wells. And in our discussions with our joint venture partner, Heritage, they had some seismic data that had been reprocessed but not interpreted.

23:20 So we they shared that with us, and we're actually looking at it right now. So that that well's been delayed a little bit only from the point of view. We wanna make sure that with this new data that we've got it in the right place. But, I mean, you've got the pad done, it's ready to go. The pad's ready. We we'd need a month to get the rig going. So when it's time, we'll we'll move it. Yeah. Yeah. What do you think is holding back the share price? I I think there's a bit of credibility. You know, I think from from our point of view, you know, last year, a lot of the wells went way over budget, and the production didn't come in where we wanted to. So this given us an opportunity to retool that a little bit. And I think when we start to see some of the results, I think the the solvent soak, you you you look at that, you look at what we were able to do with BRE with the recompletion.

24:10 And maybe you can just talk for a minute about what we're looking at doing at C R 3 on the Karamat Sands because that would be another one. Yeah. So we're we're looking in October. We're gonna send the service rig out, and we're gonna try and perforate the the Karamat sands. It's about 80 odd feet sitting just above the Herrera sandstone. Know, drilling through it on C R 3, it it had really strong gas shows of up to about 30. On logs, it looks really good. We needed, you know, pretty high mud weight to control it. So what we're looking there is to to, know, temporarily plug off the Herrera and then perforate the Caromat. Likely have higher pressure, so we'll be flowing that to the plant. And the nice thing is it's it's already tied in right after the perforation. It'll be on stream to sales.

24:58 Yeah. I think, yeah, there's a couple of questions in here. One of them was was there, MPD, which I'm guessing is, MPD used at c r three while we were drilling. So that would be the pressure drilling. Managed pressure drilling. Yep. And we did do that. Yep. But even with the managed pressure drilling, it looks like the reservoir was depleted. And with the the product that we had, we probably damaged it up pretty good. Correct. And one of the other challenges, we had the high pressure care mat sitting above the low pressure. So you're trying to control the high pressure zone while you drone through the low pressure. So one of the things we've been able to do is kinda step away, look at well design, look at rig design, look at the mud properties, look at everything that we've done. And and as we go forward at at Central Block and at Cascadura, I think we can use a bunch of that.

25:49 The last five CASCB wells had a significant problems that the question is here that have ruined them. Have those problems been identified and what action is being taken to prevent the same problems occurring again? We we are looking at all of that. I think it is very tricky, then, you know, Brian, you can jump in here. But drilling through these over pressured and under pressured zones, it's just a challenge. So, you know, we're as I say, we're stepping back. We're taking a look at it, but there are a few things we're looking at for sure. Yeah. We I mean, at at CAS two, we had that positive solvent squeeze. I think there was a question on that. Know, we wanted to try that that chemical on our low our lower rate producers just as a as a test. It it's, it reduces condensate banking. So you get condensate banking against the sand face, and this chemical breaks that down, allowing allowing the well to flow.

26:40 So we saw about a 50% uplift in the production out of that well over the last few weeks after doing it. Now it it was producing around one and a half, 1,400,000 a day, we've got it up into the twos. But what we really wanted to see there was magnitude of increase, And now we plan to deploy this on some other cascadero wells as well, and it's it's relatively cheap chemical to use. Yeah. Next question is the $10,200,000 fundraising strength in liquidity became through shareholder dilution despite the net debt only fell 6%. I I think you're correct. It only fell 6% in the quarter, but don't forget the at the June meeting, what ended up happening sorry. The July meeting, ended up happening was there was an $8,000,000 bond that came as part of that, but then also converted to equity. So you that 8,000,000 also reduced debt in q three. So you'll see that big change in the in the balance sheet in q three. So I know that was a bit of a a tricky financing the way we did it, but it was because we needed shareholder approval to issue the full amount of equity. And so it looked as 8,000,000 of that 10,000,000 still sat as debt on the balance sheet at the end of the quarter, and then it flips over in q three. So you'll really see the benefit of that in q three. It's it's a good question, and it was complicated the way we had to do that, but it was the way we had to get it done.

28:09 Total production sales BOE per day, concerned that the short term and medium term, where in all is the significant increase gonna come from? Well, one of the big increases will come from Cascadura as we get that production leveled out. I mean, it it was really bouncing around from, you know, a couple million a day depending on where it was to, you know, maximum rates were probably 8 or 9,000,000 a day. So we're definitely gonna see those go up. At central block, we've got the Keramat projects that we're working on as well as, you know, additional drilling there. And then as we move into q two and q three of next year, we start to see development drilling at at Cascadura. So, you you know, the real focus here was to get everything integrated, get it done, especially get that compressor in. And now what you'll start to do is see the the volumes ramp up as we bring on these new wells.

28:57 So, again, a a good question. Do we have faith in drilling any more new wells in Central Block? Yeah. The only thing I think the the the one comment there might be they probably won't be in the carousel for it zone or carousel field. I think what we're seeing with the new data is we're probably more excited with the Bracket East and the bracket field, especially with what you saw in that Brian? Yeah. Positive results out there. The the Carapal Pool is is the largest of the three pools at Central Block. What we're looking at at Baraka and Baraka East is probably more compartmentalization just based on those wells, what they've recovered, and the volumetric, math around it. So we see a lot of potential out of BRAC East and BRACA, you know, given the new seismic data as well. That'll help, as well as recompletions.

29:48 We we're planning another recompletion in Braca East, which we'll look to execute probably later in the year, and then, one at Braca 1 as well. So, you know, it's relatively low cost to go into these old wellbores and look for bypass sands that we can target to increase production. Yeah. The the next question is around the production chart on slide eight appears to project recovery through second half of q two sorry, second half at 2026 and 2027. I'm just wondering about a 7,000 BOE a day year end target. At this point, we're not giving out forecasts, but I think what you'll see is you'll see month when we report the monthlies, you'll start to see a much stabler, month production. And then as we do the care mats, as we do the workovers, you'll just see that volume add up as we as we get closer towards the end of the year. One of the real questions is gonna be, by the time we get all the data interpreted, go back to our partner heritage at Central Block, whether or not the Barracka well gets drilled this year, the first quarter of next year. But, again, the timing will be to have it come on as we go into that higher gas price contract next March or May depending on when the Yeah. When the turnaround is.

31:04 We talked about next questions around the the exploration land and the disappointment in the drilling of the wells. Yeah. I think, you know, that's it it there's sort of a trend through here, and I I hope what you're gonna see is that as we we've taken a step back here, we've looked at everything from the drilling rig to drilling muds to everything. And, you know, we've gotta get costs down. We've gotta get the better predictability of the rates on the wells. And the only way we can actually prove that is by doing the next one. So gotta give us some time to get that done. The next question was around the CT intervention. I think we talked about that, Brian. At c r three. Yeah. Yep.

31:52 I don't think there's much more to to talk about there. And, you know, I think when we get the results out of the care map, we'll definitely take a look at that. One of the questions here is around the the going concern note. Yeah. There were still a going concern note in there at the end of q two, and I I should have mentioned that in the presentation. I think with what we see, again, with the conversion of that $8,000,000,000 from debt to equity, if anything happens on the certainly happens on the VAT, but the other thing too is these stronger prices. So right now, we anticipate that going away at the end of q three depending of, you know, how everything looks right now. But that's just one of those things that that that's there, and we've obviously been keeping everybody informed and filling them in on that.

32:42 Question around two three and the negotiations on train two three. Maybe you can just explain, Brian, that there isn't actually a negotiation. It's just the contract flips. Yep. Yeah. So, as I mentioned, you know, purchasing Central Block, we we acquired two active LNG contracts. One is train four, one is train two three. And, you know, if you think there is a lot of embedded value in these contracts in place right now. So what happens in May 2027, the that train four contract just expires. That's the end of its term. The the train two three contract contract is active right now, and it essentially just takes over, CentroBlox gas flows to sell under that contract because the train four contracts has expired. So there's there's no negotiations. There's no paperwork to sign.

33:29 It's just a contract already in place. Yeah. Really not a question was, is there a renegotiation? The answer is really no. What are the plans to drill drilling their Cretaceous targets? The we did go out on a proposal for that. We still are negotiating with one party on that. So I'd rather kinda leave that question on the Cretaceous until we conclude those negotiations one way or the other, but they haven't gone away. I think the other encouraging thing is Exxon's out shooting a bunch of seismic for Cretaceous targets, albeit in the deep water out in Trinidad, but they're obviously moved into Trinidad. So we've we've definitely seen that. And they've also bought in a couple of interesting international partners. Oxy has come in with them and a few others. So I think this whole Cretaceous play is is moving its way geologically into into the Trinidad area for sure.

34:26 What is the possibility of building a pipeline from Cascadero facility to Central Black Evergreen's facility, possible logistical problems and costs? You know, that's a really interesting question because I think we were even talking about this yesterday. If when you when you made the Cascadero when we made the Cascadero discovery, if we had our own central block, you would have just pipelined it there. You probably would have never built a plant at Cascadero. We talked to Shell at the time, but they weren't interested in taking it. So the that's really not a great option because of all the capital that we've sunk in the cash, you'd have to build another long pipeline down there. Instead, now that we've got the compressor in Cascadero, you've really got these these two facilities that you can have a real good longevity on the on the lands. We go I mean, we're running them down to 300 PSI on the inlet, but the ultimate final stage of this is you go to 50 pounds on the inlet.

35:19 You you lower the capacity at the plants, but you get a lot longer run life out of the wells. So there's there's lots to do on that. I'd love to be able to turn the clock back, but, unfortunately, we can't on that. But I think, know, these two facilities, the compressor now at CAS is rated for probably about 60,000,000 cubic feet a day. Yep. And when we look around at not only the development stuff that we have, but also the exploration around there, there's lots of things to do. One of the questions was, has this sort of changed from an expansion on the a growth expansion from an exploration story to a development story? I think when you look at the land base that's there, you can still see we've got huge exploration opportunities. In a perfect world, what we'd like to get to, let's call it, in 2027, 2028, would be 80% of our capital spent on development and 20% spent on the exploration.

36:09 And really what that means is you'd be drilling a couple of exploratory wells every year. And but what we really need to do before we do that is get the drilling costs under control, make sure we can drill these wells, and make sure that we've got all the data in place. So that's kind of the the bit of the balance for us. But definitely, exploration is gonna play a key role in going forward. The other thing we'd really you know, that we wanna do, and it it gets back to the question about raising equity or not, is you really wanna fund those exploration wells out of free cash flow. And so as our cash flow builds up here, that'll give us the ability to fund them and, you know, not have to go to the market to do that. I think it's important to note too. Cascadero 1 was an exploration well, and it stimulated a new field, new development, a new plant. And similarly for Carrappell Ridge 1, that was an exploration well back in the day, and it found a lot of gas. So this this portion of exploration is is still needed in the business, on top of, obviously, development.

37:06 Yeah. Ben's got a question here, asking why the change in mind drilling at Baraka, the plan now, and not Carrappell, if Carrappell's largest pool. I I think part of the reason is we've got two really good wells, potentially three really good wells into into Carrappell with c r three draining the Caramat in there. You got the other two wells that are gonna adequately drill, drain the Herrera. The the the size of the structures at Baraka and Baraka East that we now see with the new three d, the amount of reserves that we could add and wouldn't be booked right now at those two pools would be much higher than what we could add doing development wells at Carapal. So it's just a matter of moving it around. But I I think everybody has to think of Central Block as one big project.

37:54 And, really, what we're gonna do is just move it around based on the cost of capital and where the best returns are. And the best returns, you know, when you look at a project like what these guys did at Baraka East, you know, a ten day payout, add a couple million a day. We just don't have many better projects than that for sure. What is the current domestic pricing for natural gas? Short answer is we don't know. You know, there's pretty strong NDAs between National Gas Company and all the suppliers. The only reason we can talk a little bit about EOG's price is because they have to file it with the SEC, so we see it in a public document. But we don't know what BP's, parenchos, or Shell's prices are. And we don't know on the other side either. We don't know what the petrochemical companies are paying for it. We got a pretty good idea, and we know that we're way below market. We think that number, if you were to ask us today, is probably $4.85 to $6, somewhere in that range. So, you know, if we were making that kind of cash out of Cascadura, the cash flow numbers would look significantly different than you see. So that's why we wanna encourage and try to get these negotiations moving as quickly as we can. But you can also see why we don't wanna drill the wells now.

39:10 We really wanna time those to go into the higher prices in 2027. Seismic was significant improvement in technology. Would it make sense to shoot new seismics on the CV before proceeding with the new well drill? I I don't think so. Because the seismic part of it and working with Gavin in our group and working with Heritage, the the the reprocessing technology, and some of it's AI driven, and some of it's just, you know, new new processing technology, that the data or the noise, as I call it, is good. What we need to do is just reprocess it. So it wouldn't wouldn't be helpful to reshoot it. I don't think there'd be a lot of benefit to that. But the reprocessing for instance, you know, we just spent another $100. I think it was a $100 US with Heritage on on getting that new dataset.

40:04 So and it and it, quite frankly, it is showing us some very interesting things. And if you think about it, it also covers Coho. So you know? And and we always wanna drill a couple more wells at Coho. So it covers central block, which is Carapal, Baraka, Baraka East, and Coho. So, you know, one of the big changes that we're seeing in seismic these days is you used to able to see structures and all those kind of things. With the new processing, they actually think they can see gas, oil, and water. And if that is the case, then, you know, it's quite a game changer for us as we go forward. So part of the reason why we put pump the brakes a little bit here on drilling the next couple of wells because, you know, we got an opportunity to to really rework this data. So that's what we wanna do.

40:50 When does the train two three LNG contract that comes into play in May 2027 end? I think it's about a twenty year contract with extensions and standard language in it. So it's a it's a long term contract. Yep. Yeah. Yeah. You know, it's really you know, I I know we pitched it when we bought the Shell deal that the the main assets we were buying was the plant and the gas field, and then the other asset that we were really buying was the LNG contract. And, you know, the other thing that we have in that deal with Shell is we also have they have the right of first offer on any new gas that we find that isn't contracted. So on all those new blocks, Charuma, Rio, and Sapero, any of that gas that we if we were to find gas on those, they would all go to these higher price contracts.

41:41 So that's why, you know, some of our most economic projects may be and and the one I like the best would be Sapero, for example. Yeah. You know, if we could drill Sapero, we looked at it the other day. It's about 6.7 kilometers pipeline down to the to the plant at Central. You know, those kind of things would be spectacular. And you and you look with Gavin and and Zav and the team, you know, they see that being about the same size as Cascadura. So at some point, you gotta you gotta put some of that risk capital because as you have those discovery wells, as Brian alluded to, you then have a whole series of development wells that come on the backside of that. And that's the stage that we're gonna get to. So that's the last question that I've got. That's I don't think I have anything else to add. I I mean, it's it's great to sit here and give everybody an update.

42:28 You know, q two was a brilliant little glimpse for us at 2027. Our capital plan is really to drill into these higher prices at central block at CAS. And even the the oil wells that we're drilling right now at at W D 4 and W D 8, you know, we'll get advantage of those higher prices. Anything else, Brian? Any other thoughts? No. I think q one and q two was was a really good quarter. It's great to see those high LNG prices. I think when we when we purchased Central Block, Paul, myself, Paul, Scott, the team talked about these contracts and what it could mean for TOUCHSTONE, and it's so nice to see it come in to be, and see see those higher prices. Now we didn't predict the crisis in The Middle East, but, even excluding that, LNG prices were still strong. So we look forward to to the back half, drill a couple of oil wells here next month, and continue our recompletion and workover plan and and plan for 2027.

43:21 Yeah. And I think the other thing too is when we look at these LNG curves, we were just looking at those this morning, you know, the gas market is not nearly as backwardated as the oil market. Right? You know, we're seeing pretty strong LNG prices through till mid next year on the curve. So, you know, there's a little more of a runway even if things were to kind of get all put back together tomorrow in The Middle East. We're still going to see some strong gas prices as we go forward. So so thank you everybody for joining us today. Hopefully, we got through everybody's questions there. And, we appreciate the time, and we look forward to keeping everybody up to date as we move forward on operations. That's great. Paul, Brian, thank you once again for updating investors. If ever please ask investors not to close the sessions, we'll now automatically redirect you so you can provide your feedback in order the company can better understand your views and expectations.

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