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

Good afternoon, ladies and gentlemen. Welcome to the Touchstone investor presentation. [Operator Instructions] 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. We 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 will be myself and Brian Hollingshead, our Executive VP of Engineering and Business Development, and 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. Let me start out, first of all, and just take a really quick look back at the first half of 2026. For those that have been following the story for quite a long time, we definitely saw a change in the first half 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. In the first half of the year, we had almost $30 million in petroleum and natural gas sales, about 69% on 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. One of the other things we've 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 million 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 million was really in the second quarter. About 4,500 BOEs a day. That production has certainly flattened out quite a bit when you look at the last few months and will 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. 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 second half of 2026. But what we also did in the first half of this year was really some key things. As I mentioned, the Cascadura facility, drilling the first well in 17 or 18 years at Carapal and Brian will talk a little bit more about that and what our plans are for that well. We then had 2 wells that we drilled in WD-8 and the business and development group sold a small asset last year, about 40 barrels a day, and we've got 3 wells drilled, 2 that got drilled in the first half of the year and that will get drilled in the second half of the year. Basically, we drilled them for free. So it was a really nice uptick. Those wells are doing north of 100 barrels a day. When you look at the economics of that swap, it certainly was very positive. Then we want to continue to optimize, and we'll talk about the BRE and the Cascadura-2 wells and picking up some of those declines and some of 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 did an equity raise about $10.2 million 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 debenture that we had into equity. That further reduced the debt in July of 2026. The one challenge for us still is that VAT refund still sits at about $11.1 million. I know there's a question that's already been submitted on that. I'll probably go into a little bit more detail as we look at that. But that kind of shows you the first half of the year of 2026. What I'd like to do though is talk a little bit about Q2 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. You look at the natural gas sales of just over $17 million, up about 40% from Q1. It's a combination of 2 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. Again, that's a result of the higher pricing, but also our lower expenses as we go. Funds flow from operations is just over $7 million. So of that $9 million in the first half, $7 million of it came in this particular quarter. It really, again, gives you that idea of what you see as we get to these higher prices, higher volumes, lower expenses. It also falls through to the earnings line. We went from a loss of about $2.4 million to almost $2.3 million 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 2/3 LNG prices. The first time we've ever seen the real benefit of the Central block gas going to a higher price. You can see we've got just under $10 an Mcf for those -- for that volume less the fees. Again, it gives you that little glimpse into what 2027 will look like as we switch into that contract on a full-time basis. Give us higher gas prices, obviously, quarter-over-quarter. You can see the Central block gas price was up 93% from Q1. Also operating costs were down in Central block. It's really turned into a great asset. I think everybody is starting to understand why we worked as hard as we did to get that one done. Crude oil numbers are up and even you look at it today, obviously, significantly higher than what we saw in Q2. We look at the operating costs, 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. When we look at that, we're going to be one of the lowest in the peer group as our operating costs as we go forward. I think you'll see that probably the average is $14 or $15. We're almost half of that average, which is -- should talk to the efficiency and the hard work that the team has done on that. Capital expenditures were $1.5 million. You look at $1.5 million in capital expenditures, you look at $7 -- just over $7 million of funds flow. You're actually seeing free funds flow in that quarter that we mainly used to pay down debt as we went forward. A really strong Q2. Again, I think it's that little glimpse of what 2027 can look like. What are we looking at as we go forward? We've got a bunch of development locations. We've got the exploration blocks in place. We now have the 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 the LNG markets as well as our condensate and our gas prices are all subject to these much higher Brent prices. 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, 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. We're getting a much higher price for that oil going forward. I think our partnerships are certainly working well together and everybody is aligned in what we're doing. On the community support side, we're very active in the Trinidad environment to make things work. I think, again, that consistent support we've shown in the community has given us that social license to keep doing what we're done. As far as the jurisdiction goes, I think we're again seeing that it's over 100 years that oil and gas has been in Trinidad. They want us to be there, and we want to be there, so it works out well. This is a map that everybody has seen, but I think the only real takeaway for us is that -- we've now got 75,000 BOEs a day of capacity. As I pointed out a little bit earlier, current production being around that 5,000 range. We've got way more capacity than we have the ability to -- 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. I'm going to turn it over to Brian, and he can walk you through some of the operational update and the work program.

Thanks, Paul. This first slide, I think, is really impactful. It speaks to why we did the Shell deal. With the Central block acquisition, we got a gas plant, a producing field. We also got 2 critical LNG contracts, which marries nice with our fixed contract at Ortoire. You can see on the slide there, we've put all 3 up. We'll start at the bottom. That's the Ortoire 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 sell onshore domestically. We'll look for that to go up. The next curve up is the Train 4 contract. 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 2/3 there. That one will kick in for all of the Central block production. 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. That bodes well. We've seen that pricing start to reflect in our quarterlies. You can see from 2025 to Q1 to Q2 2026, we've started to see the impact of those sales to LNG. In June, July, so part of the Train 4 contract is if there's maintenance on that train that we get to divert temporarily to the higher-priced contract. We actually did that in June and July. 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's an all-in price after fees that we get on that LNG.

Yes. I think the other thing to mention on that is we also get 3 streams out of Central block. We get the condensate that gets knocked out of the plant, which is basically Brent less about 15% now. Then we also get the NGLs that get knocked out at Atlantic. So sort of these 3 phases that we get, which is really great.

Looking at our 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 Cascadura, which I'll speak to. But I mean, looking at our asset classes and where they go, our Brent oil or our oil production at the bottom is about 1,000 to 1,100 barrels a day, pretty consistent low decline production. We sell that at Brent less 15%, as Paul spoke to there. The Central block production, which is yellow, so that goes pure LNG, that goes to Train 4 or Train 2/3 as the case may be. After May 2027, that will all go to that higher price contract. The little dips you're seeing in there, that's just planned maintenance at the plant. We routinely every 6 months do some maintenance on the compressors. The red line, that's Cascadura. Obviously, Central block has compression, and you can see how stable and flat it is. Cascadura did not until July. We have that installed in July. We've seen improving run times on the unit the last few months from about 54% to 70%. 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. Okay. Looking at the capital program. In the first half, we had a busy first half. We brought CR-3 online at Central block, like Paul said, our first well in roughly 15, 17 years. We drilled 2 wells on our oil blocks on WD-8. It's notable those are actually paid for -- the drilling costs were paid for by the turnkey contractor because we sold them the size of that block. 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 Cascadura booster compressor, and 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. Then we had that Baraka East recompletion, 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 0.3 million cubic feet per day to over 2 million plus increased liquids, which actually blended the gravity down of the total Central block condensate, and that resulted in improved price contracts where we're getting about the Brent less 15% on that stream as well. So kind of a double benefits on that job. By our math, it paid out in about 10 days with these high LNG prices, so really solid. Looking to the second half, we're going to continue with our recompletion work program across Central and Ortoire, looking for low-cost optimizations that we can do in the field. We're also going to drill 2 WD-4 wells. The rig is on site. It's probably going to spud this weekend, early next week. One of those wells is also paid for by the turnkey contractor, similar to the WD-8 wells. Looking forward to 2027, the key here is going to 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 going to really tailor our work program to hit those price ramps as they come in, in 2027.

Thanks, Brian. Let me just kind of 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 WD-8, WD-4, CO-1, even 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. We're going to really have compressed that time frame of when we can drill wells and bring them on stream. As far as the drilling inventory goes, 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. 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 want to do is time these wells so that they come on stream into the higher-priced contracts. Basically, between now and Q1 of next year, the focus will be on Central block. Q2, Q3 of next year will be on the Cascadura facilities. Then in the background of all of that, we'll continue to optimize and drill up the oil wells as we go along. On the exploration side, one of the questions is when do we get around that? I think that is it really is going to be determinant on 2 things. One is how strong these prices stay for how long; and two, the VAT refunds. I know there's a question on that in what we look at here. I'll wait and answer that as part of that question. The other thing that we have is a huge inventory of land, which I really -- I call it the opportunity for us. We've got 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. It changes everything on the island for us. Then the premium pricing upside, two contracts, as Brian pointed out, the Central block one that happens in May, the Ortoire one, which we'll start having discussions right away here with NGC, but it would come into place. I think it's on the 9th or 10th of October of 2027, something around there, 5 years to the date of when we started to flow gas actually out of the Coho facility. So it just -- there's a price renegotiation every 5 years. That's what that's around. But 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. What do we -- 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. We've got this inventory of deeper wells as well as the exploration acreage plus the development wells. We've got all the owned and operated infrastructure. I think we talk about it being owned, but I think it's also key that we operate it all. We can move some folks around. We can lower the operating cost. It's really, really important to us. The deleveraging, Scott 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 Q2 and what we're really doing is focusing on deleveraging and cleaning up the balance sheet. Where is the value opportunity here? It's pretty simple. I think when you look at how badly the stock has been 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. Then on top of that, in a country that wants us to be there and really needs the gas, it kind of goes all the way down. On the ESG side, we continue to focus on that. The #1 thing for us is obviously safety. I think when you look at our reputation in the community down there, I think we've got a pretty high profile. It's worked out really well. That is the summary of the presentation. What I would suggest we do now is we'll put 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? I mean, ideally, yes, we'd love to pay a dividend in the future, but let's deal with the elephant in the room here. We got to clean up the balance sheet first. Free cash flow here will be to clean up the balance sheet before we even look at any of those kind of things. When I say the cleaning up of the balance sheet, what we're looking to do is try to get to 1 to 1.5x debt to cash flow. With the kind of prices that we're now seeing, if you look at the numbers in Q2 alone, we're not very far from that. I think the team is certainly working towards that for sure. There's a 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 great -- maybe makes me a little uncomfortable. 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. Part of this Venezuela conference, I'm really just wearing a hat from the energy chamber in Trinidad to go down there. I mean it's going to be fascinating to see what's going on down there. But when you sit through the presentation that we just presented to you, I think it becomes very clear, we have more than enough things to do in Trinidad. When you look at the contracts, you look at the land position we have, the underutilized facilities, 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 going to turn that over to Brian, if you would mind take that.

Yes, sure, Paul. I think we touched on that in the presentation. LNG is May 2027. That's when the contract flips over. We have heard from Atlantic LNG that in March, they might do some Train 4 maintenance. There's an opportunity potentially there for us to flip to the higher price in March instead of May, but we'll run with May for the contract. The domestic is October, as I said. 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 gives us some leverage when we go into negotiations to look for a higher domestic price, either fixed or potentially linked to petrochemicals downstream. We'll see how that negotiation goes.

Yes. I think if we -- the only example that we can really look at is the EOG team, they went in to renegotiate with NGC and they got it -- done it about 9 months before the renegotiation time. We'll start to have those conversations certainly as we go. But the other part of that question was where are we in gas pricing versus the rest of the world. I think the real unique thing that 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 push 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 a heavy investment period last quarter of this year, likely? Again, as I point out, like even in Q2, we were already there. Now we are going to ramp up some of those expenditures as we go. But you can see, I think what you're going to see is quarter-by-quarter depending on what we want to do and the debt repayments. Mid-next year, we've paid off the first of the 2 term loans with RBL. You start to free up a bunch of cash to do other things. But again, my best answer to that question is we basically were in Q2. Next question is when do you expect tax refund from government? Why are they delaying the refunds? Second part of the question, I think the reason they're delaying the refunds is because they're just using that to finance government operations. 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 going to get those back. However, they usually deal with them in the October budget. 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. Stand by that and see it would be great if we got some positive news out of that. 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 Baraka well still planned? And if so, when do you expect to spud it? The Baraka well is another one of the Central block wells. In our discussions with our joint venture partner, Heritage, they had some seismic data that had been reprocessed but not interpreted. They shared that with us, and we're actually looking at it right now. That well has been delayed a little bit only from the point of view of we want to 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 and it's ready to go.

The pad is ready, we need a month to get the rig going. So when it's time, we'll move it.

Yes, yes. What do you think is holding back the share price? I think there's a bit of credibility. I think from our point of view, last year, a lot of the wells went way over budget and the production didn't come in where we wanted to. This has given us an opportunity to retool that a little bit. I think when we start to see some of the results, I think the solvent soak, you look at that, you look at what we were able to do with BRE with the recompletion. Maybe you can just talk for a minute about what we're looking at doing at CR-3 on the Karamat sands, that would be another one.

Yes. We're looking in October. We're going to send the service rig out, and we're going to try and perforate the Karamat sands. It's about 80-odd feet sitting just above the Herrera sandstone. Drilling through it on CR-3, it had really strong gas shows of up to about 30%. On logs, it looks really good. We needed pretty high mud weight to control it. What we're looking there is to temporarily plug off the Herrera and then perforate the Karamat likely have higher pressure. We'll be flowing that to the plant. The nice thing is it's already tied in right after the perforation, it will be on stream to sales.

Yes. I think -- yes, there's a couple of questions in here. One of them was their MPD, which I'm guessing is MPD used at CR-3 while we're drilling. So that would be the pressure drilling -- managed pressure drilling. We did do that. But even with the managed pressure drilling, it looks like the reservoir was depleted with the product that we had, we probably damaged it up pretty good. And one of the other challenges we had the high-pressure Karamat sitting above the low pressure. So you're trying to control the high-pressure zone while you drill them through the low pressure. One of the things we've been able to do is kind of step away, look at well design, look at rig design, look at the mud properties, look at everything that we've done. As we go forward at Central block and at Cascadura, I think we can use a bunch of that. The last 5 Cas, CD wells had a significant problems that -- the question is here that have run them. Have those problems been identified and what action is being taken to prevent the same problems occurring again? We are looking at all of that. I think it is very tricky, and Brian, you can jump in here, but drilling through these overpressured and underpressured zones, it's just a challenge. 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.

Yes. I mean, at Cas-2, we had that positive solvent squeeze. I think there was a question on that. We wanted to try that chemical on our lower rate producers just as a test. It reduces condensate banking. You get condensate banking against the sand face and this chemical breaks that down, allowing the well to flow. We saw about a 50% uplift in the production out of that well over the last few weeks after doing it. Now it was producing around 1.5 million -- 1.4 million a day. So we've got it up into the 2s. But what we really wanted to see there was magnitude of increase. Now we plan to deploy this on some other Cascadura wells as well, and it's relatively cheap chemical to use.

Yes. Next question is the $10.2 million fundraise and strength in liquidity came through shareholder dilution despite the net debt only fell 6%. 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, what ended up happening was there was an $8 million bond that came as part of that, that then also converted to equity. That $8 million also reduced debt in Q3. You'll see that big change in the balance sheet in Q3. I know that was a bit of a tricky financing the way we did it, but it was because we needed shareholder approval to issue the full amount of equity. It looked as $8 million of that $10 million still sat as debt on the balance sheet at the end of the quarter, and then it flips over in Q3. You'll really see the benefit of that in Q3. 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. Total production sales BOE per day, concern in the short-term and medium-term, where and all is the significant increase going to come from? Well, one of the big increases will come from Cascadura as we get that production leveled out. I mean it was really bouncing around from a couple of million a day depending on where it was to maximum rates were probably 8 million or 9 million a day. We're definitely going to see those go up. At Central block, we've got the Karamat projects that we're working on as well as additional drilling there. Then as we move into Q2 and Q3 of next year, we start to see development drilling at Cascadura. The real focus here was to get everything integrated, get it done, especially get that compressor in. Now what you'll start to do is see the volumes ramp up as we bring on these new wells. Again, a good question. Do we have faith in drilling any more new wells at Central Block? Yes, the only thing I think the one comment there might be they probably won't be in the Carapal for it, zone or Carapal field. I think what we're seeing with the new data is we're probably more excited with the Baraka East and the Baraka field, especially with what you saw in that recompletion, Brian?