Trinity Exploration & Production Limited (TRIN) Earnings Call Transcript & Summary

Good afternoon, ladies and gentlemen, and welcome to the Trinity Exploration & Production plc Investor Presentation. [Operator Instructions] The company may not be in a position to answer every question it receives during the meeting itself. However, the company will review all questions submitted today and publish responses where it's appropriate to do so and these will be available via your Investor Meet company dashboard. Before we begin, I would like to submit the following poll and if you could give that your kind attention, I'm sure the company would be most grateful. And I would now like to hand you over to the Executive Management Team from Trinity Exploration & Production plc. Jeremy, good afternoon, sir.

Good afternoon. Thanks, Jake. Welcome all to Trinity's operational update, which is focused on Jacobin. Presenting with me this morning -- by the way, I'm Jeremy Bridglalsingh, CEO of Trinity. Presenting with me is Mark Kingsley, our Chief Operating Officer, sitting to my right in our cold San Fernando offices and joining us from Reading in the UK is Julian Kennedy, the Chief Financial Officer. Before we dive directly into the operational update, allow me to briefly introduce Trinity to those who may be new to this presentation. We are quoted on AIM as governed by the London Stock Exchange. All of our oil is produced in Trinidad & Tobago and we operate across 10 licenses both onshore and offshore in shallow waters. We produce between [Audio Gap] plus some low risk developments so about 66.8 million barrels and exclude significant prospective upside. During today's update, we will lay out the life cycle of Jacobin from data acquisition to first oil, give a detailed operational update of the well and we'll also lay out the next steps in Jacobin's testing plan, which will drive our near-term investor communications. After the presentation, we'll move to a Q&A session during which, we'll attempt to go through all of the questions that we received both prior to and during this presentation. Any questions that we don't answer during today's session will be answered afterwards and posted online in the usual manner.

Ladies and gentlemen, please do just bear with us while we reconnect to the team. Jeremy, if you could just reconnect your microphone, that would be great. We can see you connected, but we can't hear you, sir. Ladies and gentlemen, please do bear with us just while we reconnect Jeremy. Jeremy, thank you very much indeed. I would just request control. Jeremy, can you hear us?

We can hear you fine.

Lovely, sir. We just lost you momentarily. I'm going to keep your camera off just to conserve the bandwidth. But if we do lose you again, we might need you to dial in. But if I could ask you to start back on the slide where we're showing on Page #2, that'd be great. Thank you.

Thanks very much. Apologies to those listening in. We seem to be having some technical difficulties, but let's press on. Before Mark takes you through the operational aspect and the next steps for Jacobin, I just want to recap the path and speed at which we proceeded from identifying Palo Seco as a strategic option, building a plan to test our strategy, identifying a drillable structure and successfully drilling a 10,000-foot well into that structure. The result of which has proven our deeper play concept. All of this was and will be funded from the balance sheet without tapping into our working capital facility or requiring any equity bridge. Jacobin is a result of focus and dissemination across multiple disciplines, which ensure safe delivery. The timeline that you see on the slide here reflects moving from this acquisition to first oil in 35 months, which compares favorably to the usual cycle of 4 to 6 years. The 3D seismic that we acquired in late 2020 was not of the best quality. We had to place and find world-class geophysicists to then sit with the data set, which took time and financial investment. It became apparent during 2021 that Palo Seco had significant potential even though it seemed to have been exploited since the 1960s by a variety of operators. Our analysis showed shallow areas of interest, but more interestingly, deeper structures that weren't drilled. This is when we developed the concept of a deeper Hummingbird Play. On the back of this, we identified PS-4 as a key property within the Palo Seco area and we eventually acquired the property and this is where Jacobin was actually drilled from. We then prepared to drill the exploration well and commenced drilling in May of this year. The well did take longer than planned due to a number of drilling challenges in getting to 10,000 feet. This is the first time that we drilled to 10,000 feet as a company. But in August we were able to announce that we had discovered 3 oil bearing zones in the exploration section of the well. That was a better than planned outcome and as the most likely success case was that we would find 1 oil bearing zone only. First oil occurred during September and we've now entered into the testing phase and Mark will go on to describe that.

Good morning, everybody. Mark Kingsley here. So just picking up from where Jeremy left. The well itself was challenging to drill, but we achieved TD and then we brought on the heavy-duty workover rig to run the completion and perforate. It's fair to say that traditionally in the oil and gas industry, an exploration well wouldn't always be converted into a production well. So there are some challenges and complexity around that. But in terms of trying to make maximum use of the well that we drilled, we obviously wanted to try and begin production. So the approach that we've taken is a conventional one of basically running a completion with tubing conveyed guns and perforating the lowest zone. And you can see on the diagram on the right hand side, you can see that's what we call the Lower Cruse 3 zone, which is shown in blue at the bottom of the right hand side. When we perforated, we were expecting a sort of wellhead pressure in the region of 2,500 psi. I think indeed that's what we saw. So in terms of the predrill, expectations on reservoir pressure were sort of matched and so we were encouraged by that. Obviously we had healthy pressure at the surface and we opened the well up and over sort of a 7-hour period, we saw initially pretty healthy rates of production and obviously there's a fluid in the well to be displaced first before oil starts to flow. But the rates declined over that period and over time we were able to see that. Unfortunately, that was due to the influx of sand. Now I want to be clear, the presence of sand per se is not something unusual. We had in our risk assessment of the well -- saw there would have been some potential for sand, but quite low. But as it happened, what we saw and what we subsequently found is that this sand is very fine. So it's basically almost like a talcum powder type material coming into the well bore and that bridged the production tubing, blocking the sort of production tubing about 1,000 feet below surface. So this is an operational issue. It's not a fundamental issue impacting the sort of viability of the well at all. But to clear that blockage, we attempted to use conventional wireline tools, things which are readily available on the island, but had no success with that. So some of the time -- I know there have been some comments about why it is taking so long. Well, Trinidad is a relatively small market. There is equipment here, but unusual equipment is not necessarily available. So we had to secure a coiled tubing unit, which we managed to find. That item is on the island. It had some modifications to make it appropriate to run into a well of 10,000 psi rated standard, which is quite unusual for Trinidad. But that coiled tubing unit is now being made ready. It's going through its statutory inspections with the state oil company, with the ministry and we're looking to start to move that to the site over the weekend. So I expect to be on location on Monday running in with the coiled tubing unit. I'm confident that we will clear the blockage and then basically we will restart the operations. So the second time around, we will be even more cautious than we were in the first time around. We'll be using a smaller choke size. We'll be taking sand measurements every 15 minutes to make sure that we don't see any more sand being brought in. And our expectation is that this should be a well that we can bring in production. This is not unusual for Trinity. We have sand produced in other similar assets and a good analogy here is our well on the West Coast, ABM-151 where we had reasonable production, but we had sanding issues. So there were some operational challenges to get the well up and running, but we basically found the sweet spot of the operating envelope and are able to produce that well quite happily today without any issues. So I expect that that's where we'll get to with this well. So the plan is then to test the Lower Cruse 3 for a period. Let's see what the sort of prospectivity is, productivity and sustainability of the flow is. And depending how that goes, we may either suspend it and then move up hole or if it's poor, then we'll potentially abandon it and then again move up hole. What is shown there, the second sort of lowest horizon in the 8.5-inch hole is the Lower Cruse 1. As Jeremy said, there are 2 prospective zones in there. So the plan once we've finished on Lower Curse 3 is to move up to Lower Cruse 1 and perforate the 2 zones there and flow them to surface again using a very traditional sort of methodology. I know some questions have been asked about why don't you commingle all 3 zones? That's been considered, but unfortunately, the pressure rating as you can see from the chart in the lowest zone, we've got 7,500 psi; in the Lower Cruse 1, we've got 4,500 psi. So you've got a big sort of 3,000 psi pressure delta there, which would potentially create cross flow and other operational issues. So really that's not something that we have considered as practical. But I stress that these are all normal operational issues. It's taken a little bit more time. Some of that is linked to the supply chain challenges we have on the island, but that's something that we are used to dealing with. And in the coming week hopefully we'll have some better news and obviously we plan to give an update in the next month or so.

Thanks, Mark. I'll just slide on to the next one and Julian, if you would take us through this, please.

Yes, I'll take this. There were a number of questions in the presubmitted Q&A around communication. And I think what we're committing to here today is that we will be updating the market and shareholders more frequently as we move through the rest of the process on Jacobin. As Mark alluded to, we will put something out once the coiled tubing unit has been on the well site and done its thing. And then as we progress with the Lower Cruse 3 zone, we will continue to inform the market. There was also a presubmitted question that asked about AIM Rule 11. I'd just like to state that throughout the process, we have and do consult with our NOMAD on announcements. And as Mark and Jeremy mentioned, the issues with Jacobin have not been unusual in terms of operational activity on the island and it was with that regard that we didn't put something out when we achieved first oil at the end of September. But we recognize that there is an appetite for information. We are committing to come back with an investor presentation that will cover the status of Jacobin at that time and a broader Galeota update in a month in the week commencing the 27th and we will finalize dates for that. We will also arrange an in-person session in London for retail investors. We then anticipate keeping the market fully informed as we potentially produce out the LC3 reservoir and then move up-hole into the 2 other oil bearing intervals in Lower Cruse 1. And then the back end of this slide just indicates the Q4 operational update at the back end of January.

Thanks, Julian. This is a pretty brief presentation so I'll just recap as to where we are. I mean the sand plug, as Mark has mentioned, this is standard operational practice for us. So dealing with the sand plug is something that is not by any means permanent. It has not impaired the well and we will be subject to getting this post Jacobin unit on over the weekend as Mark has mentioned. We'll be moving through that fairly quickly and then providing an update as to the success of that. The Lower Cruse 3 is quite interesting. We didn't expect it to flow as it did. We'll see how it continues to flow. But even more interesting is the Lower Cruse 1. So this well has a range of potential and notwithstanding, it also has in the development like the forest sands and the Upper Cruse sands, which we also know are well bearing as well. The cost of the well certainly has gone over and above what we thought it would do. But this is something that we're able to absorb through the existing operating cash flow, which is driven through managing production as closely as we can and keeping a close eye on our cost structure. The underlying business remains resilient irrespective and those cash flows are what we'll use to continue to drive not just Jacobin, but further investments into the business. And finally, I just want to touch on Galeota because the reserves in Galeota are quite transformational for us. And the Petrobras study that actually Mark led has helped to validate some of the development concepts that he thought about when he came in here originally and they had lower capital intensity and the results of that is that the scope in economics with emphasis on scoping look quite encouraging. And these will only stand to be further improved based on what we think the proposed SPT reform that the Minister of Finance announced on the budget that he read on October 2. We will provide a further update on Jacobin, but we will be providing updates for Jacobin as we go. But also inclusive of Galeota updates in our wider corporate Investor Presentation, which will be during the week of the 27th of November as Julian mentioned. I'd like to thank you for your attention and apologize for the technical difficulties that we encountered a little bit early on and I look forward to further engagement in fact with an in-person event later on in November where I hope to meet whoever can attend that. It'll be great to meet you in person and continue this discussion. Let me now hand you back to Jake to close this part of the session off and then we'll resume the Q&A.

[Operator Instructions] But just while the team take a few moments to review those questions that were submitted already, I would like to remind you that a recording of this presentation along with a copy of the slides and the published Q&A can be accessed via your investor dashboard. Jeremy, Julian, Mark; we did receive a number of presubmitted questions ahead of today's event as you did kindly already mention and we've also received a number of questions throughout your presentation this afternoon as well. So Jeremy, if I may just hand back to you perhaps to chair the Q&A session with the team. If I could just ask you just to read out those questions and give your responses where it's appropriate to do so and then I'll pick up from you at the end. Thank you.

And hopefully everyone can hear. Jake, I mean if you want to try the camera, it'll be good. If not, we can switch it back off if it creates any issues. We received a number of questions in advance of this so thank you very much for taking the time to do so. We've tried to organize these into various themes certainly on Jacobin was the heart of those questions and the best person to answer those are Mark. So I'll read some of the questions out and Mark will give his thoughts on those. Question one. To what degree is the sand in Jacobin a long-term issue, which may inhibit production from the existing deep and other 2 deep sources?

I think we addressed that in the presentation itself. I think we see it as an operational issue, but it's not something that should fundamentally change the ability to produce the well long term. So it's something now we've seen in the Lower Cruse 3 and with the Lower Cruse 1, we will be more aware of it. But honestly, the sort of the material that we've seen from the samples we've recovered from the well are so fine that the sort of traditional sand control measures like screens, sand screens and/or gravel packs would have not stopped that anyway. So it's just something we'll manage around by production so there's optimization.

Is there a worst case date by when definitive flow rate data about Jacobin will be available from all of the identified zones?

Okay. So for Lower Cruse 3, the one that we have perforated, I'm saying that clearing this blockage should be basically early next week. The coiled tubing unit is moving on. We expect to be able to clear the tubing within a 12 to 24-hour window and then we will be starting up quite quickly after that. So I would say sometime in the first couple of weeks and before the investor presentation that we've mooted for the end of November, we should be in a position to give an update on LC3 production numbers and sort of some view on the prospect of that horizon. For then going up hole, suspending the sort of LC3 and moving into LC1 and perforating that area, I would expect that sort of the worst case that would be within a 3-month window so sometime in the first quarter of 2024.

Do you anticipate Jacobin producing from 1 zone at a time or from multiple zones simultaneously?

To be determined. I think it depends on the prospect of LC3. I mean we could see it's a relatively thin horizon, it's 5-feet thick; but the initial flow rate we saw coming from the initial perforation was quite encouraging. So I think it is too early to say. But certainly the 2 sands in the LC1, I would expect us to produce them simultaneously and to sort of assess what the flow contribution is from each horizon. We will be looking to run some form of production logging tool at some point in the future just to determine what the split of production is coming from which zone. But to run all 3 initially together because of the hydraulic issues between and the pressure differences between the various zones is not feasible technically. So I would say that certainly we could run LC1/ 2 sands together. That's something we do consider.

There's a fairly lengthy question here that basically asks why we didn't say something about the sand plug when it did happen. I'll take this one. From an operational perspective, we looked at what happened. A sand plug is something that we encounter from time to time in our operations. In fact with the ABM-151 well when we brought that on, we had to deal with sanding issues and it took us a few weeks to get that under control. We kept the NOMAD close to this given the nature of the Jacobin well. Because the sand plug was something temporary, it has perhaps taken some time. But as Mark has explained, the coiled tubing units that we have on the ground is not rated for 10,000 psi so it has to be modified. The discussions that we had with our NOMAD and internally gave us guidance that this is not price sensitive and therefore not something that needed to be released immediately and that's the reason why we did it. But I think what we hear from shareholders is that keeping you up to date on the progress of the Jacobin on a more frequent basis is something that you are interested in and that's certainly what we are going to do going forward. Can you give a ballpark estimate of the foreseen final costs of Jacobin? Was it not possible to foresee that sand proofing of the well was necessary? Maybe 2 parts in there. Julian, would you want to take the part about the final cost at Jacobin?

Sure. At present we think that the outturn cost is going to be around USD 8 million give or take. And to the end of September, we have spent $4 million approximately of that. We anticipate that some of the cost will be incurred in 2024.

And I think, Mark, you already answered this. But was it not possible to see that sand proofing of the well was necessary?

I think I've answered that. I think the presence of sand was contemplated, but the view taken that really was sand proofing on -- putting sand screens or gravel packing at this stage on an exploration well where we have no real information from that horizon was probably really would have been overkill. And actually based on what we've seen, it would not have made any difference given the fine sort of nature of the sand that's come through. So I think we made the right call and we'll go back in and now we're forearmed, forewarned and we'll act appropriately.

So moving on to the next category of questions, which deals with post Jacobin what was the next step for the Hummingbird activity? So many questions here are like what are your plans for further drilling in Jacobin's deep and upper wells? I think, as Mark mentioned, it's quite unusual to take an exploration well and move to production straight away. We are in a well testing phase that will give us a significant amount of data. I mean we had a better than planned outcome, but it says that we were uncertain as to what the outcome would have been. It's worked out in our favor in this instance with having 3 oil-bearing zones. We are going to assess the productive potential of each of those zones and then that will inform any further investment decisions that we take. But certainly it's a positive read across the deeper play that we've identified the Hummingbird prospects. This augurs well for those and it is also encouraging for Buenos Ayres, which has not only these deeper Lower Cruse plays, but also the upper forests and Upper Cruse zones that we currently produce from in the WD-5/6, WD-2 and PS4 areas. There was also a clearing in Buenos Ayres, but have not yet been drilled. What are our precise plans for the next Hummingbird well? When are you aiming to commence if so? I guess maybe I'll hand over to Mark from a data and operational preparedness standpoint and then Julian from a financial perspective.

In terms of data acquisition, we obviously need to gain as much information as we can from this well, bring that into the team and then extract the personal data and then let that shape our technical view going forward. And I think traditionally taking output from an exploration well like this and then feeding it back into your next drilling target would take some months. So I would say that we're talking about a potential certainly not this year and probably not in the first half of next year, potentially a well sometime late 2024 is a possibility. But that's the sort of time frame, not before that I would say. Because of the need to really properly accept the data, understand the data and then feed that into our plans going forward to make sure we've kept the lessons learned and honestly, we learned a lot from the drilling of Jacobin. I think we presented -- Jeremy and myself and Julian presented the time-depth curve to the state oil company Heritage, which kind of showed the plan versus the actual and sort of the trials and tribulations we sort of encountered and overcame. And I think they were quite impressed with the sort of technical approach we take. And I've been involved with many drilling campaigns over the years in many locations and I think honestly, the contractor and our team did an excellent job to get this well down to TD given the nature of the job and the nature of the well. And so the current issues are not in the same scale of challenge in my view. So we are very much on the home stretch of this. But it is a bit early to say that we're going to bang straight on to the next one.