Melbana Energy Limited (MAY.AX) Earnings Call Transcript & Summary

Okay. Good morning, everyone. Welcome to today's webinar. My name is Sam Jacobs from Six Degrees Investor Relations, and I will be the host and moderator for today's presentation from Melbana Energy, Executive Chairman, Andrew Purcell, who will also be joined today by Exploration Manager, Dr. Duncan Lockhart, and Melbana's Chief Geoscientist, Errol Johnstone. Today's presentation follows on from last month's webinar and also the latest ASX announcement from Melbana, which was lodged this morning regarding ongoing operations of the Alameda-2 appraisal well at Melbana's block -- operations of Block 9 PSC area in onshore Cuba. [Operator Instructions] As previously highlighted, Melbana management obviously like to take these opportunities to engage directly with the shareholder base and explain their operations. But obviously, we want to maintain that process in "even timely manner." So just keep that in mind [Operator Instructions]. A copy of the webinar presentation will be available on Melbana's website and social media platforms later today. You can download the most recent announcement, which came out this morning just by navigating to the handouts pane in your control panel. So for now, as usual, I'll throw it over to Andrew and the team to kick things off. Andrew, thank you.

Thank you very much. Good to be here again. We've got a short presentation that really just sets the context for what is I know the most important part, which is the Q&A. But given that the announcement we put out this morning, I wanted to just step us through what it is that will give you as a framework before we get into the Q&A very short. So we top through, there is an index which is going to set the context of what we have just completed with Alameda-2. I know that probably for those of you who are following every day, is a bit [indiscernible] how difficult is to relay what is happening in the field and the order that it's happening in. So we put together some diagrams and animations. So you can be at the same starting point for us when we get into the Q&A. And then the work that I have to share with you with my colleagues on the phone and on the meeting to talk to those slides and answer your questions as well. And then we'll just start with the summary of what we done in Alameda-2 what we found and what we will do next and then we'll go straight into the Q&A. So if we a pop forward a couple of slides, please. What we've got on the left there is a video that is the oil flowing into the tanks from the Unit-1B test. As you can see, it's quite voluminous [indiscernible] lots of flows light looking oil. Unit-1B has been a great success, we think, from a number of measures that we'll talk to in this webinar. The first look at the oil we got from the bucket probably isolated from the tank, made it a little bit clearer. I think the optics of the camera skills of our colleagues in the field. They're good engineers and geologists and not so good on camera work, but you can see it's quite a live, flying into that bucket. That's the sampling mechanism, that was the initial flow. When we get the separation going forward with that sample. So that sets the context. 1B is really doing for us. Now how we conducted this test? And why we drilled the well in the way we did feed to a number of questions we've received from many of you. And so the following slides, I'll ask my colleague, Duncan, to just say, look, here is the context. These are the upper sheet, this is the formation called Amistad. It has a number of different units. We have to drill vertical well to test all of these units in the 1 well, near vertical well. And how we designed the well to do that as simply as possible based on the learnings from last year's Alameda-1 is what Duncan will now talk to you in the slides ahead. So Duncan over to you.

Okay. Thanks very much, Andrew. The slide that we have on the page, currently, is a schematic that shows the position of Alameda-2 with respect to Alameda-1 and the philosophy behind what we try to do here and what we have done here was effectively like Andrew said, drilled vertically through the upper zones, and then we decided that we would deviate the well and head up to test the Amistad Zone 3 in a more uptick position. And in fact, we were successful in that. We did that intersect that zone about 500 meters to the south of the initial wellbore. So if I -- so just running through the schematics of what we actually did then for the testing, we drilled down to around 450 meters, and we set the 13-3/8 casing shoe just above the entry point into Unit 1A. We then drilled ahead slightly around 50 meters.

[indiscernible].

Yes. And undertook the initial DST-1, which this is a test where we flowed the 11-degree API oil to the surface. We couldn't measure the rate, but we do know that this was able to flow from this very shallow depth to the surface and being 11-degree API oil. It's a great result, and we know that effectively it stopped flowing simply because the buyout of the column killed itself. After doing this, we drilled the entire hole section then. We went through Unit 1A and 1B through what -- at this point, we were calling Unit-2. But Errol will explain coming up, we've revised our thinking about what we believe Unit-2 is. It now looks like it's a very highly faulted, additional fault sliver of Unit 3 as we have defined in the previous well. We went through another seal, and we got down into just above Unit 3, where we set the 7-inch casing after logging that entire section. And based on those logs, we're able to work out which zones that we wish to perforate through Units 2 and 1. We then continued drilling down to TD in the hole section. We logged that hole. And then from that, we were able to work out where we wanted to put the slots in a 4.5-inch slotted liner, which we then ran, which is next slide. So we ran that 4.5-inch slotted liner with the slots open over the best zones that we saw in Unit-3. And then we undertook a DST of that interval. Now this is the interval where we had an initial inflow into the well of heavy oil, similar in composition to what we saw in Unit-1A. And we calculated that it ingress into the hole with a rate of around 750 barrels of oil a day, but it didn't make it to the surface due to the weight of the column. After we ran this test, we ran a bridge plug to separate that zone off, and then we went back into unit -- into what we called Unit-2 and perforated it. Then we ran a DST in this zone, which was DST-3, which unfortunately, we failed to get any flow from. We then set a bridge plug over that section. And then perforated Unit-1B. We have a total of 70 meters of -- in total vertical depth sense of perforations over the entire interval, which represents only about 20% of the entire net to gross that we saw through that zone, but we chose what we saw with the 2 better zones within that Unit-1B. Once we perforated, then we ran the final DST, and this is the one that we had a peak flow rate of around 1,900 barrels of oil a day. And the average of just over 1,200 barrels of oil a day of 19-degree API oil, and it's relatively light oil in comparison to what we've seen in the rest of the well. And it flows, as you can see, to surface unassisted. So we have now run a completion over that section.

Thank you, Duncan. That's an important point you made there on Unit-1B by the animation or the cartoon looks like we've perforated the whole thing, as Duncan said, it's really only 20% of the net pay of the Unit-1B that we've perforated to give us the results so that we've reported. So -- and then you've got the perforations themselves that are naturally restricted zone influx into the casing, which also is unlimited to the results we've had. So there's a lot of reasons to be very excited about this result. And I think if we page forward to the next slide, Duncan, the mechanism by which we're getting these flows are assisted?

Yes. So this is much macro image of the section. And you can see, well, as a geologist, I can see anyway that there is a very highly fractured nature to this reservoir. And so this is obviously making a significant contribution to the flow that we've seen in 1B as well as the natural porosity and permeability. So that has also given us a great confidence that instead of just using our conventional net pay cutoffs of 9% that we can and will incorporate if the natural fractures into these -- into the net pay calculation, which will give us a substantial increase in net pay throughout this section.

Thank you. Now I understand what we've learned, and we're learning this almost slightly ahead of all of you when we report it, is what is all this, all of these results and all these appraisals that's going to be a work that will go on for some time. But it's primarily the job of Chief Geoscientist, Errol, who's put together this diagram at very short notice for this webinar to help us all understand a little bit what's going on in his head on the results that we've set. Over to you, Errol.

Thank you, Andrew and Duncan. This represents a recent PSDM, which is depth-migrated cross section display here at 1:1 depth with the both wells plotted on it intersecting a number of shoots which make up the Amistad project in the cover. And what we see here is the 3 colored limestone units that we've actually gone through in Alameda were designated in the green, Unit 1A, which is actually a very thin unit as it turns out. But then being 120 meters of net limestone pay. So I'd point that out. As we go through a big shale between the green unit and the underlying Unit 1B limestone which are all designated in the light blue color. And you can see there with the light blue coloration at Unit 1B represents many hundreds of meters of limestone. And really, the perforations in the tests are only conducted over the upper sort of 1/3 of that unit. And so we've got a lot of that unit still below the well to actually be properly opened up and tested. It is useful to notice now that Unit-2 is now interpreted, in my opinion, as a faulted slice that belongs to Unit-1B. The basal part of Unit 1B, it's going to be a faulting slice of that. So what we saw in Alameda-1 was a faulted slice, an extra piece of 1B under the purple fault. The purple fault is the very important structural demarcation between generally, the higher pressure stuff and the lower pressure units, but Unit-2 fits in the middle here. We now believe on the results of the well, which had seriously dipping strategically towards the north and all those dip management taken into account in this particular interpretation that we've intersected where we thought that there'd be a triangle wedge of Unit-2, making it into the wellbore. It now looks highly likely, like it's a fault of silver of yet more Unit-3 coming into the wellbore. And look, in this position, we actually only intersected really the rolling top seal part of that. So we're not in the reservoir proper above the purple fault for the Unit-3. As you go beneath the purple fault though, we opened up the updip extent of the reservoir of Unit-3. And as you can see, that's separated. It's 200 meters updip from where it was in Alameda, where you see I've written Alameda Unit 3, which was there, which was probably around the 15-degree API or maybe even a little higher, certainly fairly high pressure underneath that fault. And now we've gone across those 2 faults, 500 meters away to the south and 200 meters up dip across several fault's losses. We've encountered a fully oil bearing zone with no sign of water that successfully tested and brought free oil into the drill pipe at a calculated rate of about 750 barrels per day. So on pump, this would do pretty well. And the thing that this really opens up because we've only ever assessed reserves and resource to the north of the purple fault for these zones. And as you can see from this depth cross-section, we actually expect more fault repeats of Unit-3 towards the South potentially climbing up in the stack. And this would be very exciting for one of our proposed well locations of a new pad you see there in the orange line on the left-hand side of the section to investigate the giant role that you see in the deep section of the end sheet which is pushing its way and wedging its way right into the Alameda location where the end sheet in the deepest stuff was encountered and very productive for oil. So obviously, a vertical test through that large structure is sort of plan to be undertaken of one of the next projects. But one of the other things we can do is deviate the well through these upper sheets, intersect the Unit-1 be again, intersect the upper part of Unit-3 and another fault repeat of Unit-3 before proceeding down on end of the end sheet. So there's a number of things we can do here. One of the things I really want to emphasize here is the thickness of Unit-1B encountered with highly productive, heavily fractured limestone that flowed almost 2,000 barrels a day through a vertical well through that section with only the upper third probably tested. We are quite excited now that what would that do, given that we have to perforate casing to actually get the flow we did get, what would that do with the well engineered slotted liner around the entire interval to actually produce into the drill pipe. So a number of those things all come to mind, difficult to sort of understand all the geometries I understand. But this is just to try to keep in tent here a little bit as we're thinking about what the structural complexity of this thing really is and how many wells will really need to be drilled now to actually understand to the full extent of this thing because this could be very big. And so one of the things we're talking about now is to step out fairly aggressively and to define the limits of this thing. So that's part of our ongoing program planning.

And that's a good summary, Errol. Stepping out with more wells that can bring more production on and teach us more about the extent of this thing. But perhaps one thing that the listeners may find useful, Errol, is on this diagram at the very top and the green Unit-1A section, you have a heavier oil right down the bottom in the blue Unit 3 section, you have a heavier oil. But in the middle in the Unit-1B, we have a much lighter oil. What's a working hypothesis to explain that?

Well, An idea, we just talked about the other day, which has come about by this balance cross-section attempt to trying to restore one depth understanding of what's happening here across these faults, you see that Unit-3 has proposed to be climbing aggressively across [ imbricates ] towards the South. Well, it's gotten quite high in the stack and now it's halfway to the surface by the time you get to the end of this seismic line. So if you go another 10 kilometers or even less than that maybe even 5 kilometers to the South, it's potentially right near the surface and just under the classics in the top fill. And if that's true, this Unit-3 may actually be related to the [indiscernible] that actually is exposed to the south of Block 9. And it's from that surface sheet that in the early part of the 19th century, they actually recovered a lot of ash filled pipe streets of New York from Cuban crude for that particular oil. And [indiscernible] actually, as Unit-3 may be exposed to the surface if further seismic was to be acquired back then, we could prove that we could actually explain that's how the blocks have gotten into Unit-3, and they've actually started progressively to grade some of the oil in the upper parts of the oil sheets. We'll just say that holds up as a working philosophy going forward.

Thanks. Which is in the case of one slated from the same opportunity is what I take away from that. But thank you very much...

in contrast are not exposed to surface and would be under the cover in top seals between Unit-3 and end sheet.

Thank you, Errol. We can page forward, please. So a summary of the results to date. Just stepping us back through what we've been announcing over the last few weeks and to put a counterpoint an arrow on Duncan's work, just then Unit-1A, we started with open hole test, encountered like heavy oil, but we've covered the surface, and it was not able to establish a flow rate, but it was movable and it recovered from such a shallow depth, which was an exciting result. And when we drive to the bottom Unit-3, a long way stepped out from where we intercepted Unit 3 from Alameda-1. But again, movable oil, heavier in nature, favored into particularly at 750 barrels of oil per day, not able to recover the surface from the column of oil on top of it, but it's movable. And with persistence, that's going to be a very nice little project too. Typical to what they do in Cuba. Then we came back up. What we thought would be Unit-2 where we tested it, we didn't get any movable [indiscernible] as Errol just explained, it's now no longer thought to be Unit-2, where we were. And then now Unit-1B today's results, a much lighter oil, much lower viscosity, a very small section of the unit that we perforated has led to a tremendous flow from a vertical well. So that said, outstanding result from a Cuban perspective, not just to get that sort of flow from a vertical well to get this sort of quality as well. At this depth, it really does speak to promise of what's ahead at the deeper depths and the next appraisal well. But in total, we got a 3x increase in the log net pay in this upper Amistad formation. And that goes to like 5x or 6x when we incorporate all these natural fractions. So we had this massive that's called movable oil that flows to surface in the case of 1B unassisted and Unit-1A. And we've completed Unit-1B, as you can see in the diagram there. It's hot off the e-mail, hot off the press from Cuba, just a few hours ago, overnight out time. They've completed the Unit-1B for production. So everything is now in place to turn this thing on when we're ready. Next page. And I will finish by just pointing to the predrill prognosis. So Errol's spent a bit of time talking about this Amistad Zone 2, Zone 3 reinterpretation from his early diagrams. I want to point out, this is an old diagram, but the point of this is to show. The next well is going to -- we've got a solid black line. We've got a dash black line. They are -- the solid black line was the original Alameda-1. The dash black line is the proposed Alameda-3 that's coming up next. It's exactly 20 what we did last time and these 2 deeper structures, the Alameda and the Marti, they're the ones we're really looking forward to. I mean we're absolutely thrilled with what Amistad We've got a project, a very exciting project. But these guys down here, the promise of this Alameda sheet as it used to be called. We've intercepted it way down depth where we've connected it, all this potential on the page to the left. It will be a different orientation on the compass, but all that updip potential in green from where we've intercepted it. And Marti, both of these lower reservoirs, people have been watching our progress for a while. Remember the sort of pressures we encountered in the formations when we were down there last time. And we got some pretty intriguing oil shows that we couldn't sample cleanly because it was part of the fluids formation. But what we -- when it was really flowing over the shakers, it gave us very good reason to be optimistic that there is lighter oil down there, and we know there's high pressures down there. Those two things together give us great promise of unassisted recovery to surface, but better recovery rates, too, than the Cuban average that's been applied to our resource estimates class certifier and lighter, moves easier. And it's worth more. So very exciting result. Closed. Step 2, very exciting appraisal well coming up next. And I think that's all we had for presentation purposes. We could probably go back and leave one of those slides up on the screen and Iet's get into the Q&A.

Yes. Thanks, Andrew and team. So just switching over to the Q&A section now following the presentation. [Operator Instructions] But we'll kick off things with a couple of questions that were submitted by attendees prior to the webinar in writing. First question for you, Errol. It's more of a question on the geology of the projects. And perhaps just touching on it and reiterating what you went through in the presentation there. But the question was, do these results confirm and/or change your initial geological model? And what's the implication for future drilling targets. Can you just sort of appraise that for us, Errol, with reference to what you went through in the presentation?

Yes. Well, I can. Well, in essence, we've still only had a legacy old 2D data. With that legacy 2D data, we put together a geological and structural model which is attempting to predict a very complex multilayered nature of this particular compression structure. What we're drilling into is a multilayered compressional duplex system composed of vertically stacked sheets of thrusts that are individually faulted up within each shape to give a highly fractured and we now know a very productive reservoir system. But that is typical in its detail to actually speak to what exactly will we sort of find that every last wellbore, which is always concerned with details on the tens of meters rather than the hundreds of meters. But I would say that our wedging fall-in model of this particular duplex composed of many different sheets vertically as shown have been correct. We've drilled 2 very productive wells on this, both exploration wells stepping out in different directions, and they have come in with their top seals and reservoir systems within 100 meters. And frankly, that's hard to do on 3D seismic offshore. So I'm pretty proud of the effort that we've put in here and the results that we've achieved as a result of our structural model I look forward to future exploration around this area to try to follow up these results in adjacent locations.

Thanks, Errol. Second written question that came in, this one for you, Andrew, slightly more broadly kind of project based. But based on this announcement, when would you be -- when would you expect to be in a position do you think to have first oil for a trucking operation?

Already. We've already sent out 1,000 barrels of oil on trucks up to the battery. And we've got you Unit-1B completed now. So we can just hook that up and start producing from this Unit-1B when we're ready. There's a lot of activity going on, well pad at the moment, but everything is in place now.

Great. Just one more from the written submission. We can see a few attendees have put their hand up to ask questions. So getting to you shortly. Just the third from the first round of written, the third and final for you, Duncan. Has Alameda-2 provided enough data to date to confirm or perhaps expand the estimate of assessed best resource by McDaniel's and associates that came out following the Alameda-1 result?

We do have a much more significant increase in the amount of net paid that we've actually intersected here compared to what was given credit to this section prior. We also now know, as I mentioned earlier, that we can incorporate the fractures into the net pay calculations. So with that respect, yes, I think that we can expect an uptick at least in the net pay. And I think the other thing that we can expect an uptick in is potentially the recovery factors as well. But McDaniel's come to these numbers independently of what we have. I must stress that and there's a fair bit of work to go before we'll be able to get these -- the data off to McDaniel's. Errol still has to do a bit of remapping based on the intersected results that we've seen from the wells so that we can actually get the correct updated set of maps for the individual units. But overall, there might be a swing in a round about. But when you see the big increase in net pay and the fact that we've got over 1,000 barrels a day of oil flowing to the surface under its own steam. And from a vertical well, not even a horizontal well, I think we could expect something.

Thanks, Duncan. Okay. Just switching over to our live Q&A. Attendee Lawrence. Lawrence, we've just you an unmute prompt. So when you are ready to go, feel free to fire away.

Can you hear me, okay?

Yes, we can hear you. Thanks, Lawrence.

Fantastic. Look, tremendous news. And Errol, I know this is a very complicated structure, but that we've got here on multiple structures brought together. Just with respect to Unit-3, and just going on the diagram, thanks for keeping that up on so we can view that, is it interpreted that you've actually gone through 2 sections separated by the purple line, they had the purple near the horizontal line there. So 2 sections of Unit-3. And do that give you quite different pressure results? Or -- and I can't remember if there were completions above and below that purple line?

Yes, they are 2 separate compartments separated by the purple fault that would appear at the moment. I must point out, this is very preliminary, I'm just trying to share with you my thoughts. The dips are rolling over very substantially through the well on the default repeat as above the purple fault, but it is full of oil. We did try to test it. We had a number of issues with trying to pick where the net would be and then it seems to be so heavily fractured, but the piece was a little -- it is more like the upper part of where Unit-3 is where I say Amistad Unit-3 under the purple fault. So we've had that piece pushed up and over itself. But this well has shown that there's oil both below the purple fall updip from Alameda's Unit-3 and there's oil above the purple fault in the next lever up. So it's not a long way to draw to say that each of these levers is going to bearing with no water involved. And what we need to do now is understand the actual stratigraphy within the Unit-3 sensor sector, and that's going to be made a little easier by they're having this well at Amistad now we've just gone through that. Building an understanding of the facing changes within each of these sheets is coming next, and there will be some form of internal stratigraphy from the base of the Unit-3 through to the top seal of the [indiscernible] that we keep defining the top reservoir of. So I hope that answers your question. We are rolling over, we are in a falling cutoff there where we've intersected it with this well, but the zone above the purple pulp is full of oil as well.

Can I just add to that, Lawrence, that we don't actually have any pressure information that we've been able to achieve from this well as well. So we're not certain what the pressure differential is between what was previously referred to as Unit-2, which is the upper fault repeat of Unit-3 and below the purple fault at this stage. That was simply just due to the fact that the XPT tool that we ran, we couldn't get any valid formation pressure information out of it.

Thank you, guys. We'll just go on to the next attendee question now. So I'll throw it over to user Ben E. Attendee Ben E, we've just sent your prompt if you're online.

First of all, congratulations. Second of all, it's a two-part question. Errol's mentioned the other well pads being set up for approval at the moment. Do you one for see this as being an independent project from the lower intervals? Second part of that is, are you confident of starting to put holes in this structure before you get 3D done over the entire field? And then obviously, the mention of the other share rig that just need a little bit of work on approvals. Is that something you're keeping in the back of your mind as a rig to be used for this?

I'll take. We've got a number of pads that are short step-outs from the Alameda pad, and we're permitting them up for multiple objectives on each pad, both shallow and deep depending on -- because we started the approval process before we have the appraisal results. So, Errol has got enough seismic that he has given us the best sites to be able to drill more production wells close to these results with the seismic he has, and that's the immediate objective to do those to step up beyond this and in the years ahead and freely seismic I'm sure Errol [indiscernible] Duncan be to say, can we get that done as soon as possible. And let's get these production wells going and let's get the team getting kicked to start doing -- balancing up the various objectives. The other wells -- the other drill rigs, I beg your pardon, yes, we've got a number of options up our sleeve for secondary and tertiary rigs when you count the service rigs that are available in the country that let us do various things as well. So I think there were 3 parts to your question, and I've answered 2 maybe Hopefully, I got them all in that answer.

Yes. So just probably a bit more on the rigs that you mentioned. So what sort of support do you see from the Cuban government? Do you see other companies being tasked onto this to support the project? Obviously, it's pretty critical to the infrastructure locally all this production. So do you see directors going to other companies to make progress works with those rigs that maybe wasn't sort of originally going to be done or...

There's plenty of rigs in country. Some of that are being used for a lack of capital. We've got a project. We have the need. We're talking to all of those people, and we have great support from the Cuban government who's very excited as we are with the results from this project and their lending is correct support all the trucking, for example, it is all provided by the National Oil Company of Cuba. So they're turning up and helping us and asking what more do we need. And it's a great cooperative environment to work in a development field as fast as possible.

Thanks, Andrew. Just moving through to our third user question now. [Operator Instructions] But keeping it moving to the next attendee, Andrew. Andrew, we've just sent you your unmute prompt.

Just want to say congratulations for the results. Awesome to see flows finally. Just got two questions about future plans with the project. When do you think 3D seismic will be shot over Block-9? And what's happening with the current easement for the pipeline? Are the plans to refurbish the site and sort of bring in big pipeline into bringing crude out faster in that sense?

3D is already in the planning stages. And we're -- Duncan is talking to various companies. Some of who are already presented in queue and some who were abroad with the extent of what we want to do. That will take place as and when the field development plan gets approved by our Board and our partners, which has been tabled over the next month. With regards to easements and we are permitting up some options at the moment. We've identified some routes. The team on the ground is talking to the engineering consultants that we use for the pad approvals. There's a disused rail line near to us that goes all the way up to [indiscernible] which is the deepwater port, which is a very simple, low-hanging fruit corridor. That's not built on, not being used by anybody and we can run a pipeline up. But there are some other alternatives closer to the coast directly to our north, for example, which has got a deepwater oil terminal there. So a lot of my time is thinking about next year and the years ahead. Now all of this is being done by the gentlemen on the screen and some others you don't see.

Yes. Just on that, we're actually about to initiate a LiDAR survey as well where we will be actually flying a couple of alternative potential routes for pipeline as well.

Thanks, Duncan. Yes, we can still see some attendees there with their hands up in the waiting room. So bear with us, and we'll come to you. I just thought I'd go back to some of the questions that were submitted in writing prior. Next question for you, Duncan. One attendee asked, do you expect the lighter oil to be free flowing in the Alameda and Marti sections? And will you have artificial lift available in case for Alameda 3?

Yes. So let me -- our expectation would be that we've -- as the deeper we get, the hotter it gets and the more pressure that you'll actually encounter within the reservoir systems. And we know that those reservoir systems down there are already fairly highly pressured based on what we've seen in Alameda 1. My expectation would be that a lighter oil and a greater pressure should flow freely to surface. However, it's quite some distance, 3,000 meters to get it up to the surface. But yes, we will have potential for artificial lift mechanisms in case that it is needed. But my expectation would be at this point that we should potentially see free flowing oil to the surface from those deeper sheets. But we don't know at this point, and it's as simple as that.

Understood. Thanks, Duncan. Next written question for you, Andrew. One attendee writing with the knowledge gained from the extreme pressure buildup as the previous drill bit headed into the Marti location, what's been done differently this time to safely accommodate the pressures that will be encountered there by Alameda-3?

The main learnings we took away were to simplify the casing design. We now know what we're going down to. So we don't have to have as many contingency stages designed in the drill stream, which allows us to have something specifically weighted in casing strength and hole size, for those pressures and steps. We have a better BOP up on surface and manifolds rated to the pressures. We know that we're going to encounter down there. And the main things we're going somewhere we've been before, and we've designed accordingly generally.

Remember, gentlemen, the whole purpose of drilling this well Alameda-3 is to properly evaluate the N shape and I shape reservoir properties, which were -- we tried to do some things on the fly last time that were able to be completed like we would want per se heads. We are going back to redrill that section where we know the oil, we know the strategically, We know the pressures, we know where to set casing point. And all of this should ensure that we get some valid tests off in those zones. And that's the purpose of the world.

Look at Alameda-2 ahead of schedule without any material interruptions to the drill program that we forecast. Same reason. We knew we were going into, we designed accordingly. And we didn't have the surprises that we had last time.

Yes, absolutely. Thanks, Duncan. Okay. Moving from the written back to our attendees now, I'm unmuting attendee Justin for a question. Justin if you got that prompt, feel free to unmute yourself.

A just quick question. Now that you've discovered that you can produce from Unit-1B, is the plan to start A3 immediately? Or is that going to be postponed to allow some more production drilling in Unit-1B? And if so, what's the maximum amount of oil you contract from the pad given the current infrastructure sort of in terms of civil works?

There's no interruption to the plan to drill 3 next. Oil has taken a while to permit up. The casing has to be bought months in advance. The drill program has to be agreed with regulators to drill contractors. So A3 is happening next talking about happen after...

Okay. And in terms of tracking though from the site, what's the maximum capacity you go in terms of barrels a day?

I think it's 5,000 barrels a day we can see easily, keep that geared up for this. This is -- they have trucks running up and down the country, moving oil from one part of the country to the other part all the time and we are in the [indiscernible] maybe 30, 40 kilometers from the battery and the deepwater port [indiscernible] we easily there for the shuttle most. It's not the long-term solution. Obviously, we can get up to 5,000 barrels a day, liquidy-split, which I think we can. In parallel, we get these other infrastructure solutions permitted up and developed. It's like building a pipeline from the North West has actually in the center of Australia. And it's around the coast.

Thanks, Andrew. Yes, just moving on to our next attendee, Peter Devon -- sorry, there was just the technical difficulty at my end. Yes, Peter Devon. Thanks, Peter, we've just unmuted you.

Congratulations to the entire team. Wonderful stuff. And sometimes we wish you can just transfer share price a bit of rock under the, yes. Anyway, look, congrats for this So I think I've got two questions for -- probably, Andrew, I think will be best. I noted that you said that you intended -- it could be answered before you said you intended to return to A-1. So possibly we turn to A-1. So I'm interested into the rationale behind that. And also to -- early days I know, but I'm sure [indiscernible] you would have been looking at costs. So I wondered how much-- like, what ballpark figure present a barrel to the market?

So Alameda-1 was and is, I should say, slated for plug and abandonment as the next work program of this pad. But there is some tension that I'm encouraging between our geology team and our engineering team because this well goes, as you can see, straight through. These upper cheap formations, it goes all the way down. But certainly, in these upper sheet formations zones that zones now we know something new about it showing the question out there, this is another easy quick potential producer to bring online at the same time, are there other uses for it that geology team would like to reenter it to do some other tests? And as we saw the Unit-3 separated by purple fault, we could learn something different. Now we know that we can learn back on that. So there's some value there to be discussed. But the tension hasn't quite played out. So I think that's meeting this morning, I didn't attend.

Yes, we had a good meeting this morning. So it's -- robust discussion in progress, I think, is the greatest way to put this.

So that's part of your question. The second part of the economics of the production, we're in the appraisal testing stage. So we're doing everything gold-plated and more expensively. The best data I've got to answer your question is to look at another public company. Our drilling contractor, in fact, share it who have been produced over 200 million barrels of oil in Cuba over the last 25 to 30 years. And they've done it almost entirely from these upper sheet formations. And they've reported over that time that their average cost of exploration and production was about USD 10 a barrel. Now their last reported number was, I think, 2018 such and inflations done what has done since then. So I don't know, say $20 a barrel, has it doubled, but it's still one of the lowest quartile cost producing environments in the world, Gulf of Mexico and certainly being onshore Cuba appears to be no different to that.

Thanks, Andrew. Just one more question from our round of attendees. I note Lawrence still has his hand up. Just in case Lawrence wants to ask a follow-up, we'll just check Lawrence are you there? Did you have a follow-up question?

I do. Thanks for that introduction to the debate with respect to Alameda-1, it's a high-quality problem. I really commend you to that task. But with Alameda #3, would you still regard the Alameda formation and the Marti formations as you primary objective? Or is there one over the other? And I did try to read up on Marti #5, which was drilled a long time ago and had live oil and relatively lighter oil as well. I'm just wondering what -- how does that fit in the picture of the overall thing because of the excellent result now of the 1B result and, of course, Alameda-3 with these different compartments, there's so much to go for. So can you primary target and the other ones not...

I think, Lawrence, the answer is more like you prefer your son or your daughter, but Errol, maybe give a crack on that.

The Amistad sheet -- the upper sheet is well imaged on the existing 2D. So it makes good sense to actually design a near surface, upper 1,000 meter program to go around the place with the existing seismic we have and banks relatively cheap shale holes in it to confirm their models and establish some sort of lateral productive sort of understanding. So that becomes a target project in its own right. And preliminary maps that have been made on this upper sheet put the areas of being over 30 square kilometers and what you can turn around and saying is that's going to require an excess of 30-odd wells could be planned to look out. So there's a lot to do. But you can't drill all those wells on existing seismic. So you got to have the 3D, but we could get started. But the deeper section represents the larger part of this duplex. And the fact that 700 meters of oil soak limestone was unearth in Marti-5 without them properly testing any of it and really realizing any production from it. Points that this section is productive and full of oil, even deeper than where we got to in Alameda-1. You've got to recall where you sort of got into pressure issues with the base of Alameda-1 intersecting one of the many thrust faults separating it from Marti. It's markedly higher pressure, but we're not even sure we believe that now because of some of the what things they had, some of the drilling practices they had in force in Marti-5 was. Marti -- they might watch for wrong.. So what we need to do is properly evaluate and learn about this deep section because this may be the big memo that Cuba has been looking for is actually what is down in the deep section. So we need to learn more about that. It's certainly -- the elephant in the room on every seismic section you pick up is what's going on in the deep detection.

Thanks, Errol. Okay. That rounds out a list of attendee questions. Maybe just switching back to written for now. One written question that came in, Andrew, for you noting that we're really getting into the teeth and the details of the project now. But one attendees asks, in terms of possible development steps now from the Alameda-2 results, would these be concentrated on the best quality or highest flowing oil in the Amistad unit or kind of multiunit level completions be developed within 1 well?

Not within 1 well. But of the 1 pad, certainly, you can have both shallow and deeper wells at different trajectories. So they're not inferring, getting the upper and the lower. And that's part to my earlier answer. We've got multiple new pads being permitted up, circling this existing pad with good prospects in shallow And so we've kept our options open. We've seen these results. We can start work on the upper sheet wells now that we'd want to put in for more production. And once we start to see some results from Alameda-3. Errol and Duncan will say we love these ones the best, and we'll have a deeper well for next year as well.

Yes, we still don't know what the front-runner project needs to be because we haven't tested the deep sheets at all. We're going to take a big uptick with what we found in the upper sheets. But the lower sheet, remember, they got us excited last time. So we want to see everyone have its chance to put its hand up to be the main game.

If I could add also that the 4 new well pads that we've actually got out there permitting was the strategy behind that was to maximize what we can do, utilizing the existing 2D seismic as well. So -- and the philosophy behind that was each pad having like Andrew has already mentioned, a deep well and a shallow were well. And effectively, we've been thinking around the ideas of the best way that we could, if you like, bracket, a shallower level kind of development whilst we're still appraising the deeper section. So we have been applying a lot of thought to this with the information that we have. And it's -- the information is certainly being borne out by the well that we've just drilled, and we're really looking forward to the Amistad-3 to get on to the what could potentially be a much more sizable price than what we've already discovered in this particular Amistad zone?

Thanks, Duncan. Okay. Yes. We're still getting plenty of interest from our attendees, which is great. So I might just drop back to the floor and for some more live questions. This time user, just a set of initials here, but user AP. We've sent you your prompt if you're online. We'd just wait for AP to see if they go live.

Can you hear me now, guys?

Yes, we can. Thank you.

Awesome. So my interpretation is obviously that this result is fantastic from a drilling point of view. Just wondering how the market views Cuba's ability to process the amount of oil that you guys are going to have. So my question is sort of two parts. Is there the ability for this oil to displace the Venezuelan imported oil that comes in? Or alternatively, if they don't have enough domestic refining capacity, is there an ability to go and fill up [indiscernible] or any of the other Mexican ones will they gladly take on this oil and process it as they would their own, i.e., is there near distance refining capacity?

Good questions, ones that we're looking into ourselves, quite a lot in talking with the Cubans and other refineries through our oil trading contracts at the moment. Cuba has a number of own refineries operating below capacity because they need a certain quality of crude in order to be able to process and what they're designed for what we're finding here in Amistad, this 19-degree start is suitable for refinery in the Cuban refinery that is otherwise [indiscernible]. So that's encouraging. The heavier stuff. Yes, yes, that's the stuff that they tend to bring in from Venezuela because it's the heaviest stuff that they gear up for using to fire their electricity grid in the country. And that can be displaced by the heavier stuff we're finding in this Unit-1A and Unit-3. So there's a number of different answers to your questions here, but for the regional refineries. The main game. A lot of the refineries around the Gulf of Mexico are geared up for heavy oil because that's typically what there was a lot of now that -- there's less a bit of that on [indiscernible] historical elements, U.S. Gulf state refinery is not having access as easily to Cuban and Venezuelan oil. An interesting price, supply/demand dynamic discussion to be had here, but it's too early to say more than that, but it's intriguing. I broke the webinar with that answer today.

You broke it, Andrew.

He didn't make anything, apologies, Andrew. That was me the host leaving myself unmute, which is probably bound to happen at some point. So just keeping the attendee questions going now. Attendee, Peter you've got your hand raised. I've just sent you your unmute prompt, so wait for Peter, are you live now?

Yes, yes. Can you hear me?

Yes. Thank you.

Yes. Just a quick question on and congratulations as well to the whole team. On Amistad Zone-2, which in your today's interpretation was basically missed in Alameda-2. Would you be tempted to test it on the way to Marti or on the way back since you're going right through it?

It sounds like an old geologist asking that question.

[indiscernible]

I might just say very quickly that we are very much reassessing what we can do with Alameda-3, and we're having robust discussions about potential for testing in particular, Unit-2, in the next well in Alameda-3. We're also -- like Andrew has already mentioned, we're also looking at the potential for seeing what we can do in the original Alameda-1 well before it's [indiscernible]. So all of these things are now in discussion about ways of doing it. So to test these zones on the way down, we don't want to interfere with the current well design that we've got because the first and foremost objective of Alameda-3 is to successfully and safely test the deeper zones in the N&I sheets. but we can be opportunistic. We've just got to get our heads together and work out the best way and the most efficient way that we could potentially test these zones on the way down. We do have some test...

[indiscernible] that I'm more bent on getting production revenue in as fast as possible, and my [indiscernible] scientist want to learn more things. So absolutely...

It's a friendly tension. But yes, so I hope that answers your question. But yes, nothing is off the table currently.

Yes. Thanks, Duncan. Moving on to our next attendee. Simon Carpenter. Simon, we've just sent you an unmute prompt.

Thanks, Mike. Congratulations, I must say, it's a little bit -- it's great news, but it's a bit disappointing with the share price. I mean we've had such great results, and I feel like we're only back up to what we were 3 weeks ago. It's a great lesson learned for me of how the market reacts, and we get great results that falls off an absolute cliff. We get even better results and we're barely back to what we were before. This has gone first investing on end in the game of well construction for 26 years. And I never thought finding more reserves was a bad fee, but I've certainly learned a lot about humans in the market, that's for sure. But have you got any comments on just maybe the way that the previous notification came out or any lessons learned. I mean if we didn't have the previous announcement, and we just went to this one would the shares be $0.12 a share instead of just back up to 8.8%?

We are governed by listing rules, and we have to say things that we think are material when we know them on a continuous basis. So there's no holding bad news back or complicated news back. And this is a complicated story. And what it is, is a massive discovery or massive prize and there are things learned on the way through hard to interpret, let alone explain within the confines of listing rules where we have to take certain things, and we can't say certain things. So looking back over the past would we have done things differently here and there at the margin, the communications could be better. This is why we do forums like this. This is a big demand on our time and my people are very busy. But we want them in spirit as well as in the letter of the law trying to inform the market of what we're seeing and what we're doing and the old soundbites the market is always right. So hard to believe at times I agree, but all we can do is put information out there. It's honestly and as accurately as we believe we can.

Thanks Andrew. We'll keep moving through our attendees, starting to get a little bit tight for time over the hour mark. But I think what we'll do is move on to a couple of more attendee questions and then run things out with a couple of more questions from the written list submitted. So I would just send unmute prompt to our next attendee, Jasper. If Jasper is there.

Yes. This question for Andrew. I know you came to produce good revenue. Do you think we need money -- more money turn to develop it. I know we've got about USD 45 million or $45 million in the bank as of 30th of June. Just want to say your thoughts on that.

No. We have enough money for this appraisal well program. We're funded for beyond this appraisal well program. So I don't have to think about that. We've got plenty of other things to think about, but money is not one of them, fortunately. Thank you for the support of shareholders like you so.

Thanks, Andrew. I'll just check in with our attendee, Andrew asked the question, but left his hand up. Andrew, if you get unmute prompt. Yes Andrew, did you have a quick follow-up?

Yes. Just regarding to the expectations with Alameda-3. I understand there's a lot of difference between results of Alameda-1 and Alameda-2 going to the up sheet, going sort of fractions. Do you expect a similar result in Alameda-3 compared to Alameda-1 fractures in the low sheet?

It's one for my colleagues. I don't think we are as successful in getting all the logging results if you look previously in those lower sheets will be, Duncan?

No, we weren't. So we're expecting that given that we'll have much better hole conditions that will get much better logging results, much better, higher quality logs, which is one of the biggest things that's helped us out here in Alameda-2 was the fact that the hole conditions were perfect, and therefore, we got good quality logs that you could possibly get. And therefore, we've been able to drive a lot of information from, in particular, the FMI log, which has helped us out with being able to pick out the fraction zones in particular and also see the texture of the rocks and the permeability and the porosity as well that we've been able to measure from the logs. So I would be expecting similar results when we drill down into these sections. The pressure will be on our drillers, obviously, to deliver another wonderfully drilled hole. But once we get to that point, then we'll have a much better idea of what we're actually dealing with.

Good one. Thanks, Duncan. And I'll just throw it over to our attendee, Ben E, who asked the question, but kept their hand up in the queue. Ben E, we've sent you another promp. Yes, Ben, Did you have another follow-up question for the team?

Yes, I do. This is for Duncan. It's probably more related to what you saw on the flow testing. I'm just looking for the announcement, apologies if I missed it, but have you got any surface pressures shut in and flowing? I note you did 3 shut-in -- or 2 shut-in events after the cleanup. Did you see the formation recharge well or...

Yes, we did. I don't have the actual numbers here in front of me. But yes, the formation behaved in an exceptionally good manner. In addition to the lower section in particular in 1B, which we perforated, which is highly fractured, the upper section of 1B actually did have good primary porosity and permeability. And that was basically reflected by the way that the shutting -- the well -- the behavior and the shut-in periods with the well. Sorry, but I don't have those numbers conveniently at my fingertips. But suffice to say that, yes, it behaved very well.

Thank you, Duncan. And perhaps last question from the floor, I'll just go back to our attendee, Peter. Sorry if I'm pronouncing that wrong. But Peter, if you had a quick follow-up for the team, just bringing you back live again now.

No, I don't have any quick follow up.

Maybe I see Tom like had his hand up for a while. Perhaps if we have one more question, you can ask.

Yes. Sorry, Tom, I missed you there. Just sending your prompt now, Tom. Yes, you're live. Thanks, Tom. Tom, I hope we got you there. Tom should be live, but I just got some technical difficulties. Tom, are you live now? Tom Sorry, just some technical difficulties with Tom, but I might try again with Tom shortly. But perhaps I was going to go back -- I mentioned that we're getting on in terms of time, but just round things out with a couple of written questions. And perhaps for you, Andrew, just stepping back because we've delved pretty deep into the technicals of the project. Some of the broader written questions. One was a little bit of a devil's advocate, but one attendee wrote, the recovery rates of the oil in place in Cuba do seem low compared to other reservoirs. Is there something the company can do to improve recovery rates, pumps or other secondary recovery method? So I thought Andrew I just throw that one to you. That was one of the written questions that came in.

I think perhaps the question might have meant by recovery rates, the flow rates and maybe before this morning's results. But yes, there are a number of assisted lift technologies that are employed, not just in Cuba, but in all fields all over the world. The main one being in these upper sheets because of the heavy fracturing that we've been talking about. They've learned a long time ago to drill their wells at right angles to that dominant fracture formation. So it acts like natural little conduits for the oil to flow in, and horizontal wells flow typically in Cuba about 3x the rate of their wells. So if we look at this peak 2,000 barrel a day result from this well, from one small section and then think about, well, could you put a horizontal well in that or even if that didn't work, you just put pumps down there on rolling back is on the top, this is all technology and oil field wells and all stuff the engineers can do.

But it's great because I'm sure, we can do anything we want to be able to well from the surface to intersect anything we please. And we can employ all these artificial lift systems. This is not offshore. This is onshore.

Noted. Thanks, guys. Look, I'll just go back to attendee, Tom Bleakley, on the floor. I'll see if we can get Tom on this time. Tom, I've sent you another prompt. So we can see that you're live there, Tom, just can't get any down coming in. And I'm not quite sure why we're keeping Tom quiet here, which is a bit of a pity. But yes, my apologies, we'll have to blame that one on some tech difficulties for Tom. So maybe, again, just rounding things out with a broader question, starting with Andrew, but some in light of today's update, one of the attendees write, do you still consider Block-9 to be of using the catch phrase of global significance?

I've had a lot of questions on this and It's not meant to be a scientific comparison, but it's a 5 billion, almost 6 billion barrel oil in place reserves from one well at the western end of a 2,500 kilometer license area in a demonstrably prolific hydrocarbon system onshore in one of the world's great hydrocarbon systems. So we've got hundreds of millions of barrels of reserves already, and we've only just started. That's world-class.

Yes. Look, thanks, guys. I appreciate that. And I think this forum has given us an opportunity to delve into the details of the project pretty thoroughly today. And we just ticked over the 1 hour 15 mark. So we might conclude today's webinar there. But thank you to Andrew and to Duncan and Errol for the presentation and for again taking the time to answer questions. Thanks also to our attendees and everyone who submitted written questions prior to that live Q&A. Our apologies if we didn't get to your follow-up question or where we had some technical difficulties today. But as usual, I think the number of attendees on the call and the number who put their hand up for a question is again testament to the ongoing level of interest and engagement among the shareholder base. So as mentioned earlier, as usual, a recording of the webinar will be on Melbana's website, social media channels distributed just later on today, so you can watch a replay. Perhaps just checking with Andrew and the team, are there any final comments that we might have skipped over that you guys wanted to add?

No, I think you've given us a good work.

Nice one. Excellent. Okay. Well, that wraps things up for today. Thanks again to everybody, and we'll see you again soon.

Thank you, and thanks to my colleagues.

Thank you, everybody.

Thanks, everybody.