Good morning, everybody. This is John Hamilton, and welcome to our trading and financial update for the first quarter of 2021. I'm joined today by my colleagues, Richard Morton, our Technical Director, Nigel McKim, our Projects Director, Qazi Qadeer, our CFO. Take us through some slides, following which we'll be open for some Q&A. As a reminder, today's conference call contains certain statements that are or may be deemed to be forward-looking statements, which include all statements other than statements of historical fact. Forward-looking statements involve making certain assumptions based on the company's experience, perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate to make under the circumstances. Although we believe the expectations reflected in these forward-looking statements are reasonable, actual events or results may differ materially from those projected or implied in such forward-looking statements due to known or unknown risks, uncertainties, and other factors. The current slide you're seeing is the way in which you can ask questions, either during the slide presentation, in which case we'll pick them up if you write them in, or you can raise your hand using the hand icon, and we'll try and take your verbal questions as well. Next slide, please. A quick overview of the company. We believe this is our most important quarter ever in the history of Panoro. We completed the acquisitions from Equatorial Guinea and increasing our stake in Gabon. That transaction should close soon in Gabon. What we have now is what we believe to be truly a full-cycle E&P company. We have operations from the north of Africa right down to the tip. In South Africa, we have production diversified across three different countries. We have 2P and 2C resource number in excess of 70 million barrels. We have a long reserve life on our assets, and we hope to be producing somewhere in the range of around 9,000 barrels a day during the course of this year. We believe through these transactions and over the past couple of years, we have built a very sustainable business in E&P in Africa. I'm very proud of that. Next slide, please. Some of the key messages we want to get across in terms of the equity story here are three key messages. One is that we're in production growth mode. We have organic production growth in our portfolio. We hope to be producing around 9,000 barrels a day this year on average. We drilled five new production wells still this year, Equatorial Guinea and two in Gabon to be brought on stream. We hope to have an exit rate in excess of 9,500 barrels a day at the end of the year, and we're on target to produce in excess of 12,000 barrels a day during the course of 2023. We have within the portfolio production growth. We also have near-term triggers. We have an exploration well in Gabon at Hibiscus North. We have an exploration well in South Africa, which we hope to drill by the end of the year. We also have the PetroNor dollar dividend, the dividend with PetroNor shares, which we hope to complete that transaction in the near future. On a cash flow basis, we can start being judged now on a cash flow basis. We have very strong free cash flow in this business. We are fully financed for the growth that we have announced, and we're well-positioned to pay dividends in 2023. These are the key messages we want to get across. Next slide, please. On a pro forma basis, our 2021 first quarter highlights, we obviously announced the transformational acquisitions. Group net production was 8,000 barrels a day on a pro forma basis. By pro forma, we mean including the effect of the increased stake in Gabon and the new Equatorial Guinea. we have production growth activities across the portfolio, which I'll touch on. We had a big quarter in terms of liftings. We had three crude liftings, one in Tunisia, one in Gabon, and a big one in EG, a $59 million cargo in EG. Although it gets kind of repetitive to talk about these days, we still are working in a COVID environment, and we're pleased to say that our systems, our health and safety record, and our protocols have proved again resilient in the quarter. On the financial side, you can see the effect on a pro forma basis of our revenue line and also our EBITDA, which is $25 million. That's been reduced by $31 million simply on an accounting basis, given the overlift Equatorial Guinea when we lifted that cargo. That will unwind during the course of the year. It's hard to look at it on a quarterly basis because of that overlift, but it gives you a feeling on the EBITDA side about the strength of this business now with very strong numbers coming through, which you'll see again, that overlift position from an accounting perspective unwind that $31 million recovered back into EBITDA. Again, we have a lot going on our balance sheet at the end of the quarter. It's kind of hard to describe it because we have all the movements around the completion of the acquisitions and drawdowns of debts and all that. We also have this huge receivable, $59 million from the cargo we lifted in EG. We receive the cash for that now in April. That the balance sheet is quite different as well. Next slide, please. Here are the financials in some more detail. I won't go into them in a huge level of detail here. As you can see, what we're doing is we're reporting our IFRS reporting in one column, showing the effect of the pro forma of the acquisitions and on a pro forma basis, showing the financials, where again, you can see $77 million of pro forma revenue with EBITDA of $25 million. Recognizing the $31 million of uplift that comes through. We're in a very strong position financially. Next slide, please. What we'd like to do is take you through, at a high level, each of the assets we Equatorial Guinea, we produced net to Panoro 4,300 barrels a day. On a gross basis, this is 30,000 barrels a day, which is exactly on target from what Equatorial Guinea now represents more than 50% of our production. This is now our most important asset by far in terms of production. What's quite Equatorial Guinea, we believe, is that we're really on the cusp of the operator finally drilling new wells and trying to boost production here. The past three years, the operator, Trident, bought this asset three years ago, and they spent those three years upgrading the facilities. They've not drilled any new wells, and in fact, there's been no new wells drilled in Equatorial Guinea since 2015. The real task from when they bought the asset from Hess was to improve the infrastructure and work on debottlenecking, if I can put it this way, boring stuff, arresting decline on the wells, looking to do things smarter and better. Now it's the harvest time, and the first of those will be three wells to be drilled this year. The first will spud in June in the Alen field. Again, these are the first wells to be drilled since 2015. I mentioned the cargo that we already lifted, which was brilliant. We had a $59 million cargo one week after completing the transaction where we paid $88 million for this asset. Again, you can show at these oil prices how cash generative this can be for Panoro. The Okume Upgrade Project is nearing completion. There's additional power, water injection, and gas lift capacity being installed. Again, things that are improving production and the operations. We also have commenced the second phase of the ESP program there. We're going to start seeing production growth in those assets during the course of this year. Perhaps just as importantly, the JV is very focused on production growth in 2022 and beyond. We're really, again, at the point here where the joint venture is now focused on boosting production, having spent three years investing in this asset. Next slide, please. In Gabon on a pro forma basis, we produced 2,380 barrels during the quarter. That includes the effect of the additional 10% from Tullow. Mainly this was production from four wells. As those of you followers will know, we are busy now drilling the Tortue production well, DTM-7. The well is ongoing now, and we plan to hook that well up and DTM-6H, which is the well we drilled right at the time when COVID really hit, and bring those online during the end of the third quarter, probably, at Tortue. We should see production growth coming in towards the back end of the year in Gabon. We did one lifting and that's 56,000 barrels during the quarter. That number does not include the effect of the Tullow 10%, but just the pure Panoro one. The Hibiscus/Ruche development, first oil is now targeted for the fourth quarter of 2022. BW Energy, the operator, announced their results last week and the good news here that we've moved up the first oil target from that development from the first quarter of 2023 down to the fourth quarter of 2022. There's been some very good news, very good progress on that particular project, which will see production get towards the FSO capacity of 45,000 barrels a day or more. We're going to be drilling the Hibiscus North prospect in the third quarter. We have another exploration trigger in there. The Hibiscus Extension well we drilled in May did not encounter hydrocarbons. Lastly, we're expecting the closing of the Tullow acquisition during the second quarter. In other words, in the next couple of weeks. We look to complete that one soon. Gabon now represents approximately 35% of our production. Tunisia. Next slide, please. Tunisia, we produced a little over 1,300 barrels a day net to Panoro, 4,500 barrels a day gross. Production is frequently in excess of 5,000 barrels a day. Over a period of a quarter, you get certain shutdowns of wells or temporary shutdowns that might impact the average over a quarter. It's fair to say that production is frequently in excess of 5,000 barrels a day. I think it really demonstrates what we've done since we've taken over the asset, where we've managed to boost production by 30% or 40% from the time that we bought it from OMV. Again, we're very happy with our Tunisian asset and the production growth we've managed to achieve. We also had a lifting in the quarter for about 96,000 barrels at about $60 a barrel. We continue with the production growth story in Tunisia with workovers planned and aligned and sort of seeing out the ones that are right in front of us now. We hope to be able to continue the production growth story in Tunisia as we go. We're also looking at the longer-term potential of the asset. We're working with ETAP, our partner, to update the subsurface models and plan further developments in some of the fields, including, most importantly, probably the Houmt Souk field, although this is true for all of the fields in Tunisia as well. Next slide, please. In South Africa, we recently announced the completion of that transaction. We got the ministerial consent there, which is good. It took a little while to come. The focus is now really on getting out to the well and procuring a rig for the Gazania-1 well, which we hope to spud by the end of the year. This is a very significant prospect. It's an existing discovery, an AJ-1 discovery made back in 1988, back in apartheid times. What we're trying to do here with this well is to come up dip of that and targeting two different geological prospects within this basin. It's coming up dip from the discovery. In a success case, it has the potential to be in excess of 300 million barrels gross in terms of prospective resource. It's a very meaningful well, and again, we hope to spud that well by the end of this year. We have a very interesting exploration trigger later this year in South Africa. Next slide, please. This is our guidance. This is unchanged from what we provided at the time of our February Q4, our 2020 results. We haven't changed anything here. The production around 9,000 barrels a day, again, benefiting from the fact that we have diversified production from three different assets here. We've not changed our production guidance. On the capital expenditure side, we've not changed this number. In particular, Gabon is a little susceptible to exact timing differences because the Hibiscus redevelopment is an 18-month project, basically. Exactly when CapEx gets spent, whether it's in December 2021 or January 2022, we might find some differences in these numbers. Overall, in the next couple of years, I think we provide a good guidance on the CapEx on that. We've not amended our CapEx guidance. A number of liftings, we've also not done that. We had three liftings in this quarter. In the second quarter, we will have two liftings in Gabon and one in Tunisia. The fourth quarter is when we probably have another EG lifting. That's probably a 650,000-barrel lifting probably in the fourth quarter as well. As one can see Equatorial Guinea lifting that we've just had, those are quite lumpy affairs when they come, they're quite big numbers. When they fall exactly in the quarter, we recognize revenue at the time of lifting. You could see on a quarterly basis, some quite some difference, but an important thing is to look out over a period of a financial year. Next slide, please. Here's a summary of the near-term triggers that we have and everything going on in the company. Again, in Gabon, we're drilling the DTM-7 well, hooking up DTM-6. That all happened probably towards the end of the third quarter. We are drilling an exploration well in Hibiscus North. We plan to drill wells every year in Gabon. The Hibiscus North prospect is unaffected by what happened in Hibiscus. It's a very robust structure, and we're looking forward to drilling that Equatorial Guinea, as i mentioned, the first three infill wells are being drilled this year. We will see this trend, we believe, continue into 2022. Those additional wells in EG have not been sanctioned yet by the joint venture. That typically happens in the third quarter. We would fully expect to see a number of production wells being drilled every Equatorial Guinea, trying to again increase production there. In Tunisia, we continue with our well workover activity, so it could be some new flow there coming through on the production side. We have the Panoro dividend, which we intend to distribute to our shareholders upon completion of that transaction. We have the exploration well in South Africa. We have a busy year ahead of us. Next slide, please. Just a comment on where we are currently in terms of our market cap, which has obviously taken a bit of a hit on the Hibiscus extension well, the strengthening of the NOK, perhaps some other factors as well in there. Our market cap has come down quite a bit from where it was prior to drilling that well, which is surprising to us. What we've done here on this slide is to kind of just take some of the analyst projections, take an average of where we see the analysts pointing and trying to compare that against our market cap. What you can see here is on an operating cash flow basis, at $60 Brent, we'll be generating over the next three years, $260 million, according to the analysts' assumptions, again, an average of them, and $450 million in operating cash flow over the next five years. If we look at free cash flow, which the only difference between the two really is capital expenditure. We're obviously spending quite a bit of money in Gabon at the moment for the Hibiscus redevelop. You'll see over the next three years that we'll be generating about $150 million of free cash, and then if you look over the next five years, considerably more. When you compare that against our market cap, we would argue that this is quite a compelling valuation story. I don't think you'll find many other companies with this kind of cash flow versus market cap dynamic. The analysts are estimating free cash flow yield between 20% and 40% over the next four years as we go forward. The important point is we have free cash flow really starts taking off in 2023 as we get through CapEx period in the Hibiscus redevelop. We're going to become a very strong free cash flow generating company. Beyond that cash flow in that period, we obviously plan to pay dividends. We're fully financed. We have a reserve life that is well in excess of 10 years here. We've got 33 million barrels of 2C resources, which are not included in any of these assumptions. We don't include any contingent resource in our production assumptions, in our cash flow assumptions. Those are things that are not yet been sanctioned to be produced, and most of those Equatorial Guinea. we can come back to that, perhaps, in the Q&A. Considerable upside here from these numbers. On top of that, we have other triggers every year. We have exploration wells each year, and we have a growth strategy to complement the return of cash to shareholders. We think we have quite a dynamic company that's going to be a significant cash flow generator with many other triggers on it, against a rather, what we believe is a modest market capitalization. With that, I'm finishing up, and I will open up to questions. Qazi is going to chair the questioning. Again, as a reminder, you can either raise your hand using the icon, or you can type in a question to the question panel. We're happy to take questions, and my colleagues may join in some of those as well. Thanks, John. We have a question from Stephane Foucaud. I'm going to open the line. Stephane, you may speak now, please. Yes. Hi, guys. Morning. Two questions for me. First, an accounting one, the $67 million current payable, I assume that refers to the expected payments of Gabon on closing. That's my first question. My second Equatorial Guinea. i was wondering whether, one, the three wells that would be drilled in 2021 would have an impact on reserve, particularly whether some of the 2C are being targeted. Related to EG, how do you see the potential additional reserve booking moving forward with this 2C conversion? Is it a progressive affair, or would you see a point where you would be starting sanctioning a hefty drilling program that would suddenly boost the 2P reserve? Thank you. Qazi, you want to take the first one on the payable position, and then perhaps Nigel or Richard can answer the EG one, and particularly the conversion of 2C to 2P reserves? Yes, certainly, John. I will start with the payable position. The explanation for that, Stephane, is the consolidation Equatorial Guinea business, which was supposed to be at fair value as of the completion date of March 31st. As part of the acquisition, we have done two things. One is that we have acquired all assets and liabilities at fair value. By fair value, I mean that all the over lift position were also revalued as well. We mentioned about a $31 million over lift position, which basically ends up in a kind of a accounts payable or trade payables liability as well. Hence you would see a jump in the payables, but we expect that to unwind as we produce more and replace it within inventories. A few other things on this, you are correct that our payable, we haven't booked the Gabonese payable yet. That will only happen on completion. There are some items like deferred consideration of $5 million and some other payables in relation to the implementations that we need to do in the future inside Equator Guinea. Right. Richard and Nigel, do you want to take EG? Nigel, do you want to start? Maybe Richard can jump in as well if necessary. Certainly. On the question of drilling campaigns and reserves versus resources, what has been booked as a reserve on this asset is committed projects. The forthcoming Alen three-well drilling campaign is part of the reserves that we carry for the asset. We recognize there's significant additional drilling potential in this asset, and John mentioned the substantial 2C resource that we have, that we carry on the project. The nature of the work on this asset is that there's an awful lot of subsurface work on the go at present to work up and prioritize future drilling targets. The nature of reserves bookings is that we cannot book those opportunities as reserves until the joint venture partnership have committed funds and agreed to drill those opportunities. We will be progressively transferring 2C resources into reserves as those future drilling programs mature. John touched on the fact that we believe late in 2022, there's going to be a further drilling campaign on this asset. The joint venture partnership have not committed to that as yet, but we envisage that will happen during the course of this year. Indeed, beyond that, we already see an opportunity for a further drilling campaign out in 2023. Those are notional plans at this stage that will mature over time. Thank you. Maybe what you're saying is that there may be a sanction taking place in 2021, which will have impact on open reserve, and then there will be some more later down the line. That is correct. Yeah. Okay. Thank you. Thank you, Stephane Foucaud. We have the next question from Teodor Sveen-Nilsen. Teodor Sveen-Nilsen, I will open the line now. You may speak, please. Good morning, guys. I have three questions if I may. First one, just on as far as I understand you all, of course, you have already received the cash of the EG lifting in Q1, and that you also have lifting in Q4. Could you indicate the expected size of that lifting? That's my first question. Second question is on dividend level. Now, I think you were discussing that previously as well, but on what basis will you set the dividend from 2023 going forward? Will that be a% of free cash flow or EPS or some kind of other number? If also on how we should think around dividends forecast would be useful. The third question, could you just remind us of the pre-drill resource estimates for the Hibiscus North well and the Gazania well? Thanks. Sure. The first question on the EG lifting, we received the cash in April, Teodor, not in March, just to clarify. We sold the cargo in March, so it gets reflected in those pro forma numbers that you see. We received the cash in April. The lifting in EG in the fourth quarter is currently targeted for around November. We'll have to just see exactly when it falls. That's likely to be a 650,000 barrel lifting at the moment. The one we had in March was a 950,000 barrel lifting. This one is probably going to be a slightly smaller lifting, is our current estimate. That could change, and we'll certainly update you in the market when we have a little bit more visibility on that lifting and the parcel size. That's our current working assumption. Your second question, sorry, was? That was around dividend. How we should think about that. Okay. The dividend policy, it's a great question, and it's one that what we've identified, obviously, is with the strong cash flow we have, particularly at these higher levels. Again, we designed this dividend strategy around the time when we completed these acquisitions, and we designed it around a long-term oil price, $45, $50 a barrel. Obviously, at these higher prices, it's looking even better. What we decided to do is to just try and get through some of this CapEx, make sure that the Hibiscus /Ruche development is on track and all that, and to debate the dividend strategy, which we'd like to articulate to the market, because it's the right question to ask. We're not quite in a position to define it yet for you. Clearly, there's going to be, particularly at these oil prices, quite a bit of cash, and it's likely to be a metric along the lines that you've suggested. We're not quite ready to kind of define and frame that yet. That is very much on the board's mind to define that better. As you can see, there's quite a bit of free cash available to pay a substantial dividend. The last question is on Hibiscus North. BWE, the operator, have guided a range of between 10 and 40 million barrels of prospective resource on the Hibiscus North structure. It doesn't take much to be commercial here because we can tie it back in eventually. It's quite close by to Hibiscus, even the lower end of that range of discovery is highly commercial. On Gazania, Richard, can you refresh the memory? We have two different targets there. Yeah. In terms of prospective resource in that well. Yeah. Teodor, on Gazania, that well is targeting two separate stack prospects. The highest chance of success one is the Gazania prospect itself, which is 168 million barrels, and the one above that is called Namaqualand, which has got a lower chance of success, but that's slightly larger at 186. Combined, slightly over 300 million barrels. Okay. Thank you. Thank you, Teodor. The next question, we don't have any live questions, but there are some from the web. To kick off, this one is from Daniel at Stifel, which is, "Roughly how much do we expect Dussafu OpEx per barrel drop with the Ruche and Hibiscus on stream, both including and excluding the FPSO lease? Well, Daniel, the big operating cost in Dussafu is the FPSO lease. Obviously, there are other elements to operating cost as well, but it's largely a fixed cost. What you're seeing right now in terms of the operating cost being announced by the operator is as a result of the lower production at the moment. We still have to go through our growth now in the next couple of years. The unit cost comes down quite dramatically. I think the guidance once Hibiscus/Ruche is online is close to $10 a barrel, and that includes the lease. Really, there is some variable cost as your production increases, but the lion's share of it really is a fixed cost. The more production you bring across. You'll hopefully see operating cost per barrel coming down from the early $20s at the moment down to $10, $12 a barrel, something like that once Hibiscus/Ruche comes online. I don't have the breakdown of exactly if we exclude the lease, how much the operating cost would be, but it is by far and away the largest portion of that. The lease plus the O&M contract amount. Thank you, John. Another question. I think it was a good question. I hope it answers it. There is another one from Daniel Stenslet which basically asks about what would roughly be the OpEx per barrel for the EG assets if 2C resources are converted to 2P, and we see strong production growth from 2023 onwards. Nigel McKim, do you want to have a crack at the operating cost on EG if we're able to boost the production coming across the next couple of years? Yes. John, I don't have the numbers to hand on my fingertips, but I guess the important thing to say here is that the OpEx itself on this asset won't be increasing significantly with new wells. I mean, the beauty of this project now is that we've got a series of platforms from which to drill new development targets and processing facilities to tie those back into. The cost required will be CapEx to undertake the drilling and tieback operations. There would be some small incremental increase in the OpEx, but nothing significant. As we drill further tranches of development wells, we would expect the production to be boosted and the OpEx per barrel to be reduced proportionate to that production increase. I hope that answers the question. Yeah. I'm happy. Yep. Thank you, Nigel. We have another question about the Sfax Offshore. What are our thoughts about the Salloum West drilling permit? Yeah. It's a little bit the same as it was last quarter, which is we have plans to drill the Salloum West well in Tunisia that has been held up for quite some time now on government approvals. We've also had obviously COVID come in the meantime. We've been working with the regulator in Tunisia to try and come up with the best solution on that. I don't think it's a very near-term well to be drilled. I think COVID situation in most of Africa now is still quite live. The ability to get people in and out of the country from service providers things like that for drilling a well, is not the perfect environment to do it. We still have that thing on pause at the moment. We'll definitely update the market when that situation changes. Thank you, John. One last question from another investor. Equatorial Guinea which asks us to elaborate on what the operator is doing with these infill wells and how it may impact production levels. Nigel, I know you touched on it a little bit. Do you want to just address the question, which is just what is the operator looking at on these infill wells? Again, looking forward just to make sure we answer the question. Absolutely, John. Yeah. It's a very exciting stage in this asset's life, in fact. Typically, what one does at this stage in a project's life is create subsurface static models of the geology and run dynamic simulation models of the fluid displacement within the reservoirs. On that basis, you identify targets for new development well drilling. The rather unusual thing about this asset, and what makes it so fascinating, is that the seismic data is really very clear, and we can not only see the reservoir subsurface, but we can see fluid movement subsurface. In fact, we've just been involved in a meeting with the joint venture partners where that type of information is becoming apparent in a new set of seismic data that was acquired last year. The subsurface teams have created these dynamic models, and they're now beginning to bring in that seismic data that can show where the water is, where some gas breakout has occurred, and where the optimal target would be for development drilling of the wells. It's that work that's now informing the ranking of new development well targets for subsequent drilling campaigns. We're confident that we're going to be able to share more information on that in the months and quarters ahead as we begin to firm up those plans and sanction the forthcoming drilling projects. In the meantime, I think as part of your question, you're asking about how the infill wells will impact production levels. The total incremental production that's expected to come through at startup of those wells is in the range of 4,000-5,000 barrels a day. That's indicative of the type of impact that we can expect to see from these wells. Clearly, as modeling work proceeds and we firm up the next drilling campaign, we'll have more detail on precisely what we expect in subsequent activities. Thank you, Nigel. Thank you, Nigel, again. This was the last question I had. Hang on. There's another one from Auctus Advisor, I have opened the line. You may unmute from your side and please speak. Morning, Auctus Advisor Yeah. Morning. We have been waiting for the completion of the Gabon part of the transaction. Did you say now that you expect finalization of this within the next couple of weeks? Yes. Yeah. That's great. That's very good answer. Yeah. We always guided the end of the second quarter. It really just has to do with getting it through the ministerial consents, basically. That's all in good shape. We would expect to be able to announce the closing of that transaction certainly by the end of this quarter, and perhaps earlier. Yeah. Thanks. Okay. Well, thank you everybody for joining. We got a good-sized crowd here today, and very much appreciate everybody following us. Again, we're available if anybody has any individual questions, you can always come through directly to us. Again, thank you very much for joining. Goodbye.