Panoro Energy ASA

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 Qadir, our CFO, to take us through some slides following which will 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. uncertainties and other factors. So the current slide you're seeing is the way in which you can ask questions either during the slide presentation, 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. So a quick overview of the company. We believe this is our most important quarter ever in the history of Panora. We completed the acquisitions from Tullo in Equatorial Guinea and increasing our stake in Gabon. That transaction should close soon in Gabon. And what we have now is what we believe to be truly a full cycle EMP 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. So we believe through these transactions and over the past couple of years, we have built a very sustainable business in EMP in Africa. I'm very proud of that. Next slide, please. So 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've grown five new production wells still this year, three in Equatorial Guinea and two in Le Bon 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. produce in excess of 12,000 barrels a day during the course of 2023. So we have, within the portfolio, production growth. We also have near-term triggers. We have an exploration well in Gabon, which is north. We have an exploration well in South Africa, which we hope to build by the end of the year. And we also have the Petronor dividend, the dividend of Petronor shares, which we hope to complete that transaction in the near future. And 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. So, on a pro forma basis, our 2021 first quarter highlights, we obviously announced the transformational acquisitions Our 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 asset in 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 over-lift position in Equatorial Guinea when we lifted that cargo. So that will unwind during the course of the year. So it's hard to look at it on a quarterly basis because of that over-lift-under-lift, but it gives you a feeling on the EBDA side about the strength of this business now with very strong numbers coming through, which you'll see. Again, that overlooked position from the county perspective on one, that $31 million recovered back in through EPTA. And 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. And we also have this huge receivable, $59 million from the cargo we lifted in EG. We received the cash for that now in April. So 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, but 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, the acquisitions, and on the pro forma basis, showing the financials, where, again, you can see $77 million of pro forma revenue, EBITDA of $25 million, you know, and recognizing the $31 million of over lift that comes through. So we're in a very, very strong position financially. Next slide, please. So what we'd like to do is take you through at a high level each of the assets we have now. Equatorial Guinea, we produced net to Bonoro 4,300 barrels a day. On a gross basis, this is 30,000 barrels a day, which is exactly on target from what we anticipated. Equatorial Guinea now represents more than 50% of our production. So this is now our most important asset by far in terms of production. And what's quite exciting about 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. So 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 have been no new wells drilled in Equatorial Guinea since 2015. So the real task from when they bought the asset from Hess was to improve the infrastructure and work on de-bottlenecking, sort of, if I can put it this way, kind of boring stuff, arresting decline on wells, looking to do things smarter and better. And so now it's the harvest time. And the first of those will be three wells to be drilled this year. The first will start in June in the Elon field. And again, these are the first wells to be drilled since 2015. I mentioned the cargo that we've already lifted, which was brilliant. So we had a $59 million cargo one week after completing the transaction where we paid $88 million for this asset. So again, you can show at these oil prices how cash generated this can be for Panora. The Akume upgrade project is nearing completion. There's additional power, water injection, gasoline capacity being installed. So again, things that are improving production and the operations. We also have commenced the second phase of the ESP program there. So we're going to start seeing production growth in those assets during the course of this year. And perhaps just as importantly, the JV is very focused on production growth in 2022 and beyond. So 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, so that concludes the effect of the additional 10% from Tullow. This is production from four wells. As those of you who follow us will know, we are busy now drilling the Tortue production well, DTM7, which is the well that's ongoing now, and we plan to hook that well up and DTM6H, which is the well we drilled right at the time COVID really hit, and bring those online during the end of the third quarter, probably, at Tortue. So we should see production growth coming in towards the back end of the year in Gabon. We did lift one lifting in that 56,000 barrels during the quarter. That does not – that number does not include the effect of the TELO 10%, but just a pure panora one. And hibiscus roof development, first of all, 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. So there's been some very good news, very good progress on that particular project, which will see production get towards the FPSO capacity of 45,000 barrels a day or more. We're going to be drilling the Hibiscus North prospect in the third quarter. So we have another exploration trigger in there. The hibiscus extension well we drilled in May did not encounter hydrocarbons. And lastly, we're expecting the closing of the tillow acquisition during the second quarter. So in other words, in the next couple of weeks. So we look to complete that one soon. The bond now represents approximately 35% of our production. Tunisia. Next slide, please. Tunisia, we produce 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. So over a period of a quarter, you get certain shut-ins of wells or temporary shutdowns that might impact the average over a quarter. But 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 Olympia. So, again, we're very, 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. And we continue with the production growth story in Tunisia with workovers planned in Al Ain and Sarsina are the ones that are right in front of us now. So we hope to be able to continue the production growth story in Tunisia as we go. We're also looking at the long-term potential of the asset, working with ETAP, our partner, to update the subsurface models and plan further developments in some of the fields, including, most importantly, probably the Goubiba field, although this is true for all of the fields in Tunisia as well. Next slide, please. So 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 after the well and procuring a rig for the Gazania 1 well, which we hope to spot by the end of the year. This is a very significant prospect. It's an existing discovery, an AJ1 discovery made back in 1988, back in apartheid times. And what we're trying to do here with this well is to come up-dip of that, targeting two different geological prospects within this basin. It's coming up-dip from the discovery. The success case has the potential to be in excess of 300 billion barrels gross in terms of prospective resource. So it's a very meaningful well, and again, we hope to spot that well by the end of this year. So we have a very interesting exploration figure later this year in South Africa. Next slide, please. So 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 Rouge development is an 18-month project, basically. So exactly when CAPEX gets spent, whether it's in December 2021 or January 2022, you might find some differences in these numbers. But overall, over the next couple of years, I think we've provided good guidance on the CAPEX on that. But 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. And then 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. So as one can see with our petroglyph lifting that we've just had, those are quite lumpy affairs. When they come, they're big numbers. And when they fall exactly in the quarter, we recognize revenue. at the time of lifting. So you could see on a quarterly basis quite some difference, but the important thing is to look out over a period of a financial year. Next slide, please. So 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 on 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 one. In 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, but we would fully expect to see a number of production wells being drilled every year in 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 Petronor dividend, which we intend to distribute to our shareholders upon completion of that transaction. And we have the exploration well in South Africa. So we have a busy year ahead of us. Next slide, please. And just a comment on where we are currently in terms of our market cap, which is obviously taking a bit of a hit on the hibiscus extension well, the strengthening of the NOC, perhaps some other factors as well in there. But our market cap is... 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. And what you can see here is on an operating cash flow basis, a $60 grant will 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 its capital expenditure, we're obviously spending quite a bit of money in Gabon at the moment for the Biscuit Rouge development. So you'll see in the next three years that we'll be generating about $150 million in free cash, and then if you look over the next five years, considerably more. And 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 yields between 20% and 40% over the next four years as we go forward. Again, the important part is we have free cash flow really starts taking off in 2023 as we get through APEX period in the Viscous Rouge development. So we're going to become a very, very strong free cash flow generating company. And beyond the cash flow in that period, we obviously have – we're planning 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. So we don't include any contingent resource in our production assumptions, in our cash flow assumptions. Those are things that have not yet been sanctioned to be produced, and most of those reside within Equatorial Guinea. We can come back to that perhaps in the Q&A. So, there's considerable upside here from these numbers. And on top of that, we have other triggers every year. We have exploration wells each year. We have a growth strategy to complement the return of cash to shareholders. So, I 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. So with that, I'm finishing up, and I will open up to questions. Cassie is going to chair the questioning. So 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.

Thank you, John. We have a question from Stéphane Fouchard. I'm going to open the line. Stéphane, you may speak now, please. Yes, hi, guys.

Morning. I have two questions for me. First, an accounting one. The $67 million current payable, I assume that refers to the expected payments of Gabon and closing. It's my first question. My second question around Equestrian Guinea. And 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. And related to EG, how do you see the potential reserve, additional reserve booking moving forward with those 2C conversion? Is it a progressive affair? Would you see a point where you would be starting sanctioning a hefty adjoining program that would suddenly boost the 2P reserves? Thank you.

Kazi, do you want to take the first one on the payable position? And then perhaps Nigel and Richard can answer the EG1 and particularly the conversion to CO2P reserves.

Yes, I will start with the paper position. The explanation for that, Stefan, is the consolidation of the Equatorial Guinea business, which was supposed to be at fair value as of the completion date of 31st March. So as part of the acquisition, we have done two things. One is that we have acquired all assets and liabilities at fair value. And by fair value, I mean that all the over-lift position were also fair valued as well. So we mentioned about a $31 million over-lift position, which basically ends up in a kind of accounts payable or trade payables liability as well. And she would see a jump in the payables, but we expect that to unwind as we produce more and replace it with inventories. A few of the changes we are correct that are payable. We haven't booked the payable yet. That will only happen on completion, but there are some items like deferred consideration of $500 and some other payments in relation to the positions that we need to do in the future, which I'll do later.

Nigel, do you want to start? Maybe Richard can jump in as well if necessary.

Certainly. So on the question of drilling campaigns and reserves versus resources, what has been booked as a reserve on this asset is committed projects. So the forthcoming ELOM three-well drilling campaign is part of the reserves that we carry for the asset. But we recognize there's a 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. Now, 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. So 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. And indeed, beyond that, we already see an opportunity for a further drilling campaign out in 23. But those are notional plans at this stage that will mature over time.

Thank you. So maybe what you're saying is that there might be a sanction taking place in 2021, which could have an impact on the Open Reserve, and then there will be some more later down the line. That is correct. Yeah.

Okay. Thank you. Thank you, Stéphane. We have the next question from Theodore Nielsen. Theodore, I will open the line now. You may speak, please.

Good morning, guys. I have three questions if I may. First one, just as far as I understand, you will, of course, you already received the cash of the EG lifting in Q1, and that you also will have lifting in Q4. Could you indicate the size, the expected size of that lifting? That's my first question. Second question is on dividend level. I think you were discussed that previously as well, but on what basis will you set the dividend from 2021? and going forward, will that be a percent of pre-cash or EPS or some kind of other number? Any thoughts on how we should think around dividend forecasts would be useful. And the third question, to just remind us of the pre-deal resource estimate for the Hibiscus Northwell and the Gathania well.

Thanks. Sure. The first question on the EG lifting, we received the cash in April last Not in March, just to clarify. So 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 just see exactly when it falls. And 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. So 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 in that lifting and the parcel size. But that's our current working assumption. Your second question, sorry, was...

That was around dividend. How would you think about that?

So the dividend policy, it's a great question, and it's one that we've identified, obviously, is with the strong cash flow we have, particularly at these higher levels. Again, we designed this dividend strategy around time when we completed these acquisitions, and we designed it around sort of long-term oil price, $45, $50 a barrel. So obviously, at these higher prices, it's looking even better. But what we decided to do is to just try and get through some of this CapEx, make sure that the Hibiscus Rouge 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, but clearly there's going to be, particularly at these oil prices, quite a bit of cash, and it's likely to be, indeed, a metric along the lines that you've suggested. We're not quite ready to kind of define and frame that yet, but that is very much on the board's mind to define that better. But 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 the Hibiscus, so even the lower end of that range of discovery is highly commercial. On Gazania, Richard, can you refresh the memory, because we have two different targets there.

Yeah, so is Theodore on Gazania? That well is targeting two separate stack prospects. The highest chance of success one is the design of prospect itself, which is 168 mean, 168 million barrels. And the one above that is called Namakwa land, which has got a lower chance of success, but that's slightly larger at 186. So combined slightly over 300 million barrels.

Okay. Thank you.

Thank you, Theodore. The next question, we don't have any live questions, but there are some from the web. This one is from Daniel, which is roughly how much do we expect the dose of OPEX per barrel drop with rouge and hibiscus on stream, both including and excluding the PSO leaves?

Well, Daniel, the big operating cost in DUSEP is the PSO lease. Obviously, there are other elements to operating costs as well, but largely it's a fixed cost. So what you're seeing right now in terms of the operating costs being announced by the operator is as a result of the lower production at the moment. We're set to go through our growth now over the next couple of years. The unit cost comes down quite dramatically. I think the guidance once a viscous rouge is online is close to $10 a barrel, and that includes the lease. So really, there is some variable cost as your production increases, but the lion's share of it really is a fixed cost and more production you're putting across. So you'll hopefully see operating cost per barrel coming down from the early 20s at the moment down to, you know, $10, $12 a barrel, something like that, once a viscous rouge comes online. I don't have the breakdown of exactly, if we exclude the lease, how much that operating cost would be, but it is, by far and away, the largest portion of that, the lease plus the O&M contract on that.

Thank you, Jonathan. I have another question. I think it was a web question. I hope it answers it, John. There is another one from Daniel, which basically asks about what would roughly be the OPEX plan for the EG assets if 2C resources are converted to 2P? And we see strong production growth from 2023 onwards.

I mean, Nigel, 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 at 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. And so 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. So 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, no, I think, yep. Thank you, Nigel. Then we have another question about SWATs offshore. What are our thoughts about the Saloon West drilling permit?

Yeah, so, you know, it's a little bit the same as it was last quarter, which is we have plans to drill the Saloon 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 in the meantime. So we've been working with the regulator in Tunisia to try and come up with the best solution on that. So we don't have much of an update on it. I don't think it's a very near-term well to be drilled. I think, you know, COVID situation in parts of 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, from drilling a well. It's not the perfect environment to do it, so we still kind of 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. It's about 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've 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? And again, looking forward, just to make sure we answer the question.

Absolutely, John. Yeah, yeah. So it's a very exciting stage in this asset's life, in fact. So 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. And 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. And 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. So 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. And it's that work that's now informing the ranking of new development well targets for subsequent drilling campaigns. And 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 info wells will impact production levels. What has been committed to this year is the three well campaign on the Elan field. And the total incremental production was expected to come through at startup of those wells is in the range of four to 5,000 barrels a day. So that's indicative of the type of impact that we can expect to see from these wells. But 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 Ottawa and Brooklyn. I have opened the line. You may unmute from your side and please speak.

Morning, . Yep, yep. Good morning. We have been waiting for the completion of the Gabon part of the transaction. Did you say now that you expect a finalization of this within the next couple of weeks? Yes.

Yeah, that's right. You know, we always got to the end of the second quarter. It really just has to do with getting it through, you know, the ministerial consent, basically, and that's all in good shape. So 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've got a good-sized crowd here today and very much appreciate everybody following us. And, 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.