Panoro Energy ASA

Good morning, everyone. This is John Hamilton, Chief Executive of Inoro Energy ASA, and welcome to our third quarter year-to-date 2020 Zolf presentation. I'm joined today by Richard Morton, our Technical Director, Nigel McKim, our Projects Director, and Qazi Qadir, our CFO. We'll take you through this presentation. We'll open it up for some Q&A towards the end. I understand that the link to NewsWeb this morning had a glitch in it when it was generated by NewsWeb, so I'm very glad that so many people have been able to find their way onto the presentation. We're busy trying to fix that as well at the moment, but we do have a number of attendees here this morning, so that's good. Next slide, please. So, as a reminder, today's conference call contains certain statements that are maybe 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 and perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances. Although we believe that 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. Next slide, please. So, for those of you who have joined us before this webinar system, you have the ability to raise your hand, ask a question. As long as I can see the hand, we can unmute you and allow you to ask a question. You can also type in a question down into the question pane, and we'll try and pick those up as well. Depending on how many there are, we'll try and address those as well towards the end. Next slide, please. So what are the key takeaways here? You know, we've all had a year to forget in some ways. It's been a very challenging year for the oil sector, for everybody. But there's also a year to remember. Remember that actually we have a good company. We have a lot of interesting things happening in it, and we've managed to come through the crisis, I think, although we're still arguably still in parts of it, in good shape. We have production growth. We have production growth in our core assets in Tunisia and Gabon, recently demonstrated by us hitting our 5,000-barrel-a-day growth target in Tunisia, where there's also additional potential. In Gabon, you're going to see production growth each year from 2021 through 2024. So we have it all in front of us in terms of that production growth. We also have quite a bit of exploration upside in the company as well. We'll talk a little bit more about Hibiscus. Those of you who follow Hibiscus know that it could be three times as big as the currently booked reserves. We have the ambition as a joint venture in Gabon to drill two wells per year for a total of five years, so 10 wells at least. We hope to kick that off already in 2021. We'll talk a little bit more about that. And in Tunisia and South Africa, we also have further upside potential. In our company, we have a well-governed company. We have a good board. We are financially conservative. We have a deliberate strategy to grow a stable and sustainable business that's focused on HSE, on ESG, and we also have the dividending of the Petronor shareholders when that deal completes hopefully in the near future. So again, we've come through a difficult year, but we think we're well poised to grow from here. Next slide, please. A few operational highlights and financial highlights. These are all embedded within our E3 results, and you can read those in greater detail. However, I will touch on a few of these. We did hit 5,000 barrels a day gross production, and we've maintained that production level Q4 to date. So as we speak, we're producing and have produced since October 1st approximately 5,000 barrels a day. We drilled the first new well in Tunisia successfully without any HSE incident, which is very, very proud of that. And we established two production zones. including the Duleb. We have two production zones in that particular well. I'll talk a little bit more about the Duleb in a couple slides further. And we have more workovers that we're currently working on over the next three, four months. We should be trying to bring a few new wells on stream as well. Not new wells, not new drills, but workover wells. Viscous, we'll talk more about that, but that could be three times as big as previously identified in Caban. And Gabon is also quite exciting in the sense that the crisis has allowed us to re-look at the development concept for the next phases of Gabon and identify material cost savings. On the gross revenue side, you can see the numbers there. What's interesting to note is we've had five liftings year-to-date, but we have three more in Q4. So something like 35% to 40% of our revenue will be booked in the fourth quarter. So it's quite a heavy quarter coming up. OPEX per barrel, still very, very attractive, low operating cost barrels that we have. These are not ones that require high oil prices. We enjoy high oil prices, but we don't require them. Our hedging, our conservative financial strategy has continued to pay us dividends, so to speak. And we're busy in advanced negotiations for a reserve-based loan, an RBL, a structured loan, to help finance the next phases of our development in Gabon. Next slide, please. So this is a slide we've shown recently, and this is just updated. We have made $3.9 million in cash realized gains off of our hedging program so far year to date. We have colors that have a floor of 55 on them. So if oil is 45 on those barrels that we've hedged, we make $10. And we have this hedging program all the way through to the end of 2021. representing approximately 30% of our current production, something like that. So on average, for the barrels we've hedged, we've probably made about $20 a barrel. And across our entire production, that represents something like $7 of extra revenue, $7 per barrel extra revenue we're making off the back of this hedging program, which has really put us in good shape during 2020. Next slide, please. So Gabon update, some of this has already been rehearsed by BW Energy in their third quarter results, but we had gross production in the quarter of 15,500 barrels a day during the quarter. We have four wells in production there at the moment. The gross total production for 2020 is estimated at around 14,250 barrels of oil per day. It's slightly down on previous operator guidance. That's largely due to some COVID-related things, the shutdown of the FPSO briefly, and also a little bit of the OPEX situations, trying not to max things out too badly. The four wells are doing extremely well. This is not a reflection of the reservoir. This is simply operational. The four wells are, each of them, performing extremely well at the moment. OPEX per barrel is approximately $19 a barrel for 2020, slightly higher than had been originally guided by the operator, and that is largely down to COVID costs, which we hope will fall away during the course of next year. Next slide, please. So there's a lot of information on this slide, but actually the message is quite simple. We have 112 million barrels discovered in Gabon, in Dusafu, We hope to find more, obviously, but that is what we have our current two peak book reserves at. And we are busy in the middle of a phased development approach. So we have Tortue Phase 1, which we did. We have Tortue Phase 2, which we're most of the way through. We have to bring two more wells on stream during next year. So we've gone from 10 to roughly 20,000 barrels a day through that phase. The next phase coming up we should see first order probably in the fourth quarter of 2022, is hibiscus rouge phase one, which should see us come up to the main plate capacity of the FPSO, about 40,000 barrels a day. Could be a little bit higher than that. We have also hibiscus rouge phase two. Now, in an upside case, where we're able to identify additional reserves at hibiscus, we could see pushing the FPSO capacity beyond its current main plate capacity. This FPSO does have the capacity to go to 60 or maybe 70,000 barrels a day of processing capacity. So we have the flexibility to upsize the FPSO capacity in a success case. And we're on this journey now to get to at least 40,000 barrels a day. On the right-hand side of the slide, you can see what the operating cost evolution here is. The operating cost at Dusafu is largely a fixed cost. The more barrels we produce, the lower the operating cost per barrel is. As we get to 2023, 2022, we bring the new wells on stream at Abiscus, you will see our operating costs dropping down to something like $11 or $12 a barrel. And what does that mean? That means even when Brent is something like $45 a barrel, we are making more than $20 operational free cash flow per barrel after tax, after operating expense. So this is an extremely profitable operation even at today's oil prices. Obviously, if oil prices go up to $50 or $60 or, dare I say, at $70, this is an enormous cash cow. Next slide, please. So there's been a lot of talk about hibiscus. I've got a couple of new images here, but just taking a step back, reminding people what happened. We had this as a prospect. It was 11 million barrels we thought we were drilling for. We ended up having a big success on that. As everybody can recall, we booked about 45 million barrels of 2P reserves off the back of the wellbore and the sidetrack. Since then, the joint venture has engaged in reprocessing the seismic that Canola acquired back in 2013 and 2014. And what that has done is, if you can look at the two images, the first image, the map, you can see the high areas there, the red, the brighter amplitude in the front there, the red, is what we thought the structure looked like when we drilled it and found the 45 million odd barrels. The structure on the right is what, based on the seismic reprocessing and the new mapping we've done, is what it could be. And this is where the excitement has come. Again, you don't have to be able to read technical maps to see that the red areas, the yellow areas, this is a much bigger structure potentially. We'll have to drill a couple of wells to delineate this, which we plan to get after already in 2021 by drilling an additional well. But I think the picture tells the story that this structure could be enormous. It could be up to 155 million barrels potentially. And we hope to be able to drill the first of those wells this summer when we have the rig back out there drilling the production wells. Next slide, please. So that's not all. Hibiscus isn't the end of the story. We have 13 more prospects in Leeds. We have the ambition as a joint venture to drill two exploration wells per year for the next five years. What will those be? We'll need to see. I think the first wells we're going to drill are going to be in the Hibiscus area. But after that, we could be looking at Prospect B. We could be looking at Hibiscus North, Espadon, String of Pearls, Prospect 18. There are lots of things to go for here. And with the recently reprocessed seismic, the teams are very, very busy. So BW is operator, but Panora on its own as well, Solo on their own as well, and GOC, our state-owned oil company, on their own are all looking at this reprocessed seismic, each coming up with their own interpretations, and we'll be sharing those with each other in due course. It does take some time, but we're very, very excited, for instance, and we concentrate on really looking at the viscous areas first, which is what's generated those maps. We are in a very, very good oil fairway, and we have this block for 18 years, so we've got plenty of time to find this stuff. So the Bonn-Dusafu Block will be a long, long-term asset for Panora and its partners. Next slide, please. So we'll talk a little bit about Tunisia. We hit the 5,000-barrel day-growth production target. We previously announced that. We have further workovers underway as we speak. We drilled the first well for over six years on the block in the Gulbiba Field, which is one of our onshore fields. where we found oil in two reservoirs, the Barreno, which is the more common and prolific reservoir in this area, and also in the Dulab, which is less common, but when you find it, it's very, very good. I'll touch on that in a moment. Gross production, as previously guided, was 3,261.25%. previously guided that this was going to be a weak quarter in terms of production due to needing to replace two pumps on two very important wells for us. So we kind of had two of our big wells needing replacement at the same time. A bit unusual, but it happened and we flagged that earlier. Our quarter four production to date is 5,000 barrels a day. We're currently producing around that level. So hopefully it'll be a strong quarter in Q4 for us. And OPEX per barrel, again, these are very low operating costs. assets, you may see a little creep up of operating cost per barrel in the fourth quarter because a lot of this work over activity is classified as operating cost, not as capital expenditure. But nonetheless, the assets are cheap operating cost assets. Next slide, please. And here's a graphic. We've shown it before, but we've extrapolated it now out to incorporate the last three months. As you can see, when we took over the asset, it was producing around, on the left there, around 3,500, 3,700, somewhere in that zone. We were able in the first part of this year to kind of get that up to 4,000 barrels a day. COVID struck. We had to down tools, so to speak. We just continued to want to produce oil and not produce it with too much difficulty, with too many crews, things like that. So production did fall off a little bit. As previously guided, we had a third quarter we needed to not only contend with COVID, but we had to replace a couple of pumps on two of our key wells. But then immediately into the fourth quarter, we managed to hit our 5,000 barrel a day target, which we have, as you can see, maintained and even exceeded at times during the quarter. So I think this tells the story of the ability of Panora to get after these assets. These were unloved by OMV. That's taken us some time, but we have the right boots on the ground, and we are now getting after these assets in a good way. Next slide, please. So what are the next challenges? We hit 5,000. We want to do better than 5,000. Historically, these fields have produced 6,000 to 8,000 barrels a day. There have been spikes where those have been higher than that, but consistently back when the assets were invested in and loved, They were able to produce 6,000 to 8,000 barrels a day, and I think that that is not a target we're setting out here today, but that is a reasonable expectation of the ambition we have on the asset as the next step. Our work over activity continues as we speak, and we have further stimulation, optimization, work over initiatives identified beyond the end of the first quarter of 2021. And what for us is important is that this is, again, like Dusaflu, it's a long-term asset for Panoro. And what we want to do is make sure that it continues to produce oil for a long period of time. And so we've been spending a lot of time remapping and modeling fields to try and justify and try and convince our partners and ourselves that the assets need continued investment in them. And one of the interesting things that's happened is the Gwibiba, when we drilled Gwibiba 10, We encountered the Duleb Reservoir, which is a very exciting reservoir in the field, although we do find it in other fields in the area as well. Now, we knew it existed. We knew we would find it. What we've ended up finding is on logs, it looks like a very, very good quality Duleb Reservoir. We do produce from Duleb at the moment in other wells. The Barreno, which is a lower reservoir, is a more prolific producer. Those wells produce three, four, 500 barrels a day type of thing. Very good wells, very economic wells, and they produce for a long period of time. A dew lab is a different animal. It can produce 1,000, 1,500, maybe 2,000 barrels a day, these wells. And so when you can find them in a good location and you can provide the right water support, water injection support for them, they can really produce exceptionally well. So as you can see, if we're able to identify additional locations to produce the Duleb from, we have a chance of really changing the production profile of some of these fields. We're currently in Glaviva 10, which is where we have the Duleb, producing from the lower Verena Reservoir. That's producing oil as we speak. And we will produce that until such time as it becomes less interesting to produce that we drain the reserves, in which case we'll come up the well more. We're re-completing the Duleb, and we hope to achieve production rates at that time that I've indicated there. We also have other potential in the Cecina field, the Remora field, and Ironfield. So there's lots more potential in these assets. And again, the key here is to make sure that we have a stable and growing production base for the longer term here. We also have the Saloon West exploration well, which we have planned for 2021. In the success case, we can tie that back to TPS as well. So we have plenty to go for in Tunisia still to come. Next slide, please. For the corporate updates, Block 2B in South Africa, this is a very exciting block that we farmed into together with Africa Energy. We're expecting approvals from the ministry to enter into this block before Christmas, we hope. Completion of our deal is subject to that consent from the minister. It's also subject to ASEAN, who are the proposed operator, coming in and farming into the block as well. So it should be a fully funded well there. The pandemic, again, just like in Dusafu, has created some opportunities to re-look at things, to re-tender things. We're looking at some cost savings on that as well. In the meantime, the technical teams have been able to continue to advance their thoughts in terms of the best downhole locations and things like that. Ajay continued to produce oil. We had a lifting even recently. We continue to work closely with Petronor in respect of The disposal of this ministerial consent can take a long time in Nigeria, and this has not been an exception. That process is well underway. The regulator is currently reviewing the proposed documentation. We hope that that transaction will complete sometime soon, fourth quarter, maybe early into the first quarter. And the intention is once we receive the PECSANOR shares that are consideration for that transaction, that we will dividend those to PANORA shareholders. Next slide, please. ESG, one of the things we're very proud of is all this work over work that we've done in Tunisia. We had two rigs going. We drilled the first well for six years in the block. We had multiple crews. We had COVID to contend with as well on top of all that. And we performed all those operations without incident. In Gabon, similarly, we were able the operator was able to maintain production operations through this very, very difficult period. So I think what we're finding is that our policies, our procedures have really withstood some serious tests over the past year, and we're very, very proud of that. We were even able to initiate our solar program, solar initiative in Tunisia, where we've set up solar panel lighting for our operational, our own use, our own power use in some of our fields down in Tunisia. So we are proud of our ESG footprints. We can always do better. We are setting up benchmarking to benchmark ourselves against the industry and against our own performance as we go forward. So the company is taking these things very seriously and continues to consider ourselves a very, very well-governed company in this respect. Next slide, please. So the final slide. You know, I think we have a lot to look forward to. We have production growth within the company to look forward to. We have exploration wells during 2021 to look forward to. And all of this is set within a company that has a good balance sheet. It's got low-cost production. It can withstand times of low oil price. We have the dividending of the Petronor shares to look forward to. And we always have to remind ourselves, particularly with oil, with the $20 a barrel, that the reserves, the resources that we have are extremely valuable, even in down cycle times. We are in a cyclical industry. Hopefully we're about to hit an up cycle. And these reserves and reserves we have will continue to be valuable in our opinion. So that concludes my presentation. I think the next slide is a reminder on how to ask questions. And as long as we can master the technology, we will try and identify if anybody has any questions. So you can answer questions in the text box or you can raise your hand here. Let's see, I've got a raised hand here. Sorry, let me get my technology correct here. All right. I'm trying to unmute Stefan Foucault. For some reason, Stefan, I think you have to unmute yourself.

Can you hear me? Yes. Hi, John. Stefan. Thank you for taking my question and thank you for the presentation this morning. I have really two questions. The first one is a bit early, but I was wondering whether you had any idea of where the 2021 CapEx and production in Tunisia might be looked like. And second, you talked about at Ibiscus, the FPSO of being $70,000 per day of processing capacity. Would that be including water or is that just oil? And if it includes water, what would be your view around the production capacity for oil that would be available at the FPSO at this time?

Thank you. Okay, I'll take the second one first and come back and clarify your question on the first. No, that's oil processing capacity, Stéphane. So it's... The water handling is in addition to that. So again, I don't think the full engineering work's been done, but this is a very interesting FPSO. It was the world's first, I believe, FPDSO. So they're doing a rig on it. And so there's this huge area on the surface of the FPSO that could handle more processing capacity. And so the idea would be that in a success case, for instance, we find a lot more oil in hibiscus and that the development plans change and are accelerated to the point that we could produce those kind of volumes of oil, that the FPSO could be modified to handle, say, 60,000 to 70,000 barrels a day of oil on top of any other liquids. Your question specifically on CAPEX 2021, was that specifically Tunisia?

For the CAPEX, it was for both Tunisia and Gabon, assuming, of course, Gabon everything works and the restrictions are being lifted. but the production was just for Tunisia.

Yeah. So production Tunisia, I think, you know, we'd like to, we'd like to come out and tell you that we, we have, um, you know, plans to, to grow it from here. I think what we recognize, we have 14 wells on stream. We've just gone through a work of a program. Some things work, some things have not worked. Some things have worked better than expected. Some things have been a little disappointing, but on a portfolio basis, obviously it's, it's gone very, very well. And we have additional activity, work over activity, so it's not CapEx, it all comes through OpEx, lined up over the next three months. Let's hope that those go well. Those activities do have the possibility to increase production materially from where we are, but until they're done, we wouldn't say. So, I mean, at the moment, we're kind of good and steady on the 5,000. I don't see it this stage until we get through the remainder of the work program to really uh to to to really uh guide beyond beyond that uh capex uh for 2021 therefore is predominantly going to be um capital expenditure in the bone and to the extent that we uh when we drill in south africa or in southern west those those would be x related activities as well there's some uncertainty in terms of the exact timing of those two events but the capex and the bomb is principally to come in and tie the fifth well in and to drill the sixth well, production well, to get our production back over 20,000 barrels a day. That is reasonably low capex. I think that plus the exploration well is, we drill an exploration well as well, we hope in the summer, is something like $50 million gross So 7.5% of that, you know, it's not terribly much money. And then when we re-sanction the Hibiscus Roots project, we'll start incurring towards the second half of the year, presumably, some additional capital expenditure related to that. Great. Thank you. Right. So now I just need to look and see. We have some written questions. Let me just see if there are any more raised hands here. Yes, we have a question from . Good morning.

Good morning. How are you? I hope everything is well. Thank you. On slide number 16, you, in the production, you say that additional activities underway, including and other initiatives. Could you elaborate on other initiatives, please?

Sure. Basically, I've got my colleague Nigel Kim on the line as well, who is responsible for a lot of these activities. Nigel, do you want to take that one?

Sure, John. So yes, the Elaine work, we've got two wells there that we're looking to bring back online in the coming months. One learning out of activities over this past year was the success of acid stimulations. we had an early success in the remora field at the beginning of the year, where we managed to get a significant boost in production from an acid simulation on remora one. So that particular technology we've been looking at using elsewhere across our assets, and we've identified a few wells in the Cicina field that could benefit from that. So one of the first operations out there is intended to target one of those wells, Acina 3, where we look to acid simulation and change out an ESP pump. So that's another of the activities that we have in our near to medium term plans for workovers. And then alongside that, as touched elsewhere in the presentation, we've got a series of subsurface re-evaluations going on, and that may yield additional opportunities.

Okay.

Thank you very much.

Great.

We have some questions that have come in, written questions. There are a couple questions on the timing of the Nigeria deal, the sale of our Nigerian interest to Petronor. The question is concerned with the timing of it and if there's a risk that it won't happen, given that there is a long stop date under the sale and purchase agreement of December 31st. Look, the intention of the parties, both Petronor, they're not on the call and so they'll have to speak for themselves, but both Petronor and Funoro and the operator, Adagie, are extremely focused on completing this transaction and that we see everybody is still fully intending on completing this transaction. We are hostage a little bit to the fortunes of the Nigerian regulator. Basically, we had a two things which slowed down their process. One was COVID and the offices were closed for a number of months. We also had, there was some sort of civil unrest in Nigeria, which again closed the office. And we also, they're also undertaking a big marginal field licensing round in Nigeria. So the regulator cut their hands full but we're all pushing towards it. Is there a risk it doesn't happen? Of course there is, but my position is that this is a transaction that we expect will fully happen. Whether it will happen this side of Christmas or not, I can't say, but I think it will happen reasonably soon. Let's see here. We have a question. I might ask Richard to help on this one. which is around South Africa and around what is the resource potential of the license and what cost savings have been identified. As a reminder, we farmed into this block again in South Africa about nine months ago, and we farmed in together with Africa Energy, who were selling down their stake. They were focused much more on their big project with Tatao. And with ASINAM, our transaction is subject to ministerial consent and to ASINAM completing their share of the foreman. Those two things have not happened yet. We expect the ministerial consent to happen soon. Then we rely on ASINAM completion as the final step on that one. Richard, do you want to talk a little bit about what the potential on that license is and what that story is about? Just rely on people quickly.

Sure, thanks, John. So as a reminder, the block is very small, a small basin drilled in 1988. There's already two sea resources on it from the discovery well, which is the AJ well. That amounted to 37 million barrels. The plan is to drill up dip from that discovery. We're targeting a stratigraphic structural play there, and we estimate 163 million barrels over a couple of prospects there with a stack prospects and ultimately in the block itself we've got a prospect in lead inventory which amounts to just under a billion barrels in total great let's see here I think that

A question from Daniel. Let me just find that one real quick.

Okay, well, I think that we have answered the questions that I see here. Let me check one more time to make sure that there are no more raised hands here. Great. Well, thank you all very much for participating in the call, and we look forward to continuing to update you all on our various projects. Thank you very much for attending.