Panoro Energy ASA

Good morning, everyone, and welcome to Panora Energy's fourth quarter 2022 trading update and results. I'm John Hamilton. I'm joined today by my colleagues, Kazik Dhir, our CFO, Richard Morton, and Nigel McKim from our technical and project side of the business. And I'll be going through some slides as usual and we'll open it up to Q&A at the end. 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 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 made different materially from those projected or implied in such forward-looking statements due to known or unknown risks, uncertainties, or other factors.

Next slide, please.

As a reminder, you can join in the Q&A. You can either type a question in in the window pane, as you see on the left there. You can type a question. to answer it unless it's already been answered by a previous question, or you can raise your hand with the hand icon, as you can see on the right there, which we can unmute you so you can ask your question verbally, which everybody can hear. If you don't want to ask a question publicly, please send us an e-mail to the e-mail that's on the press releases, and we'll endeavor to answer those by e-mail as well. Next slide, please. So this is a record financial year for Panoro. And we also are today announcing a maiden cash dividend for the company at US dollars 3 million, which is in line with the expectation, NOC 0.2639 per share, payable in March. And this is a dividend that is coming six months earlier than we'd originally forecast at the time of making the Telo acquisition. So we're very, very happy. This is a big landmark day for Bernarda to announce its first cash dividend. Our revenue line, $188 million with a very strong EBITDA of $126 million. Cash flow from operations of $98 million. Our balance sheet is strong with net debt of $46.8 million. So a net debt to EBITDA ratio of 0.37 times, which is a very, very modest leverage we find. So, the company is in good shape, both on the P&L and on the balance sheet we find, and that's, of course, allowed us to initiate this first cash dividend. Next slide, please. So, as a reminder of what our 2023 shareholder return policy looks like, this is exactly the same as we have previously communicated. And as a reminder, this is not 2024, this is 2023. 2024 should look even different than this, hopefully to the positive. But what we're targeting is a core dividend this year of $20 million on a quarterly basis, which is starting in March, and weighted towards the second half. This is subject to oil realizations being in excess of $80 a barrel and no material change in the operations. So we're sticking by this. Obviously, if oil prices are higher, we're going to try and do better than that. But this is very much what we set out to do. under those conditions, and today's announcement, I think, is the first step towards that. And so, again, we're very, very happy to announce that today. Next slide, please. Production. You can see on the left side in the brighter colors what the past five quarters have looked like and what the full year looked like in terms of production. This has already been pre-communicated. We've also previously and today again reiterating guidance for the year between 9,000 and 11,000 barrels a day on average for the course of the year, with a target of reaching 12,500 barrels a day or higher towards the end of the year when the six hibiscus and roosh wells are coming online, which we'll talk a little bit more about. There's upside beyond this as well, which I'll touch on as well, and that is really in the form of additional wells in Equatorial Guinea, which we still have not added to our guidance. Those are probably early 2024 events rather than 2023, but there is some upside to that number. It's also worth pointing out that our first quarter 2023 production will be between 7 and 7,500 barrels a day, largely due to the shutdown of the FPSO in Gabon. This has already been pre-communicated, which is required for the tie-in of the new wells and the new production facility in Gabon. production grow during the year from a lower space, and every time a new reduced food well comes online, the production should increase, getting us towards that target towards the end of the year. So this is all in line with our previous communications and guidance. Next slide, please. Liftings. A lot of the business, the P&L and our cash flow is dominated by these liftings. We produce oil every day. We don't sell it every day. And so from a revenue recognition and a cash perspective, these liftings are quite important for us. As everybody knows and follows us, 2022 was a bit lumpy. We didn't have much going on in the first half of the year. And then we suddenly had record quarters in the third and fourth quarter last year as we had some big liftings happen. And we lifted approximately 1.8 million barrels of entitlement barrels for us during the course of last year. This year is looking much better, and 2024 will look, I think, even much better than that. So we're really on a growth trajectory here. Here we're anticipating lifting about 750,000 barrels in the first quarter of this year. That is Equatorial Guinea in about a week's time, and a lifting in Tunisia in March. At the moment, second quarter looks a little bit light. There could be some movement there. This is our best guess at the moment. We'll have three liftings in the second half of the year, three big liftings supplemented by some smaller Tunisian liftings. So again, when we talk about the dividend buildup during the course of the year, this is what we have in mind. It's when our new wells are coming online and we're producing and selling more oil. And we hope that on our best assumptions at the moment, we should be lifting about 50% more than we did last year. So as much as 2.9 million barrels during the course of this fiscal year. All other things being equal, this should be a new record year for the company as well. Next slide, please. Something just on CapEx and our balance sheet. There's nothing new here, really, just in reiterating guidance. We anticipate during the course of the year repaying a minimum of approximately $20 million under our loan facilities this year. We have some scope, obviously. Oil prices are strong to accelerate some of that, which we may choose to do. And our capex as previously got is around $75 million for the course of the year. This is Equatorial Guinea for our drilling program that we have coming up. It's for Gabon where we have the big drilling program going on as well and a small slice in Tunisia as well. This includes some exploration spend as well in Equatorial Guinea principally. where we have announced a couple of things on the exploration side. These are small cost items, but they have been included here. We'll touch a little bit more on those exploration activities as well in the next slides. Next slide, please. I won't dwell on this slide. It's just we try every quarter to show the reconciliation of the cash flow, so be as transparent as possible in terms of when the cash comes in and where it goes out and how that affects our cash position. and we'll continue to produce a slide that looks like this every quarter. But I won't dwell on it here now. I think the numbers probably speak for themselves. Very strong net cash from operations, $98 million of cash from operations. Obviously, we're still spending a lot of money, the $54 million of capex. This year, everything should look bigger, but we're still spending capex this year. 2024 is when I think the capex will slow down a little bit, and obviously we'll be harvesting cash in 2024 to a higher extent than we are this year. Next slide, please. So a slide on each of our assets for the moment. DUSIFU is going to plan. As those that follow us know, we are in the middle of starting a six-well production well program, which is starting with the very first well in Hibiscus, which is drilling. We have pre-announced that, and we're expecting oil, first oil from that by the end of March, so sometime soon. Everything's going to plan there. And from there, we're going to be drilling five more production wells in this area, Hibiscus and Ruchin, tying those back to the FBSO, which is anchored at Tortue, the Adolo. We have additional well slots under this rig contract, a minimum of two additional wells. The joint venture is still deciding what to do with those well slots, whether we activate them or not. But you could see some interest perhaps in 2024 after we've drilled the six production wells, maybe looking at an exploration target in this prolific license that we have here in Dusafu. Not something to talk about today, but just to note that we do have two extra slots on that rig contract that you could activate. Next slide, please. Subinokume, we're very busy there with ongoing ESP conversion work, re-preparations, all kinds of activity. But the thing to really look forward to here, I think, from the market's perspective is that we have a rig contracted from Island Drilling to come and drill three production wells at Ceiba and Okume. That rig should arrive probably in the early fourth quarter, and we'll be drilling three new production wells there. And again, our production guidance for 2024 we've not provided yet, but clearly three new wells here is going to add to the plot as we get the new DUSIFU wells online that are taking us towards the 12,500. this should then supplement that so during the course of the years we get a little closer to it we'll start providing a little bit more guidance in terms of what we see for perhaps for 2024 production but clearly we're building a nice head of steam here and on the production front uh that re contract also has a slot on it earmarked for an exploration well uh in block s um which is i came deep and what i'd like to do briefly is because we've made some announcements recently both on the farm into block s which you can see on the left side there and EG01, which is inboard there on the right. We've made some announcements recently on that. I'd like to ask my colleague Richard Morton, our technical director, to talk a little bit about what our thinking is on these two exploration blocks. Richard, do you have a couple words to say there?

yeah thanks john so um everyone um so the uh the recent acquisitions in eg is really built around a philosophy where we're trying to uh have a portfolio in the company that will deliver uh drilling opportunities that can be quickly and easily tied back to producing infrastructure that we have a interest in so hence the uh farm in in october we announced to block s we've taken a 12 interest in that one The partners are Cosmos and Trident, so we're fully aligned with a group producing at Sabre and Akume. That block has got a number of wells drilled in it in the past, and it's also covered with good quality 3D seismic. We're targeting an Albion prospect, which is a really nicely defined four-way structure, which is only 15 kilometers from the FPSO. It's kind of one of those prospects that is a little bit unique in the exploration world in that we have an FPSO right next to an undrilled four-way, so you don't find many of those these days. That's why it was an attractive prospect for us to farm into. So, as John mentioned, we're looking forward to drilling that in 2024 at the end of the Block G campaign. And then we announced on Monday that we've farmed into Block EG1, or been awarded Block EG1, which is shown on the bottom right of the map, right next to the Okume and Sabre complex. This one, slightly different to Joint Venture, we will operate with 56%. We have Cosmos as a partner and G-Patrol. The Block's got three wells on it already that have been drilled by previous operators and it has oil and gas shows at multiple levels. Similar plays here to that we see in Block G and Block S in that we have Albion prospectivity, we have Campanian prospectivity. Campanian is the main production from Block G. uh and we have some gas prospectivity as well in the esc and so quite a number of different prospects to go for we've covered in 3d seismic already so we don't need to reshoot we've got a three-year period here where we're going to do some detailed reprocessing G and G studies to work up that prospect inventory. And then we have an option to enter into a two year period, which will involve drilling a well. So that's, again, the concept here is to deliver a drilling target that we can tie back to the FPSO quite quickly. So that's a quick summary of our exploration plans. Thank you, John.

Great. Thanks, Richard. Can we move on to the next slide? Thank you. So in Tunisia, we are busy optimizing production there. We have a continued target of trying to reach about 6,000 barrels a day, which we think that this, on a gross basis, which we believe these assets can generate. Indeed, we've come quite close a couple of times, not on a sustained basis, but we have come close. So we're doing a number of work over activities now to try to boost that production. And we also have identified a rig to come in and target a particular well, which we think has a particularly high chance of success on it in the Guamipa field, which we'll be talking a little bit more about once we get that activity underway. But this asset continues to be a steady oil producer, and we believe still retains quite a bit of upside to it. So hopefully we'll be able to talk a little bit more about that during the course of the year. Next slide, please. Our TCP in South Africa, this is the helium and biogenic gas play that we are incubating in South Africa. Just to repeat, this is not a change of strategy, but this is part of our commitment towards ESG, trying to use our subsurface skills to try to help South Africa in this case. figure out whether there's means of displacing the use of coal or its power generation. There are other companies, some large, some small, looking at this same play system. It's quite an emerging area, both for helium and for gas production. And we have another half year left on our TCP year, which is simply a desktop study license, at which point we can elect to take that into an exploration phase and turn this into a license. Our capital commitments here are minimal and they will remain very, very small. But nonetheless, this is something that we think is quite interesting and being on the forefront of some very interesting developments here in South Africa. Next slide, please. Just a quick word. I'm not sure people know it. We are going to put out our first sustainability report this year, which we think is an important step for Panoro as we've grown as a company. We've always held closely our responsibilities towards sustainability and ESG, and I think that's well reflected in our reporting, in our board, in our disclosures, and the way that we operate our business. But here in the next couple of months, you'll see us alongside our annual report publishing our maiden sustainability report, which is a further commitment to that transparency. to that responsibility that we hold. So this is something that we're going to be quite proud of. And obviously, a number of investors do look at this quite closely. So we're glad to be able to produce more information and more insightful information, more analytics, more data to help those investors that focus on this recognize the strides that we've taken as a company and our commitment to this. So look out for that one. And the final slide is a summary. which is just to remind people of the trajectory that we're on this year, producing per year 7,500 barrels a day last year, trying to get towards the end of the year to an excess of 12,500 barrels a day, further upside beyond that with the Block G wells in Equatorial Guinea, the three new wells that are coming there. So we're really entering into an exciting period where we're drilling at least 10 wells in the next 12 months or so. nine production wells and one exploration well. Those are committed with options over further rig slots. So we really do have an interesting inventory, I think, of drilling going on over the next 12 months. Our production is unhedged at the moment. We will seek to do a little bit of hedging around our liftings just to maximize the price that we think we can get around those liftings. We have inaugurated our cash dividends. We have a very clear framework, we believe, in terms of the shareholder return policy. So we're holding that quite close. And as you can see with what Richard talked about in Equatorial Guinea, we are looking at strategic positioning in acreage around our core production assets. So infrastructure-led exploration strategy where we will never expose the company to very, very big amounts of financial exposure to the exploration activities, but we feel that this is an important part of of replacing reserves, finding new oil to put through existing infrastructure rather than going for something that's a wildcat somewhere that would take years to develop, something that we can plug and play back into an existing infrastructure. So hopefully that gives a feeling for the company's performance, its commitment to ESG, its strong production growth that we have ahead of us, a little bit around our strategy as well. And with that, I'd like to turn it over to any questions we may have. Here's a reminder of how to do that in case you need a reminder. You can type a question in, you can send us an email if you don't want to do so publicly, or you can raise your hand.

My colleague Andy Diamond is going to help navigate the questions. Thank you, John.

The first question is from Stefan Foucault. Stefan?

Yes, good morning to all and thanks for taking my question. I've got a few. Let me start by the operational. So if we come back to the EG01 license, could you come back on a bit the history, who previously had the license, why did they decide to relinquish and what do you potentially see different from the previous operator? That's my first question. My second question is about Tunisia. The Q422 production is very strong, a pound. Would you expect that very strong production to continue in a 1Q and 2Q of 2023? And I've got then some question. Thank you.

I'll deal with the Tunisia question quickly and then maybe ask Richard to comment a little bit on the history of Block AG01 and what we see there. And on the Tunisian side, yes, we did have a strong quarter. We have a number of wells producing there. I think the well count is around 15 wells or something like that. So, you know, we sometimes have strong months and then weaker ones, depending if a well needs an intervention, a pump replacement, something like that. So we would expect some variability quarter to quarter on those assets, but directionally on an annualized basis, we would expect that strong performance to repeat itself during the course of this year. It all depends quarter to quarter and we're always, you know, these are onshore assets, you're always working with as well stock you've got. But we have some ambition also to do better than we did in the fourth quarter during the course of the year, but let's see. But we do expect, at least on an annualized basis, Stefan, for that strong production to maintain itself. EG, Richard, do you want to step back in there, talk particularly a little bit around the Albion play, I guess, which is kind of what's changed a little bit?

Yeah, so thanks, Stefan, for the question. Good question. So EG1 has been around for a little while. The former operator, it was their only asset in Africa, a very isolated small asset. I think the difference with the current joint venture that's been assembled, it's ourselves and Cosmos who are going for this thing, is that we have a regional understanding that the previous operators didn't have. So obviously we're in Block G, Saber Okume, we understand that play very clearly. We are now in Block S, so we can see that the picture regionally and the newer play that's emerging in the Albion is also present, of course, in EG1. So we're focusing on something slightly different. We've got a regional approach. We've got more regional data. So I think we can unlock this thing a bit better than previous attempts. The previous well drilled in this block was a number of years ago, 2016, and it did have some shows. I think they positioned it in slightly the wrong place, but I think we can do better with reprocessing that we're planning and deliver a compelling prospect into the block.

Okay. Thank you. Perhaps for my question, you can take a question from others and I come back to that afterwards.

Thank you.

The next question is from Theodore Sven Nielsen. Theodore, please go ahead.

Good morning and thank you for the update. Three questions from me. John, you mentioned that the 2024 CAPEX is expected to decline. I just wonder if you could provide some more color on that, how much it will decline compared to this year's level. Second question, production cost on DUSAFU relatively high this quarter. Just wonder if you could could indicate which level we should expect when hibiscus is on stream. I assume most of the costs here are fixed, meaning that the cost per barrel will be much lower by end 2023 than what we saw in fourth quarter 2022. And then final question on block G, regarding the infill wells. I assume those wells are targeting barrels that already are booked as reserves.

So, yes is the answer to the last question. Those are targeting existing reserves. They're meant to be, you know, target-targeting known accumulations. These are not exploration wells. They're production wells, so yes. On the DUSAVU operating costs, yes, as BW have guided, operating costs are still quite high at DUSAVU, and that's been well understood, I think, by everybody because what we have there is a very, very high fixed cost of a of an FPSO, a leased FPSO that has an O&M contract on it. So your cost base is rather fixed. So the more barrels you put across the vessel, the lower your OPEX gets. And obviously, while we've been waiting for this new development to come online, OPEX and production has been in natural decline on the existing wells, that OPEX is stubbornly high. Where I expect it to get to is probably In the mid to upper teens, once we get the new production online, it could be lower than that as well, Theodore. But directionally, you should see it halving from the fourth quarter number, I would thought, once things are online properly. And this asset then really should, as long as it's sitting there at plateau, should be a nice low operating cost asset. In terms of the capex for 2024, we're not quite there yet. I think my point is that this year, last year were particularly high years. I would expect 2024 to be a lower number. It's not going to be zero, but maybe if you had to put something in a model, maybe something around $40 million for next year, because we'll still have some of that block G drilling going on. But it's a little early to provide pure guidance on it, but I think directionally will definitely be lower. So, that answers the questions.

Yes, absolutely.

Thank you. Thank you. And John, a further question from Stefan.

Stefan, please go ahead. Thanks.

Some more boring questions. So if I look at the cash flow statements, there is, I think, $10 million of the non-cash positive movements in Q4, and I wasn't knowing what it was. And likewise, on the CapEx, and there was a comment on that in the press release, but there was a $55 million investment in the cash flow statement, but the headline is 65. And I was wondering what's the 10 difference and whether we should add that back, if it's working capital, to the 23 CapEx number.

Thank you. Yeah, I'll answer the second one. Maybe I'll ask Cosby to respond to your first question. We provide CapEx guidance. Sometimes the way that we account for some of that CapEx falls into UpEx, and that benefits us from a tax perspective and under the production sharing contracts as well. So I think what we've tried to do is just try and highlight that the CapEx number you might see in the cash flow statement is a little different than the 65. We've got it. We have spent the 65. The difference really is non-recurring costs that are being held in the operating cost line. So this will be principally around the Equatorial Guinea asset where it's a midlife asset. There's lots of ongoing work on facilities upgrades, on pipelines, things like that that may not fall into your traditional capex lines that get captured more by the accountants. and certainly for the purposes of cost recovery under the production sharing contracts operating costs. But we see them as one-off project costs, we call them. And so we're just trying to make a little bit of differentiation there to make sure that R65 reconciles with the 55 that you see in the cash flow statement on the capital expenditure side. We'll continue to try to show the difference on those. But when we give the gross capex, we're including these one-off project costs that we have that are typically mostly, to be fair, on the Equatorial Guinea asset. Kazi, do you want to take a stab at his first question?

Kazi Vaheguru Yes, Stephan. I think this is basically largely – we call it – well, assign it to one of course but you know there's some portion of cost that we have to allocate to investing activities so that comes as a kind of a swing as a positive item and then basically gets a deductible against in the in the in the capex cost which is which is shown in the cash flow statement so nine million is largely those costs which are basically part of the 14 million um as a as a payment going out in the in the capex line It's basically how the mechanics of the cash flow works that you need to add back all the items to the nature that are of CapEx and then basically deduct it back in the .

Understood. Thank you.

Thank you, John. A question that's been submitted online. Could you please try and elaborate a little bit and indicate what the potential in the portfolio is, taking a slightly longer term view of production opportunities and production growth potential?

Yeah, it's a great question. I mean, you know, I think that we, you know, start with Dusupu, which is probably the one that has such a great potential still on it. As a reminder, the Ducepew block is the largest exploitation block ever granted in the history of Gabon. It's got numerous prospects and leads on the exploration front, which in an area where we found already lots of oil. So I think that with Ducepew, we've got another 16 years on the licensor and we can always ask for another extension. So I think what you're going to see with Ducepew, particularly if we can continue to find more exploration barrels to add to our 2P reserves, you're going to see in the shorter terms over the next, say, three or four years, a nice plateau of production as we drill these production wells there. And if we're successful, and I think we will be ultimately in finding more oil in this area, that will just serve to extend out that plateau for quite some time. So rather than it going into decline from that plateau of two, three, four years production that we have in front of us now, uh we would hope to be able to continue to keep that plateau going for for longer by finding more oil obviously then we have to find it first but i think that there is lots of potential there over the over the longer term to continue to find book new reserves at ducifu equatorial guinea uh there is potential uh as well we'd be drilling these three new production wells we do have a number of contingent resources there as well uh and as we continue to work that asset, and hopefully these three wells will go well. We'll probably be presented with the opportunity to come and drill more wells. Obviously, what Richard talked about with the exploration potential in and around the block is what I think could provide a huge upside. Admittedly, it's exploration, so I don't want to get too far ahead of ourselves there. But if this deeper Albion play that Richard referred to can be de-risked, we're going to find lots of opportunity in this region for more Albion structures here. which could tie back into that infrastructure. We've now extended those field life, sorry, our licenses out to 2040 on that. So to the extent that we can find additional new reserves through exploration and exploitation of the existing assets, you could really see a nice long plateau there as well. I think that's probably where the greatest potential is. I don't want to leave Tunisia untapped either, but Tunisia, we get quite excited about one particular reservoir in the Goubiba field there that we're going to try and test out this year. We're going to re-complete a well on that. And that could also provide relative to the size of the Tunisian asset, quite a little lift there. So we're quite happy with the portfolios we've got. We think it's good for the short term and the medium term and even the longer term, particularly if we can get some of these exploration wells coming in successfully.

So hopefully that answers that question. Thank you, John. And that concludes the Q&A.

Perfect. Well, thank you. Thanks, everybody, for listening. And I appreciate you taking the time to stay with us during this call and follow us in the future. Thank you very much.