Seplat Energy Plc (SEPL) Earnings Call Transcript & Summary

Thank you, and good morning, everyone, and welcome to our Seplat 2021 Annual Results Presentation. We're just going to run through the slide deck. I'm joined in London here by our Operations Director, Effiong Okon; and also our Chief Financial Officer, Emeka Onwuka, who's in the room with me, in London. So we just turn to Slide 3 to start off the slide deck. Just running through our corporate highlights. We'll see 2021 as a year of transition for the company and robust performance. We have a profitable business, and we can see that when we go through the financial results. And so in terms of the full year 2021 achievement, the first one up there, which is really very much strong for us, which is our strong safety record. We recorded 28 million man hours with no LTI on our Seplat Energy operated assets. So it's something that we strive for very strongly. In terms of the strategy, we put out our strategy in July in 2021, focusing on building a sustainable business and delivering transition that is right and just for Nigeria. And in that process, we renamed and rebranded the business and really set out what we believe is going to be a very exciting future. In terms of governance and the ESG ratings, really what we've been focusing on is strengthen that governance, and that is being demonstrated by the elimination of the related party transactions. We delivered robust production despite again, we have challenges in the Forcados outages, and Effi will run through some of that. And then financial strength has increased, enhancing returns for all stakeholders and enabling the acquisition, which we announced at the end of last week. And you can see there, I won't go through the slides in that we have a separate presentation on that, you get recording, but you can see on the right-hand side, just the EXXON Mobil Producing Nigeria acquisition and what it does for our various metrics. And it's picking up quickly on Q1 2022 post balance sheet events. One area that we list here is Sibiri, which is the exploration well in OML 40. That has come -- has been drilled up to technical depth, and it's a discovery. We are beginning initial indications. It's encountered 8 oil-bearing reservoirs, 355 feet of gross hydrocarbon pay and 205 feet of net pay. And at the minute, we are looking at data acquisition analysis. Effi will probably pick this up in his section. And then the Amukpe-Escravos Pipeline, that's the pipeline that will take our Western asset volume through Escravos. That was mechanically completed. We put some oil into it. And now what we're doing is finalizing the commercial agreements, which will enable Chevron to lift that oil from Escravos' term loan. That's injection expected in March. So next slide, Slide 4. Just quickly, we'll run through the group production. Dark green there is liquids, light green is gas. And you can see there over the last, I guess, 8, 9 years that we're running in '21 47,693 of production, slightly at the lower end of guidance. And that's largely because of the force majeure at Forcados. And then we can look at the reserves. Again, we are at strong reserves. We have outlined the reserves on the right-hand side there by asset. And you can see the bulk of the reserve sits in OML 4, 38, 41, but obviously, OML 53 has got a material reserves on the ANOH gas and condensate. And then you can see the working interest production full year by assets. So let me just hand over to Effi, who's going to run through our operations review.

Thank you very much, Roger. Good morning, again, everyone. I hope you're all keeping safe as well. So 2021 has been a very challenging year for us overall. But if you look at the performance we're discussing today, it just shows the degree of robustness we build into our business. Resilience also always talks about. And on the P&L that is, of course, the new strategy which Roger talked about. So -- and also the transition, which I think has been quite successful, still working from last year. So if I then start on the HSE side, I think if you look at the indicators, this is really world-class HSE performance by any standard. We're able to manage the pandemic successfully in 2021 would land a lot on that and consolidated down landing into 2022. We had no major impact of pandemic on our operational activities across all project site, production sites. And we've done extremely well in that regard. So we did a lot of tests. You can see over close to 14,500 COVID tests across all our location and offices and very, very low positivity rate. If you look at the latest trend early this year, we're actually down to almost 0 positive cases. So based on that, we have conscious strength in our proactive health merger program looking at all indicators and driving really, really top quartile operational health performance across our offices in Lagos, Sapele and Warri and also all the field locations for -- that's on health side. On the safety side, we've done very well, 3 years without LTI in a very challenging environment. We've done about 28 million man-hours, no LTI. That translates to the lost time and frequency of 0 and total recordable case of 0.27. This is a really, really outstanding performance. We're doing a lot around trying to get our logistics space also up to speed in terms of drivers' capability assessment and also building a part of improving journey management for safety, which is a big issue in Nigeria, like you know. We're also strengthening asset integrity process safety management. This is one area we've done very well. These assets are quite old. So we're looking at reducing loss of primary containment and spills. If I move on to environment, we were focusing on implementation of compliance across all our assets, so we can meet all regulatory requirements. And I noticed an area where [ Orogho ] is quite very, very clear in terms of our complements to ESG. Also we keep driving our ESG commitment going forward. The other part we spent a lot of time on putting in place a very clear road map of how we're going to take down carbon with focus on greenhouse carbon emission based on the work on the flare -- ongoing flare reduction project. In 2022, we continue to develop and implement and improve our overall greenhouse gas EMP decarbonized and -- decarbonization program. We're looking at implementing sustainable development plan, which includes biodiversity action. We run out a new set of HSE framework to further strengthen and drive excellence in terms of how we manage HSE service assets. And lastly, we did a lot around internal process safety. We're revamping our emergency response system and crisis readiness processes. We're also looking at even at the front line, simplifying and operationalizing our core HSE framework around electronic permit-to-work system, lockout-tag-out of critical equipment, incident management and contractor HSE performance regarding HSE. I'll move on now to liquids performance. Just like Roger mentioned, if you follow our events up to the media, we were way, way towards the high end of the guidance up to middle of last year in June. Unfortunately, in August, SBM of just the 2 more modern systems of SPDC was with the operator of the terminal field. So the terminal was shorting, and that's how we ended up [ those ] deep. You see on the right-hand side of the production performance in August and September. The out-of-door SPDC was what took us down. All the assets were running out. All these assets are over 90%, 95% availability for works we don't have control, but the challenge has been on the export terminal. And that's what impacted our overall production for last year. You see we come towards the low end of the guidance. So average working interest production was just over 9,000 barrels of oil per day, slightly below the 33,714 in 2020. Off-time wasn't too bad, 25%. If you take out the Forcados outage, the challenge has been on the Forcados side. And we do have -- we did get a bit of a slightly higher reconciliation losses in the East. Five wells were drilled successfully, Gbetiokun 6, 7, 8 and 9 and Umuseti 7. All these wells came in within prognosis and have also delivered combined potential that's slightly above expectation. We did not only do so recorded better initial potential. Also these wells came in at really, really significant material cost saving, which shows the effort we're putting in to try and drive down our drilling cost across the portfolio. In the East, as part of our derisking strategy, we did operationalize the contract we signed with Waltersmith Refinery and the site taking about 2,000 barrels of oil per day. And the last bullet point here, I think which we're really proud of is the results which Roger just mentioned. We did a lot of work around prospectivity of OML 40 well. Sibiri is actually one of the best prospects in our portfolio. That well was successfully TD-ed earlier on. It's been on prognosis. If you look at what was the prospect, and what we found out that the valuation is ongoing with 353 gross hydrocarbon pay and a net of 229. We're currently doing a lot of wireline logging, open hole data acquisition. That will be followed by all the valuation required, PVD sampling, well testing and eventually, we'll come back in terms of the reserves discovery. On the right-hand side, we did also notice that our capital investment in terms of new wells have actually gone very well this year. We added very new potential of just over 18,000 barrels per day gross and $130 million of cash on the gross side. I'll move on to the next slide around our Amukpe-Escravos Pipeline. I know this has been a very long project, but good news is now we're really getting to see the light at the end of the tunnel. That project is pretty much at the very final phase. We will launch it pretty much very soon. In terms of what we have achieved to date, we have mechanically completed that project in January. We have introduced as part of the commissioning process, we increased work time to the line first, and then we introduced hydrocarbon down into the line in the Chevron terminal. We are now working on finalizing the commercial agreements for the crude handling and also the offtake. And once that is done, we will then inject a hydrocarbon into that line. We're looking at before end of March, we will start to use that line in terms of exporting. And hopefully, the first offtake will then happen once we build an off-cargo for the FS offtake in Q2. AEP offers us a really step change in terms of driving of uptime for Western assets regarding availability and also very low losses because the pipeline is pretty much HDD. The barrel depth is over close to 30 meters at some point and 15 meters in some areas, which makes it very difficult for any third-party interference. We're guaranteed about 40,000 barrels per day through the AEP from the Western asset. So this means if you now look at the right-hand chart, it just shows that we're actually looking at about 6 export routes, 4 I indicated on the right-hand side. First one is the line that goes to the Chevron terminal. And there is the tee-off option we can obtain of that line to the NPSC tank farm. And there's another tee-off that goes on to the TEP, which then gives us another evacuation all the way to Forcados terminal, actually TEP pipeline, which takes production from OML 40 into Forcados and then the option of going to FSO offshore. If you add all these 4 indicated options and then add the water refinery option and the TLP option, then you looking at potentially 6 routes. So this is a major, major achievement. I think it was really, really -- we're proud that when we come fully on production next in March, we'll come back, and I'll give out the share updates on the next call. On the gas side, I think average working interest production for gas is just 108 million scfd of gas a day, slightly above performance last year. The outage of Forcados did impact the associated gas production in the Western asset. But overall, we're still able to hit the part of the plan which we have set up for this year. Government has done a major review of the domestic supply application price review, and that led to a slight reduction in the gas price from $2.50 to $2.18. And we also went back to discuss one of our customers, NGMC, in terms of the potential impact of this reduction. And that's part of also why you saw a slight reduction in the Q4 gas production. But the good news is we've been able to land a new contract now with NGMC. We're ramping up production back to the level to take care of our full IPSC, and this should only be a major issue again for the rest of the year. In terms of the gas wells, we successfully drilled 2 new wells, Oben 50 and 51. And as part of our cost reduction initiative, we have planned to drill 4 new gas wells. But based on the creative work by the asset team, we're able to substitute those 2 new wells with 2 workover wells, which means we're delivering wells at the same -- for the same potential. We're now actually doing work over the fraction of the initial CapEx of the new wells. This has led to really, really material savings in terms of our capital cost for the wells. And it should not play out in our CapEx utilization for 2021. So finally, I'll move on now from the base assets where we have established really, really strong operational excellence to one of the projects which we're working towards completion, the ANOH gas processing plant. Like you know this is under the AGPC SPV. We've made a lot of progress on this asset -- on this project. In spite of all the COVID-19 impact in the past 2 years, all the equipment that was fabricated in Florence in Italy by [ deals ] and GPS in Dubai, they've all now been delivered to the sites. All the foundations are pretty much complete. All the civil works are pretty much done. We've now started and started on this equipment on the foundation. So overall, completion of the foundation is about 90%, and we're now going through the very last phase of the installation. So far, we've made a lot of progress, we've installed pipe racks, the inlet manifold, compressors, quite a lot of the position equipment on the E-House. So that's gone very well. Overall, project completion at this were 84%. We're very fortunate. Our projection this year is by second half of the year, we will be mechanically complete regarding this project and ready for start-up for introduction of gas into the class. Now we have some delays around things that are out of our control. The OB3 pipeline, which have a very small scope remaining, they've had some challenges with crossing the River Niger, but we think they will be able to surpass the challenge within the next quarter. The real big one is around the spur line. The spur line has been manufactured in China. Payments have been made. And we're hoping manufacturing will start in Q2 and delivery to Nigeria sometime in Q4. And that will require a couple of months doing the installation and then enables now hook up the gas plant to those lines, so we can then do the commissioning for the plant. In terms of commercial side, I think that's going very well. We're able to complete a funding $260 million loan from accordion, which gives us enough headroom that will happen in February 2021. We've also signed condensate offtake agreement with Vitol, and also the LPG agreement was also signed with local offtakers. And the key element of this part is part of our decarbonization strategy here is to drive LPG penetration into the local market. And that displaces biomass cooking and firewood, which is a big challenge in the country. So this is very much in line with what we said at the strategy, also Capital Market Day last year how we're trying to drive Nigeria's energy transition using gas transitioning field. So on that note, I think it's been a remarkable year from an official excellence point of view, project delivery, very challenging. But I think we're very optimistic 2022 will even be better year. I'd like to hand over now to CFO, Emeka Onwuka.

Perfect. Thank you very much. Good morning, all. We'll continue to show a very strong and robust performance amidst all the challenges that Effi just highlighted. The crude oil prices improved for the most part of last year, and we achieved realized crude price of $70.54 per barrel. And that took up our revenue by 38% to $733 million. And we have achieved an adjusted EBITDA of $372 million. PTT for last year $177 million -- was at $177 million. We continue to generate significant cash flow through the year with $341 million of accrued cash on the balance sheet with net debt at $426 million. This improvement from previously with $440 million for 2020. With the dividend we are going to declare this year, we commenced our ordinary dividend regime last year. And we'll see how the final dividend to declare and that's difficult to assess as one do. And in terms of the unit operating cost this year was $9.90 in terms of BOE. I'll take you to Slide 13. Slide 13 shows the split between oil and gas revenue. We see oil revenue at $618 million, 48% up on OpEx over last year. We had an amount of equipment of $4 million. This mainly on OML 40, applying IAS 36 on the payments, we had in 2020 were about $114.4 million impairment on that. Finance cost includes $20.4 million one-off costs related to the financial last year and JV partners managing account payments on their cash cost. And as such, we have some kind of lower balance today on JV funding. You see $10 million if I get one-offs that we had there last year. I'll take you to Slide 14, Slide 14 is on our CapEx spend. Let me talk about the one we did last year about the drilling and completing 8 wells, a capital of $137 million value for the well drilling and also for preparation for Sibiri exploration that Effi also discussed. And also, we also achieved some reduction in terms of -- we talked about the savings on the walkabout business of new deals, our main investment. And I said to Effi as well, all within the $137 million CapEx for last year. I'll take you to Slide 15. Slide 15 shows the sources and uses of the cash we generated last year included our $324 million, excludes restricted cash $341 million like I said earlier. The next slide shows robust liquidity. Apart from the cash we had on balance sheet, we also have undrawn RCF of $350 million. And all together, we have over $700 million liquidity available for utilization by the business. I'll hand it back to Roger.

Thank you, Emeka. Okay. So just on to the final slide, Slide 18, just highlight what's ahead of us in this year. Obviously, we've been doing a lot of adjustments to the business in terms of leadership, that's embedded in. And obviously, there's been some Board changes and everything else. And again, that's a clear plan of how to execute that. The next point there is our strategy, and we've laid out a 3-pillar strategy. And so we've got very clear plans of how to deliver on these all 3 pillars. But heavy, of course, the focus will be on the first 2, the upstream oil and gas and the midstream gas business. After [ '19 ], the Mobil Producing Nigeria Limited, MPNU new transaction. We said we're expecting that to close in H2 2022. It's still subject to regulatory and government consents for that transaction. We will develop a prospectus as we laid out on Friday as part of the reverse takeover on the London Stock Exchange and relisting. And we just think -- and then it will be basically looking through the project management office to engage with teams to look at onboarding the transactions. But as we laid out very clearly on Friday, that's very much we're looking to continue to operate on a stand-alone basis because there's a lot of people coming across as part of that transaction. And in terms of production guidance, we set that out at 50,000 to 60,000 barrels of oil equivalent per day for this year. Liquids, 30,000 to 35,000 and gas, 116 million to 150 million scf a day, which is 20,000 to 25,000 barrels of oil equivalent. It's quite a wide range, but we'll revisit that most likely in the half year and seek to tighten it. Then just highlighting Sibiri. We put out what we can in Sibiri at the minute. I mean, it's a discovery. It is extremely good for us to open up OML 40, just North Oklahoma. But it's too early to say exactly what's there. They're still doing data acquisition and assessments. We'll put out a separate RNS on this once we're very clear on what the volume metrics are, et cetera. So that will come back more towards the end of this month or early next month. And then the final one there is ANOH plant. It's frustrating for us that we are seeing a delay there. We've identified it now to be very clearly the spur line. And we're monitoring that very carefully with NGC, our government partner, just to see when we can get that completed. On the right-hand side then, we lay out the CapEx for 2022. And you can see the big fat bulk of $160 million is focused on development production with $20 million on asset integrity and $30 million on and exploration and other projects. Our priority is of the first, end of routine flaring, and that is a very clear plan to taking that down to 2024, ensuring our gas obligations are met, looking and progressing on significant projects, drilling sustained production, arrest decline and looking for growth where we can. And we're going to see that the cost reductions we're already seeing in the drilling program, embedding ESG focus on all assets on coming out with very clear targets on that. And then production and export security is top priority. I think that largely gets derisked in the Western assets with the -- and we described our pipeline system. Okay. So thank you very much for listening. Now I will just hand it back for Q&A.

[Operator Instructions] Your first telephone question today is from the line of Alex Smith from Investec.

Just a few questions on ANOH, please. Previously, you were highlighting that you were under budget for the project. Could you outline the -- potentially the extra costs associated with the delay and the amount of CapEx for ANOH in 2022 and 2023 given the delays?

Okay. First of all, we don't see any additional CapEx increase. I mean, we're getting very close to completing the plant complete this year for us. So we don't see any CapEx going into next year. Obviously, we'll be commissioning testing. The key thing here is it's a 23-case spur line because in order for us to be able to ship that gas, OB3 that needs to be complete. So we don't see any increases in CapEx. In fact, we've been actually looking at CapEx being reducing slightly from the original plan. And so we don't see that, Alex, going into 2023, no concerns from our end.

Next question is from the line of Nikolas Stefanou from RenCap.

It's Nick here from RenCap. I have to -- 3 to ask please, if you can please answer them. So the first one, I just wanted to go to the dividend outlook, now that, that will be delayed. Roger, if I recall correctly, your dividend policy is based on stable gas revenues. And now that ANOH will probably kind of like ramp-up in 2024, is 2024 the year I should expect a dividend increase? That's the first question. The second one is actually on the production target for the year 2022. I noticed that it does not include ANOH. And it looks a bit aggressive compared to 2021. So I just wanted to get a sense that are you expecting basically that Amukpe-Escravos' pipeline will be completely operable and so that you'd be able to evacuate all your crude from there? So that's why you're effectively assuming higher uptime in the West assets? Is that the main driver from kind of like the increase in 2022 versus the 47,000 barrels per day that you produced in 2021? And then the last question is if I could get an update on the new energies business that you announced in May, I believe. Any projects you have identified, any progress there? That would be helpful.

Okay. Nick, just -- so the few questions. The first one on the dividend. So what we said in the dividend is that any growth in that dividend really has to be underpinned by growth in revenues. And of course, one of the big things, obviously, is the ANOH project because not only does it bring dry gas sales, but it also brings in LPG sales and probably more importantly, the condensate sales. So it's quite a significant ramp-up. We'll only revise it upwards. So I think, look, with the delays coming in on first gas into 2023, then the knock-on effect, obviously, will be that there won't be the revenue. So you're right in that aspect. And therefore, what we'll then do is relook at that dividend probably in 2023 and see where we can grow in the long term. And obviously, the other factor this is going to be is what do we do with MPN, assuming we get all the regulatory consents done then we then need to assess the impact of that acquisition has. And of course, it will have a longer-term benefit to the plc from additional cash flows through dividends. And therefore, we'll actually then look to reflect that. So yes, I think it's fair to say that, that will -- dividend policy will probably stay the same in the short term. In terms of just answering on the production, so yes. I mean, I wouldn't say we're aggressive on that. I think we just looked at it quite conservatively on our production. Two bits to it. One is, as you say, the AEP, that being on stream, and we really want to see that operational this quarter with oil flowing through the terminal. And then obviously, you see how that performs. We don't -- we have got 40,000 a day production knowledge on that. We don't have our full production complements in the West. But then, obviously, there's drilling. So there's wells been coming in, and that will increase production as well during the year. So it's a combination of all of that really impacts on the -- positive impacts on the production numbers, and we don't see it being aggressive. We see that being realistic. And then the new energy business, just around the energy business. Look, what we did is we said is a clear plan of transition to the future. And we said that the transition from what we call pillar 2, which is the midstream gas business going down into gas to power, I think that's the most likely shorter-term scenario where we go into electricity in-country and in a sort of off-grid way on a willing borrowing sort of basis. The bridge, of course, then into renewable energy is most likely going to be solar. We are looking at some solar opportunities today, but we've got to be very clear is how do we build out scalable business? How do we then transition from that pillar 2 to pillar 3 business in the longer term? And that, the team has been working on. We've been bullish in the team, bringing some expertise into the business, which we will then bring in this quarter or early next quarter. And then you'll start to see some generation of development in the pillar 3 business.

Okay. And just a quick follow-up. If I go back to the West assets, well, except ANOS, of course. I mean, those were always constrained by the downtime at Forcados or the TFP. So I just want to get a sense, what do you think you can take production to if you don't have this downtime because of the AEP? It's just -- I just want to get an idea of where you would kind of like focus your drilling activities. I presume you're going to target more of the kind of like a condensate or oil wells just to grow oil production further as well. So just can you give me a sense of what that could be?

Effi?

All right. Thanks, Roger. Thanks, Nikolas. So I think just to build on what Roger just explained that -- let me start with that a little bit on the second question, I'll come to this one. So AEP basically takes our uptime significantly higher. Today, we're running about 20% downtime. [ 8 billion ] comes in, we're looking at uptime less than 10%. So that's one big change and then the reconciliation losses, which was in the worth of around 10% to 12%, pushed down to almost some like 3%. So that incremental step change in performance, it's part of why you see that change in the range. The second part, which I already talked about probably didn't give you an explicit numbers is if you look at our capital investments this year, we're drilling about 16 new wells. So there's one present well on the [ Warri ]. There's one exploration well in Sibiri. Obviously, those wells don't -- are production and then 4 other wells. We have 10 wells, 10 development wells across the Western assets, around Oben and also Amukpe and [ H O ] we're doing initial completion. And then we're doing 3 new wells in the East in Ohaji South. And also in OML 40, we're doing 2 wells on Opuama. If you gross of all those wells, they all come in different points in the year, but absolute add somewhere between 8,000 to 10,000 barrels per day fresh new production gross. And if you then add back to the improvement in uptime we see, that's why you don't see really is more robust range that had last year. It's not just been aggressive, like you said, just like Roger explained. So very confident that the range of giving reflects our investment level, also the derisking work within around the export terminal. I did mention that all our assets have been run at over 90% availability, which is really top quartile. The challenge though is around either the export pipelines or the terminal. Coming back to your point around what we're investing. So we're drilling 4 wells in -- sorry, one initial completion and 3 new wells in the West. And also in Eland, we're doing 2 wells in Opuama -- sorry, 3 wells in Opuama and also Sibiri appraisal following the success. So in terms of the export route, you're right that AEP will derisk the Western asset. There's a whole lot of additional work going on around surveillance to run new strategy security, which then brings a bit more higher uptime on the TEP, the line that provides a our operational route to Forcados terminal for OML 40. So in summary, therefore, the investment in new wells and also our production growth is very, very highly underpinned by a lot of the changes we're making around derisking export through, Nikolas. I hope that explains or addresses your last question.

[Operator Instructions] Next question is from the line of Uwa Osadiaye from FBN.

Congrats on the results. My questions are around the acquisition of MPNU assets. Firstly, what challenges do you expect, if any, in getting final approvals? Secondly, on Friday's call, I recall you mentioned a potential LNG project or possible projects in oil and gas, which is mixed with oil sands. In terms of domesticating the huge gas potentials on that asset, how are you looking at pruning it? Are you thinking of actually investing at the moment to invest in gases reserves, some projects such as [ Afren, Ciampa ] and so on or rather just to yourselves as the gas provider? On the relisting point that you mentioned, I didn't properly hear what you said. Do you mind explaining this point, please?

Thank you for that. Just on your third question, could you just repeat that?

The first question?

The third. Third question.

The third. Okay. I said on the relisting point you mentioned, I didn't properly hear what you said. So if you could, if you don't mind, reexplaining that point to me?

Yes. I don't know it's -- we're finding it very hard to hear your third question even when you repeated it. Maybe even just a bit slower. Just say that again, please?

Okay. Let me go again. You -- on the relisting point once you're going through your outlook -- yes, the relisting point, I didn't probably hear what you said. So I'm asking if you could explain this point to me.

Yes. Okay. All right. Well, let me -- okay, so in terms of government approvals, it's a very clear set of approvals. So MPNU is the acquisition of the shallow water assets, Mobil Producing Nigeria Unlimited, the sellers of those assets is 2 Delaware-based companies in the U.S. Because it's a company acquisition, it's very clear that there's a clear path through -- obviously, we need to apply through FCCPC, which is the Competition Commission to ensure that there's proper competition here. And then there's also going through the NUPRC, the old DPR process, which will range up through to the Minister of Petroleum, which, of course, is the President. So it's a clear set of processes you need to go through demonstrating predominantly operating capability, strength, operational technically and also financial robustness. So in terms of that process, we're very clear in what that legislation is. And we work through from when we announced it on Friday, we're now working through those approvals process along with the seller, Exxon. In terms of the various projects on gas, I mean, look, what we say is be very clear that there's going to be a domestic element to it, which is, obviously, at the minute, they're selling gas anyway from the assets, a lot of the gas gets dried and reinjected. And what we want to be looking at is what domestic plays we could do. That might be supplying power plants, doing power plants or other industrial consumers within Nigeria. I think that's very much the strength of what we have. We're one of the biggest domestic gas players in country. But also given the size of the resource here, which we estimate to be around over 7 Tcf of gas, this really lends itself to longer-term export plays. And the obvious one is LNG, whether that feeds into the existing LNG trains within Nigeria or there's a real ability here to create an LNG play with these assets directly. And we foresee a big demand in LNG into the future. We really see it today with Germany announcing 2 LNG trains. I think a lot of Europe will go this route, and I think it gives an excellent opportunity for Nigeria to capitalize on that. But it's too early at this point to really put any meat around the bone. We have only announced the acquisition. We haven't got in to fully understand what we can do and work with the government partners. In terms of the relisting, the reverse takeover process, which is a technical delisting and a relisting. What happens is we are standard listed on London. What that means is that we have class tests, and we have to -- and given the size of the acquisition, it requires us then to provide a prospectus. And we will work through that and provide that over the coming months. The -- because we're not premium board listed company on London, there is no need for a shareholder vote around that. So what would happen is that we provide the prospectus. There will be a technical delisting and then a readmittance as part of the larger group. But that's -- we don't see any execution risk on that at all. It's just a technical mechanism that's required on London.

The next question is from Ayodeji Dawodu from Standard Bank.

Congrats on the results and the pending acquisition. I have just 2 questions really. The first one is on the gas business. Following the reduction in the DSO prices, has there been pressures from, I guess, commercial contracts to reduce prices there as well? And my other question is really just generally on downtime. It seems over the last 2 years, it's been progressively higher downtime across a lot of the terminals in the oil-producing region. I guess from the interactions with governments and regulators, are there any initiatives being brought on to improve this downtime? Or are you looking at any initiatives to improve this downtime?

Okay. Thank you for that. Let me just answer the first one, and Effi can answer the downtime. So in terms of the pressure on the gas prices, I think with the PIA coming out and setting effectively what the lower domestic gas price and there's an industrial price there as well, and there has been some pressure on that. A lot of our business is obviously contracted, so long-term gas supply agreements. That is really the future of where we want to go with that business anyway. And so we haven't had downward pressure on the gas prices around that. I think the PIA is setting this up, but actually, what it does is transitioning to a willing buyer-willing seller model in 2023. And that's where I think it's good for Nigeria to go because what that will then do is drive what the market price of the gas is. And so we see a short-term play. Yes, there are discussions from players around looking to actually drive down the gas price. We think it's a short-term play. And longer term, we'll see a recovery in gas prices because the alternative is, as we've identified clearly, the alternative is imported diesel-fired off-grid power, which is 5 to 6x what the cap -- on-grid gas price is. So I think certainly, economically, it makes a lot of sense for Nigeria to go gas. But it needs to be on the market related gas price. Effi?

All right. Thanks, Roger. So thanks, Ayodeji. So on the downtime, you're right that we did mention that even in Roger's opening statement and my segment that 2021 has been quite challenging if you follow the events in Nigeria across whether in terms of sabotage, in terms of third-party defense. But if you look at the landscape, it's -- I think it's a bit different from the West and the East. The West actually hasn't been that bad last year to be fair. The challenge in the West has been with the SPDC-operated Forcados terminal having the majeure problem with the SP, the single more invoice system, which enables export. So there has been some failure in August -- in July, August. And then in December, they brought in a Jacobi unit to try and fix the SBM. And the Jacobi unit got stuck. That will happen. But in terms of the pipeline uptime, the West -- rightly that around Forcados or sorry, TFP, the TRP and the TEP, which are the 3 lines that go into the Forcados terminal. So it's a bit of a different kettle of fish but overall, I think SPDC is now in works with the SBM. They have repaired one, and the second one has been repaired now so they'll have redundancy regarding addressing that export challenge within terms of the SBM. And then the pipeline of course that deal worked to improve the off-time. And then our AEP then comes in nicely then to pretty much derisk that whole issue around the TFP pipeline. Hopefully, Escravos Chevron time-operated terminal will not have the SBM kind of challenges SPDC faced and Forcados. So that is West. So overall, if you look at last year's performance, losses were actually low, around 10%, 12%, and off-time wasn't too bad from a pipeline point of view if you correct that of the terminal issues SPDC faced. If you go to the East, it's a different kettle of fish. So in East for us, we inject crude into the TNP. That goes to Bonny and also inject through from Jisike into the Adag delivery line that goes to Brass and [ Boucha ] and Brass Terminal of places like [ Egypt ]. Yes, indeed, the Adag delivery line had a lot of sabotage last year. And the TNP, which is operated by SPDC, also had a lot of time. We had a lot of workshop last year with the government. I can tell you this is the #1 priority on the GMD list on the former DPR, the new NUPRC, while it was the former director. We had a lot of engagement with him. The new CEO for NUPRC, Gbenga Komolafe. This is also top of his list. There's been a lot of government intervention. If you fully what happened in real estate, for example, Governor Nyesom Wike actually mandated that end to sabotage in the East. And we'll start that play out in the results. So in December, losses was around 90% in the TNP line but in January that's come down now to about 70%. So a lot of holes in the intervention, comes in, we think, with government now taking a really leading role, and we supporting on that effort. We anticipate that the sabotage will come down significantly going into 2022 because the government is actually the biggest loser -- the losing -- loss and loss of revenue and all their JV investments across the country. So it's quickly number one. It might be some coming back to your point, lots of intervention with government and security agencies, the OPTS collaboration platform because this also impacts on IOC's production, not just IPPG. So lots of work and I am optimistic that we see towards the middle of this year the results of all intervention playing out at [ IoDCCG ].

This concludes our question-and-answer session, and I would like to turn the conference back over to Roger Brown for any closing remarks. Please go ahead.

Okay. Thank you. So thanks, everyone, for joining. Obviously, 2022 is going to be a defining, a quite sizable year for the company, very clear what our strategy is. The focus in this year is going to be efficiency, getting the drilling in place, getting the production and managing the downtime and then obviously embedding in the new acquisition subject to government consent. So thanks, everyone, and look forward to talking to you in the Q1 results in April. Thanks.