Seplat Energy Plc (SEPL) Earnings Call Transcript & Summary

Ladies and gentlemen, welcome to the Seplat's Q3 2020 Results Conference Call. My name is Stuart, and I will be the operator for your call this morning. I will now hand you over to Roger Brown, CEO. Please go ahead.

Thank you. Good morning, everyone. I hope everyone is keeping safe in these tough times. This is the Q3 or 9-month 2020 results call for Seplat. And if I just now move to Slide 3. Before I do that, let me just make some introductions. Obviously, Roger Brown, the CEO. On the call today, we have Effiong Okon, who is our Operations Director; and we have Emeka Onwuka, who is our new Chief Financial Officer. So if I just then move, obviously, to Slide 3. Let me just run through and kick off the call with just some of the macroeconomic events. Look, everyone be aware of this, obviously. But obviously, we've had quite a shock to the oil price, with COVID-19 and the Russian price war against -- with the Saudis. We saw some respite in this coming back in Q3, some recovery around the $40 barrel levels. But what kicked in for us in Q3 was OPEC cuts. So the -- Nigeria is complying with the new OPEC reduction -- or production reduction cuts. And they've really started to bite in, in Q3, predominantly for our -- more for our Eastern assets, [ there are 40 ]. In terms of Nigeria, with regard to COVID-19. Touch wood, Nigeria has been reasonably lightly affected and quite a little number of cases and a little number of deaths as -- at the current date. So, so far, so good there in terms of COVID-19. In terms of what's happened with the COVID-19 restrictions on our operations. Again, Effi will pick this up in his section. But we've been lightly affected there, and we've been able to continue to operate in a safe manner with the quarantine of workers, et cetera. So that's worked reasonably well through the quarter. And then you'll have seen, recently, we had the SARS demonstrations, which is obviously with the police and some difficult incidents with protesters in the army. That has resulted in local ban restrictions within Nigeria. We're just starting to relax now. But we've been able to, again, operate through those tough times. Moving on to Slide 4. And let's just run through quickly on the 9-month 2020 performance highlights. And the key figures are boxed. So you'll see there, with the volumes, we're within guidance. We set quite a wide range of guidance in March from 47,000 to 57,000 barrels of oil equivalent. We're narrowing that, and we'll show you that in a second. But our guidance -- our production as of the Q3, it's just slightly less than 51,000 barrels of oil equivalent within the guidance range. Our revenues of $388 million, and they're down to last year, also down to oil price reduction predominantly. But you can see that in the cash balance, we're still maintaining a strong cash balance of over $213 million. And a lot of that actually sits as USD. Quite a lot of it's offshore as well. And looking at the performance metrics. Production, again, as we said there, within guidance. Although Effi will run through this in a bit more detail, so I'll just skip this. In terms of our focus. The focus is on cost reduction and efficiency. Our dollar per barrel OpEx cost is $8.73 per BOE, and we're looking to continue to drive that down further. And we've been pretty good with cost reductions with about 30% across with our suppliers, et cetera. In terms of the balance sheet, it remains strong, and Emeka will take this up in his section. But you can see -- you'll see that we -- even after CapEx and dividend payments and reduction of debt, it's a strong balance sheet and our receivables position is reducing. In terms of the oil price. We've had average oil price for the 9 months at $38.60 per barrel, and we continue our hedging program. We're hedged out in Q4 of 2 million barrels in total, a mixture of between $30 and $35. And we're hedged out in Q1 2021. We'll probably put in a Q2 hedge shortly. In terms of the CapEx. It's increased, it's $109 million in total so far. And there's a bit more CapEx put in Q4. And then in terms of major projects, ANOH remains on schedule for Q4 2021 for first gas, and we've done scenario and modeling on that. And we're comfortable with that time line. And then Amukpe-Escravos pipeline will -- again, will be picked up in a couple of slides. But unfortunately and frustratingly, we've had to slip the timetable for completion of that. Let me just pick up on Slide 5, some of the recent corporate developments. Obviously, the -- I took over as CEO on the 1st of August, and Emeka came in as the CFO then. We're looking just to make some internal realignment, reorganization, with a real focus on efficiency. In these times, it's essential to be efficient operator. I'm still looking to make some management changes, which we've done already of our top team. The asset managers now report directly to the CEO, and that's just to give more visibility around their asset performance. But I'll be heavily supported by my executive team, the Ops Director, Technical Director and, obviously, the Chief Financial Officer as well. We've created a New Energy unit. And this is really -- as we start to move the business through, obviously, keeping our traditional upstream business and make it efficient, we're then looking at lower carbon technologies. Our gas business is really very active in terms of cleaner and lower-carbon gas business, but we look to expand that and then look at other lower-carbon energies. We've created a New Energy unit to focus on it because I think it's a slightly different skill set. We've re-tweaked strategy and business development, and that's something we're beefing up. We've created a technical training and development Centre of Excellence, which is in our Aberdeen office, when we acquired that from Eland. And that is really to look at new technologies, looking at support of the overall group, training and, obviously, some business developments. We've done some merger in terms of our Corporate Services department; created a new research and sustainability area, and this is really the focus on our ESG drive-out. And then we recombined General Counsel and Company Secretariat together. And launched a change management process, which is going through the rest of the organization and just aligning. And we've set a time line for Q1 2021 to complete that. And then just a couple of words on our sustainability initiatives. I've talked about the New Energy group. But we've also had ESG consultants on board for most of 2020. They've done a gap analysis already. We've presented this to the Board with our strategy going forward. And we will be coming out shortly with our performance measurement, et cetera, and aligning with the major standards of the TCFD or the IPIECA, and you'll start to see that come through in our full year reporting in Q1 next year. So -- and finally, we just say we're going to -- we'll organize a Capital Markets Day probably in March next year, and we'll go through in a lot more detail. Okay. So moving on to the next slide, I'll hand across now to Effi Okon, our Operations Director.

Okay. All right. Thank you, Roger. Hello. Good morning. Can you hear me? Hello?

Yes, Effi. We can hear you. Go ahead.

Okay. I'm just testing here because the speakers are off [indiscernible]. So okay. Thanks, Roger. I'm going to run through the operations update, just like Roger did mention. I'm on Slide 7 now. Hopefully, you can hear me. So it's been a very challenging year for us. Not just us, I think, globally, with the impact of COVID-19, every business has been impacted on. But I think I'm really proud to say the way we managed this has been quite impressive. So we had a very clear, robust strategy at the onset of the pandemic sometime in Q2. And that meant a real focus by the top leadership team of Seplat and also Board oversight. And that's how we've been able to manage the pandemic in such a way that it has had no impact on all of our activities, be the production site, the project site, drilling site. I think we're one of the very few companies here that has been able to have a very smooth continuity in all aspects of our operational activities. We also put in place a standard operating procedure, which we then refined and tweaked over time as we learned a lot more about the virus, the transmission system and also what other companies were doing around the oil and gas, both locally and globally, through the [ OPTS ] and through a number of networks, which we put in place. I would say that has been quite very successful. We have to refine our modus operandi. All the staff working from Lagos remain to work from home, WFH, which is a new normal. Field staff hard to change the work cycle to 7, 21, 14, which means we now -- we have to do PCR testing for everyone going into the field. And that's how we've been able to manage these in a very, very successful manner. I think that would be around COVID. We're still learning. We're still monitoring the situation with the second told wave, we were picking up in globally. But just like Roger mentioned, we have been actually very, very lucky, to some extent, that would not send the sort of fatal rate, which has been established in Europe or in America and the Western world. So on that note, I think you didn't see that play out in the production numbers. We're still very much within our guidance. So as of end of September, we delivered just slightly over 50,000 barrels of oil equivalent across all our assets. If you go back to where we have the H1 call, we're very much also within guidance. You see a little bit of drop between H1 and where we are today, and that's mostly attributable to the very unfortunate incident we had at the Gbetiokun asset, which is the asset we got through the Eland acquisition, where we lost about 7 people. That asset is operated by NPDC, just to be very clear, and we were just carrying out a fabric maintenance work on the BRS -- BRVS station. So that led to -- once that happened, of course, by regulation, we have to shut down the production facility, investigation with all sorts of agencies and then report our shared and then clear recommendations put in place before we're allowed to reinstate production. We're back on production since, I think, from the 12th of August. And we have ramped up production to maximum capacity since then. Gas production has been quite stable since the turnaround maintenance in the first quarter of this year. That has restored integrity, and we're seeing much higher reliability of that plant so far. And that's going to go into the next few years to ensure continuous delivery of gas supply from the gas plant. Average gas price was $2.88. Again, COVID did impact some of our customers on the gas side, but begin to pick up again towards the end of the year. And finally, on the production side, we didn't see OPEC playing out, so Nigeria had a big cutback. This country produces about 2.2 million barrels of oil per day. The country was asked to cut back to about 1.5 million at the onset of sometime early in Q3. Later on, even as low as 1.3 million barrels of oil per day. And that cutback was also then distributed across all operators. So it did have some impact, especially on our Eastern assets, where we had to shut down production by about 20%. On the western asset, we're leveraging on the fact that we do have some bit of running room with the light oil and condensates, which are normally not part of the OPEC quarter. So we haven't seen that impact too much around the Western asset, which accounts for over 60% of our production, as you all know. We're working with the regulators, DPR. We're also working with the commercial team in NNPC. And we've seen that relationship actually playing out positively. They've just given us additional quota of roughly about 6,000 barrels per day, which gives us enough flexibility now to finish the year even stronger than what we saw in Q3. So in summary, pulling all that together, we're standing very strongly behind our guidance, but we've sort of narrowed that window a little bit down to 48,000 to 52,000 barrels of oil equivalent as of full year liters view for 2020. I will move on to Slide 8 now. Slide 8 just gives you a broad overview of our portfolio. What you see here is if business started from the heartland, I call it heartland in the West, the Western asset, which still accounts for 100% of our gas business out of Oben and Sapele. And then you then see that asset still accounts for over 100% of our gas supply. Over time, as ANOH comes on stream next year, you then see us begin to move towards our strategic ambition of moving towards the 1 Bcf process capacity company, 1 Bcf of gas per day processing capacity, which is very much at the core of our strategy as a company as we continue to grow that gas sector. Just like Roger said, this is part also of our own energy transition as we begin to move more towards a bigger share of oil versus gas in that mix. And then you then see, on the oil side, you see the Western assets still also kind of large share. But over time, as we begin to grow the rest of the portfolio, you see the Eland investment coming in at over 8,000 barrels per day. And also OML 53, which is also -- will have the ANOH asset. You see that also coming strong in gas for the time. And also the OML -- OPL 283. Overall, I think if you look at our reserves base, just over 500 million barrels of oil equivalents. At current production rates, you're looking at the results production life of somewhere between 15 to 25 years. All depends on the depletion pattern we'll take going forward. This is quite a robust portfolio, and it's beginning to see some bit of diversification across the Niger Delta. Looking at that slide, you don't see our access to about 3 terminals, Escravos, Forcados and also Brass and Bonny. Hopefully, with the work we're doing with the Amukpe-Escravos pipeline, that then gives us access to the Escravos terminal as well. So that's basically a quick broad overview of our portfolio geographic distribution, the results overview and also our production intensity across those assets. I'm going to move on to Slide 9 now, just to give you a bit more flesh around the operations. So the key one is around the BRVS, which I've talked about. We didn't give a lot of details around what happened earlier on in the H1 results. So that's now back up. Downtime at Forcados, tank top, the terminals and also reconciliation factor losses were very much within provisions we made for 2020 business plan. And then also, our wells program is going on as planned. We have to cut back, if you remember, in terms of capital investment programs, to fuel wells. So, so far, we delivered the Sapele, Ovhor and Ohaji South wells and also the Gbetiokun well. We keep pushing the cost rationalization, optimization to try and drive down costs, improving efficiency and agility in terms of how we manage our operations across the entire portfolio, and we see that playing out very nicely. And you probably see that when the CFO goes through his financial slide to see how the cost savings also played out in terms of our bottom line performance. The last slide point on that, on the left side of the slide, is around our Amukpe-Escravos pipeline, which I will talk a bit more about in the, I think, in the next slide in terms of where we are. Or maybe I'll just talk -- tick through that now. So I know it's been quite a very, very long journey on this pipeline. But the honest truth is we've made huge progress. We have laid lines between assets and the connection to the pipeline. The pipeline is in place. It was basically hydro tested, intelligent pigging carried out and dewatered last year. So the pipeline itself is ready to go. The remaining scope is just within the Chevron terminal, and this scope covers the LACT unit, which is already in place. We're doing the software installation and also the commissioning. The fire safety systems has been installed within the Chevron terminal. Another system integration and control room integration will determine what the Chevron terminal infrastructure. All that scope of work only requires just 3 months to complete. Once we're done with that 3-month scope, then we're ready to go live with introducing hydrocarbon to the pipeline. Unfortunately, [ wall at ] this pipeline, which is owned by Pan Ocean, has gone through some tough times. The license was revoked earlier on, and then also the AMCON debt. What I understand now, AMCON is somehow reached on kind of settlement with Pan Ocean. And also clients around the ownership has been provided by NNPC and hopefully, in the next few weeks, once all the paperwork is sorted out, we'll then be allowed to go back to the terminal to now resume the remaining project scope. So if all goes as per plan, I think we should be ready to now do the final set of commissioning sometime first half of next year on the road to bring this pipeline on stream. So long journey, but we're almost there. And I hope we can share some really good news when we have the next call next year. On the gas business, I think we've done very well. We've filed production of about 100 million scf, pretty steady for the first half of the year. We're doing 2 more wells this year. Oben-49 has been drilled and completed. We'll start unloading that well the [ next one week ]. Hopefully, we get to [ steady state ] production early November. And then the last well for the year will be Oben-50, and that comes on stream towards the tail end of the year or early next year. Sapele gas plant decommissioning has started. We have provided update to the market earlier on that we have invested heavily on an old bit of a brand-new gas plant that comes into Sapele. The new gas plant would be about 75 million scf of gas per day. That plant will take out all the flares around the Sapele axis and then hopefully help also improve gas delivery to all the customers in the Western axis. And we're also going to be producing at [indiscernible] spec gas, which can also go into the urban gas delivery line. ANOH is doing very well. We're still on track for Q4 next year first gas. All the 6 contract modules have been executed. The first 3 module gas processing is -- by a global process in Dubai, that's gone very well, almost 80%, 90% completion. The compression system that was for certain equipment in Florence, Italy is also pretty much on track. The civil works on sites were doing extremely well in that. The last to scope around pipeline lane and also the installation contract are all being -- they're all in the final stages of award now. So once that happens, the modules will begin -- will be shifted to Nigeria from, I think, early next year so we can then start installation work. And hopefully, by second half, we'll be ready for start-up and commissioning. On the financing side, I think all the equity injections have been made successfully. And now the debt part is also almost at the final stages, with very good opted by a lot of banks. That's also gone extremely well, [ although subscribed and short ]. I'll move on to Slide 10 now. Slide 10 is bio integration. We did talk -- tell the market earlier on that what we're doing now is trying to get the best of 2 worlds. So we'll look at what Eland was very good at doing, what Seplat is very good at doing. And bringing those 2 together has been a very good marriage, where we then leveraged on all aspects of our business. We're driving that whole integration to maximize synergies and also savings across the business. So far, I think, on the nontechnical side, we've consolidated all the support function. We're looking at all our locations, our resource distribution. We're also optimizing in terms of systems, HR, payroll, finance, legal. In terms of external affairs and community projects, we're also leveraging on the collective experience across Seplat and also the [ Gbetiokun aspects ]. And we're working on that integration, and this is something that'll run into 2021. On the technical side, we're also looking at our operational synergies across. There's been a lot of that already happening between the assets in the old Seplat portfolio and the Eland portfolio, driving, practicable, replicating and maximizing best practices across the portfolio. Same with the subsurface and exploration expertise. We will begin to look at our subsurface robustness, subsurface imaging and also exploration prospectivity work. And hopefully, very soon, you'll see decisions have been making the round. We want to put our best, [indiscernible] and the next best exploration prospect across the entire portfolio. And finally, we're also looking at trying to understand the cost base and see where we can maximize synergies to drive down material cost reduction. So in summary, on the right-hand side of this Slide 10, we then see the Seplat staff distribution, about 500 people in Lagos, Abuja, London and also Sapele where we have our base office. On Elcrest side, you see 27 staff in Aberdeen, which is going to be our Centre of Excellence to drive capability development, especially for subsurface staff, where we have -- want to leverage on most recent technology in terms of optimizing the depletion strategy for assets. And also new business development and also new energy, just like Roger mentioned earlier on, as part of our energy transition strategy. And also on Elcrest Lagos office, we also have 112 staff. So all these put together, we'll start seeing a lot of benefit of this integration going into 2021. I think my last slide is on Gbetiokun incident that happened at BRVS. So I stress our thoughts and prayers with the families. It's been a really, really painful exercise. We've had a lot of deep dive reflections, learnings on all the gaps that came out of the investigation work. And this learning has actually been implemented across the entire Seplat portfolio, not just only on the Eland side of the business. So in terms of the actions we've taken so far, we have asset investigation, we've had a lot of deep dive with DPR, who led the investigation, with NPDC/Elcrest. We had also an independent investigator. All these have led to a lot of presentation, not just to the NPDC/Elcrest side of things, also to the Seplat Boards and the Seplat committees. They've had a lot of deep dive and looking at what came out of those learnings. And the real biggest -- the biggest gap in that whole incident was the permit to work system. We've taken a lot of action around closing all the gaps. Action borders on the HSE management system framework on how safety is managed across the company, with the right tone from the top. Lots of documentation has been put in place now. The culture is also being worked on. We'll have to set up an incident review panel. Every single incident has got to be reported and investigated. And whole lot of transforming the safety culture in the organization and leveraging on our experience in Seplat. And finally, I think also we are really providing lots of support to that Elcrest effort to really drive the overall safety culture improvement. We also did provide a lot out of our duty of care. We have provided a lot of support to the victims, all the burial, the funeral arrangements were all supported, financed by our company. And also, we have provided scholarships to all the children of the deceased, from primary all the way to university level. And that's really very much at the core of our strategy, our focus to be able to make a positive impact on the society and trying to support people as much as we can. And that's something, I think, we're really, really, really proud of. So on that note, I'd like to hand it over now to the CFO, Emeka. Thank you very much.

Thank you, Effi. Good morning, all. This is Emeka Onwuka. It's a deep pleasure to meet all of you. This will be my first interaction with investors. I'll take you straight to Slide 18 (sic) [ Slide 13 ], which gives some of the financial highlights. We will continue to operate intelligent translation environment. However, we'll continue to prudently manage the finances of Seplat to reflect historical strong finances of the company. And this reflected in the sub highlights we have for the 9 months up to the end of September. And the revenue for this time was $388 million, is a drop about 22%, reflecting the impact of COVID and the drop in oil prices. In terms of crude revenue, we had a drop of 5.3% to $205 million. We have realized oil prices of about $8 this year, as I guess, the half figure for last year. However, we -- it had an [ equity effect ] from the production coming from the Eland assets. Working interest production for this period, highlighted already at about 13.9 million barrels of oil equivalent. In terms of liquidity on the balance sheet, we're still very strong, about $213 million of cash on the balance sheet. Net flow -- net cash flow from operations these 9 months of $187 million. We will actually repay the $100 million part of the RCF loan that we have. That $100 million is still available to us. We'll make a repayment to receive on interest. And also paid dividend for -- final dividend for 2019, which are about $29 million. So after this 2 major outflows, and I want to share on that slide in terms of that, we'll see how the strong calculate on $230 million on the balance sheet. Unit cost for this time was about $8.73 per barrel of oil equivalent. This has gone up because we have also consolidated the cost of production in Eland, which is higher than the Seplat. However, we are aggressively working down on the cost operational of Eland as reflected in the detailed reports, where you have the budget cost, which were previously above $14 per barrel, been worked down to $5 per barrel currently. Our net debt position of $479 million, a reflection of our total debt of about -- is currently under our cash of $213 million that we have in the bank. The G&A has been worked down. I'll talk about the cost saving initiative in a different slide. Our CapEx for this year is $109 million so far, and we're targeting to close $120 million. And this study shows have been undertaken to improve the performance of the assets. NPDC receivable, this year, we received, so far, about $152 million. We received about $147 million from NPDC and is down this year to $152 million from $222 million for the same period of 2019. I'll take you to Slide 14, which is also for a summary of the results. We talked about the lower revenues arising from the oil price war and realized average price of $38 for this period. The gas revenue for this year does not include tolling, which was a one-off income for 2019 and realized the price of $2.88 per million scf of gas during this period. Our operating expenses now includes Eland business expenses. And we also have done further impairments on financial assets this period, both bringing the total impairment so far for the 9 months to $158 million. I'll talk about the CapEx cost for this year. Okay. We'll go to the next slide, Slide 15. We -- the federal government has directed E&P companies to renegotiate and cut across 30% across our suppliers. We are currently doing that, and it is reflecting in the drop in the cost of -- in our cost for these 9 months and it will further reflected in this very last quarter of the year. We'll talk about the barging cost in reduced on the Eland asset OML 40. And also other costs, such as travel, legal, hospitality, rents and other that, which, of course, reflects the reduced travel for this period, also being worked down. On the next slide is our cash position, which has still remained strong. We added, like I said, about $107 million from operation in this period. The major cashout led -- be the OpEx of $109 million, the repayment of $100 million on the half year and the payment or [indiscernible]. At the end of this period, we have about $200 million on our balance sheet for this period. The last slide is Slide 16 (sic) [ Slide 17 ], on the capital structure, which have been amended following the acquisition of Eland. And also, currently, like I've said, our total base as shown [ $92 million ]. This also incorporates the RBL on Eland with about $100 million. Most of the debt are 2022, maturing 2023, and we are currently working on pushing further down the majority of the debt in terms of renegotiating and restructuring the loans that we have. So overall, the capital structure remains very strong. We have very good liquidity. And for these 9 months, the Board has approved and announced a dividend of $0.05 per share. I'll hand over to Roger for the outlook.

Thanks, Emeka. So let me just run through the outlook before we go to Q&A. And so on Slide 19, we just lay out a timetable for investors of the key derisking events. So, obviously, the first one there is ANOH financing. We've talked about it. The last dating item really there is finance -- the financing, and that is doing extremely well. So we're almost there on that, and we should be announcing that shortly in Q4. And we have a lending group, mix of local and international banks and the joint financing team with the government. So that will end the projects that we funded. And then the schedule on the project in terms of delivery and Effi ran through, that's still on track for completion in Q4 2021. And that's really out of first gas there. Obviously, we are a 50-50 JV with the government in corporate joint venture. And so the dividends will flow back up. 50% of the dividends will flow back up into Seplat Plc. And what this really does in first gas is really strengthens our position as a leading gas processor in the country. And that's very -- an area that we really want to drive and develop, really delivering gas, which is effectively displacing expensive diesel-generated power in country. And therefore, there are a number of environmental benefits from that, from greenhouse gas reductions and CO2, et cetera. So anyway, that first gas Q4 2021. The Amukpe-Escravos pipeline, we are so close to it. But again, we don't control all the nodes in that, but hopefully, we can get that completed. But for planning purposes, we put that to H2 2021. Hopefully it comes in earlier than that. The next event really is the Sapele gas plant upgrade. That is where we're taking the Sapele gas plant from 60 million scf to 75 million. And we're putting an LPG module on that, which will then take any flaring we're doing at Sapele and enhance the economics of that project selling LPG into the local market. And then the last real event is that we are looking at exploration across our portfolio. We've been doing that for a while, but we have a dedicated group on it. There's some really good exploration prospects. And we will then look, at some point, coming up in 2021 and 2022 at potentially putting in an exploration well. On to Slide 20. The guidance, as we said, is 48 to 52, and we're just short of 51 at the minute. Hedging, we continue to hedge. We talked about that previously. And we're obviously doing deferred premium puts on the hedging that's the same strategy we've had for a while. And we're hedged at Q1 2021, and we're looking at Q2 for a minute. And then CapEx for the full year guidance will be $120 million, with $109 million spent in the 9 months. Looking at the short-term value drivers. The new gas wells coming on stream in 2021, which we filled this year, so that's 75 million scf. Looking at production increases at OML 40. And the export on OML 40 is the current Escravos pipeline, which is different from the Trans Forcados pipeline. So it's a different route into the Forcados terminal. In terms of the third one there, which is greater and more reliable output expected from 4, 38, 41, as the pipeline gets put in place. And it probably means around 1 million barrels differential from the Trans Forcados per annum. So it's quite material. We -- having -- we're also looking at it. We're not coming out with any real detail yet, but we're looking at a dedicated export route for the OML 40 and our Western asset production. I think that's really the long-term solution for here is not underlie on -- solely on the Forcados and Escravos terminals, but actually they get potential our own rating for exports. Again, a 5-year uptime. These are just efficiencies that we're looking at. Looking at the highest producing wells, et cetera, the more bang for a buck. And then, obviously, gas flaring is one area that we want to eliminate. Our longer-term drivers is really this long-term displacement of expensive electricity in Nigeria and putting in place cheaper gas-fired electricity, which is really where the government wants to deal with it and Seplat's really driving that with the government. The ANOH coming on stream, given the 300 million scf. And there's lots of opportunities for us to increase the skill of our business as we will see more divestments, particularly, we believe, from the IOCs that we start to divest from Nigerian assets. Money back from Westport loan and obviously there we're looking at -- we mentioned there the Amobe prospect that looks a very good exploration prospect at OML 40 that we are looking at. So that really summarizes our future drivers. Going to Slide 21, this is -- this ends our presentation. So I will now hand it back to the organizers to coordinate the Q&A. Thank you.

[Operator Instructions] Your first telephone question today is from Michael Alsford from Citi.

I've got a couple of questions, if I could, please. Just firstly, on the ANOH project, you mentioned in your comments that you've made a sort of risk assessment on the timetable for the project. Still confident on 4Q '21. So I just wondered if you could just elaborate a bit further on what the key risks are to the timetable. What milestones should we be looking for to ensure that the project hits the timetable that you've outlined? Secondly, just on production. I'm just wondering whether you can give some sense as to what the exit rate will be on production for 4Q. I'm just trying to get a sense as to where we could see maybe production upside into 2021, given the wells drilled in oil, the gas -- the capacity at Sapele, for example. And finally, just wanted to elaborate a little bit more on the impairments, the financial impairments that you made in the quarter, as to what they are. And should we expect more of those to come in the future?

Okay. Thanks, Michael. I'll answer the first one, and Effi can deal with the production, and Emeka can pick up on the third question. So in terms of the ANOH project. Yes, we've done -- we did quite a detailed risk assessment on it. We ran 5 different scenarios looking at the impact of COVID, et cetera, and the other areas. And I guess the key risks for us is, obviously, the OB3 pipeline being completed. Now that looks like they're making some very good progress with the HDD in drilling, the [ din of river crossing ] at the minute. That's where it's been delayed previously, but there's a new contractor and more comfortable that they will get the OB3 pipeline figures end of this year or Q1 next year, and well in advance of first gas. The other issue we've been looking at is a small spur line to connect into that OB3 pipeline. And again, we're getting comfortable now that, that will be completed in advance of the project. In terms of skids coming in and all the other rotating equipment, we're very comfortable with that. So I think we really are narrowing down the risk timetable. The other gating item, of course, is the debt financing, but I think we're in the short strokes to complete that. Effi, do you want to answer the production question?

Okay. Thanks, Roger. Hello. Can you hear me?

Yes, go ahead.

Okay. So on the production side, Mike, and it was an asset, we build capacity, we call it IPSC to what that asset can produce on a good day with no export terminal issues or export line. The IPSC of the Western asset now is roughly at about 75,000 barrels of oil equivalent per day. That's just all liquid, but that's 100%. If I want to put in a working interest term, you're look in at roughly about 30,000 barrels of liquids per day. If I go to Eland, in terms of IPSC, Eland is also roughly about 10. So if you add that, you're looking about 40. And then in the Eastern asset, we've also built IPSC, working interest [ mobile ]. So in total, we're looking at [ asset rate ] for liquids across the portfolio somewhere between 40,000 to 45,000 barrels of oil equivalent per day based on the IPSC. On the gas side, we did say we've had a very steady roll on the gas, it's about 100 million scf. With the 2 wells coming in, those 2 wells, they're going to add about 75 million scf of gas per day. If you then take a working interest of 75, that then means about 33. So that means we're looking at exiting the year on the gas side at about 133 million standard cubic feet of gas per day. Again, that -- those telling you -- looking at the maximum potential, actual production is then driven by OPEC quota [ and annual constraint ], but that's what the IPSC projection will carry now for end of the year. So very, very robust portfolio of production, underpinned by operational excellence. On the Sapele gas plant, I didn't get your question. But we're basically decommissioning the old plants now. That project, similar to iron ore, a lot of the components have actually been fabricated in Houston. And the plannings are based on our projection, so we'll try to wrap up the decommissioning phase now also starting -- started civil works, piling foundation. Next year, once the components get shipped from Houston to Lagos, through customs, we're looking at starting installation in the second half of the year, in readiness for commission and start of late 2021 to early 2022. Mike, I hope that addresses your questions.

It does.

Okay. Mike, I'll take the impairment question. We made for impairment this quarter, in respect of OML 55 and [indiscernible], this is coming as of [ short form ] expectation of our share of production during this period. And other financial assets that we have, we have to reassess them and took a view [indiscernible], all totaling $19 million.

Next question is from the line of Alex Smith from Investec.

Just a couple from me. First one, just on Escravos. And I guess it has a material impact and is a big -- and it was previously quite a big derisking event for the company. And I understand it's frustrating that it's under your control. But H2 2021, that seems quite far away. In April, we were looking at final commissioning commencing. So is this just more of a conservative estimate? And what do we need to kind of reach completion and gain access to the terminal? And the second one, just on the receivables. The balance is clearly coming down from the start of the year. Just how is the relationship going with NPDC? And do you expect that trend to continue?

Okay. I'll probably...

Effi, I'll just pick up these questions. I think just in terms of the timing. Just, look, Alex, just in terms of Escravos, we're extremely close to, yes, H2 2021 is quite far out, but that's really for planning purposes and everything else. There is probably 2 to 3 months' worth of work as a maximum. It's just -- we're getting very close at getting access into the terminal to complete that. And that's a little bit of work. Effi ran through what that was going to be in terms of the works to complete. So again, when you're not controlling the time table, you're not in control of all of the nodes that's why we've had a pretty conservative completion there. In terms of receivables, NPDC, the relationship is very good. It really, over the years, has continued to improve, even in these difficult times. And we've got a very clear understanding of how we're going to develop the assets, and you can see that in the receivables balance producing. So despite the tough times, we're reducing the receivables, and the relationship is going from strength to strength.

Next question is from the line of Dragan Trajkov from ARC.

A couple of questions from myself as well. In terms of -- if hypothetically, if we assume that the OPEC quotas remain for quite some time, can we assume that actually your production is likely to stay somewhere in the 50 to 55, if you have a bit more gas? And what kind of CapEx would you need to maintain that production for the duration? So that was my first question. And the second question, NPDC and the NGC, indeed, receivables have been down -- going down. In your receivables, there's an item called National Petroleum Investment Management Services that seems to go up. Can you give me more information on that? And I can take that offline as well if you don't have it readily available.

Yes. Let me just deal with the receivables. And then Effi, maybe you want to comment on the range, the OPEC impact. So in terms of the -- the National Petroleum is NAPIMS. NAPIMS is our partner in OML 53. And we've just had a little bit of a rise there in terms of -- the government has been driving down cost savings of 30% to 40%, and that's delayed some of the approvals around that. But the relationship is strong with NAPIMS, so we'll continue to work with them and we'll bring that balance down NPDC and NGC. So we really don't -- Dragan, we don't really have any concerns with our government. We just continue to work with them as a partner. Effi, do you want to deal with the range in OPEC?

Yes. Okay. On the OPEC quota, so basically, what -- the way we manage OPEC quota, over time, is we've always had a sort of deferment provision in our forecast of roughly around 20% to 30%. And the way it works is the government does monitor our production delivery on a monthly basis. So that means that early parts of the month, we normally will ramp up to maximum capacity and only run down towards the end of the month when there is no major outage of the export pipeline. So that simply means that the OPEC quota constraint of around 2020 [indiscernible] deferment. At the same time, we don't have a quota, don't have an issue. So for us, we're pretty confident around the number you just mentioned, Dragan, around 50,000 to 55,000 barrels of oil equivalent overall. Now this has already developed potential. So you do need a new CapEx to basically deliver those production volumes. The only 2 -- the only CapEx we're spending for the rest of the year is the last Oben well, the Oben-50 well, which is the last well we're drilling this year. Now going into 2021, just to build on my earlier response to the exit rates discussion. We've built very, very good capacity, which will take us at least into 2021. And then we're looking at our 2021 work program and budget at the moment, and that will determine what level of CapEx investment we're still going to be making next year for new wells in the gas and on the oil portfolio. But overall, the 50,000 to 55,000 range you just quoted is pretty robust with quite a number of actually allowance around that to keep us into the much longer part of 2021. Hope that helps, Dragan.

[Operator Instructions] The next question is from the line of Nikolas Stefanou from Ren Cap.

It's Nick Stefanou from Ren Cap. I have 3 to ask, please, for Roger. First question is with regard to the dividend. I think consensus for Brent is, I think, the next 1 to 2 years, it's probably going to be a range bound within $40 to $50. And I was wondering, given that you've got a strong balance sheet, a robust free cash flow generation, how do you think of that building going forward? Is $0.05 going to be the new normal? Or would you be willing to pay $0.10, given that, I mean, around that price range I just mentioned? The second question, see, with regard to your gas aspirations, and in general, how you think gas growth will play out going forward. It is often the case in Nigeria about [ funding a labor source ] of demand, it's easier said than done. So I was wondering if you'd be willing maybe to move down the value chain in order to unlock that gas demand potential. First of all, your option was to go higher in the future. Is that something that you guys consider? And then my final question is about the Petroleum Industry Bill. Any thoughts, views? Is it like with your expectation? And any color you can give us will be helpful.

Thanks. I'll deal with these questions. Okay. So first, in terms of dividend. Look, we obviously run pretty low oil prices in this range, the $40 to $50 you're talking around in terms of a forward planning. And what we're paying now is a $0.05 interim dividend. And what we try to do is pay a core dividend of $0.05 and a top-up of $0.05. That is what we will try to do. So there is a commitment to shareholders. Dividend is very much part of what we're doing. And obviously, it all depends on macroeconomic conditions. But assuming that we -- the world doesn't go down into full lockdown again, and we see $20 oil prices, we're looking $40 to $50 oil. We'll be expecting to pay the core. That's what we promise and then we would also like to be looking to top up to the $0.10. And in terms of going forward, ultimately, we would like to grow the dividend. But really, that's why we're investing a lot in our gas business. We believe that will be a growing revenue stream. And that could be something that we can look into the future. So in terms of your second question, the gas aspirations. We had a strange situation that, within Nigeria, you have electricity generated by burning hydrocarbon oil, predominant electricity sourcing country, which is extremely expensive. And the gas-generated electricity is probably about 1/4 of the price. So there is massive demand, but there's a gap in terms of accessing that demand. And that will take time, we believe, but we believe it will be ultimately solved, getting people off expensive diesel-generated power on to gas. In terms of then, how do you manage the value chain. Yes, we are looking at further down the gas value chain, looking at maybe capturing more margin as well. And that's what the New Energy group's really looking at. We're also looking at opportunities in regional gas as well, particularly into neighboring countries. And that's something we're looking at to manage the gas business going forward. And then the final question on PIB. Look, we, as an industry group, that will be PTS group and the IPPG group, which is made up with the major oil companies operating in country and also the indigenous players, we all came together. We've commented on the latest draft of the PIB, which is an Executive Order just coming from the President. I think there are investment areas that need discussion, but it's certainly heading in the right direction for the PIB. So our fingers crossed that, that PIB will be passed. It's certainly, I think, so in my experience of looking at this for quite a number of years, it's making some very good progress that we've not seen for years. So fingers crossed, it will be passed. And I think it would be workable for us. It will certainly analyze what impact it will have for us as a business. And we think, with some slight changes, it will be reasonably neutral for us going forward.

That's very helpful. Sorry, just a clarification on my second question. So is it going to be maybe the case that you might want to maybe invest in midstream? Or -- maybe gas and power, like IPPs or something? Like how are you thinking moving down the value chain? Like in what way?

I think like in terms of midstream, yes, we will grow our gas processing. We're looking at with ANOH and others, Sapele gas plants, et cetera. We're looking -- we're putting on LPG out on all our plants. We're looking at CNG opportunities. And the big question is, is do we then go into power? And we've not made that decision. It's a big strategic discussion at the Board whether we go into that and ultimately moving into renewable energy. Renewable energy will mean going into power. So not fully decided yet. We still do a risk assessment, et cetera, on it. But certainly going further down the value chain in the midstream processing, absolutely, we're doing that.

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

Okay. Well, thank you very much. Thanks, everyone, for listening to the Q3. We're looking forward to coming back to early next year, Q1, for the full year results. And just ask everyone to stay safe and keep investing in us, please. Thank you very much.

Ladies and gentlemen, this concludes today's conference. Thank you for joining. You may now disconnect. Goodbye.