Seplat Energy Plc (SEPL) Earnings Call Transcript & Summary

Ladies and gentlemen, thank you for standing by. Welcome to the Seplat 2020 Half Year Financial Results Conference Call. My name is Haley, and I will be the operator for your call this morning. I would now like to hand you over to Austin Avuru, CEO. Please go ahead.

Thank you. Good morning all, and welcome to our half year result broadcast. But let me just start with a few key highlights of our results. As you all know, we've -- industry has been hit by a combination of COVID-19 and the earlier pricing war -- oil pricing war between Russia and the Kingdom of Saudi Arabia. And so oil prices took a huge downturn, particularly during the second quarter, but a recovery now over in the past few weeks, around $42, $43 for Brent. Now the price recovery itself has been driven by OPEC costs, OPEC and Russia and a few other countries to combine that require substantial volumes of the market. The result also is that Nigeria been a member of OPEC has had to cut down on its own national total production. These costs have been handed down to all operators or producer, including Seplat. However, we have managed these costs in the case of Seplat in such a way that it has had very little impact on our net working interest production as we see shortly. The COVID-19 itself that has ravaged the entire world, its impact to Nigeria has been quite muted, not as much. Just about last night to cross about 41,000 cases, which still with less than 900 debt as at yesterday. I mean these are horrible figures, that's relatively related to the rest of the world has been very mild figures. The lockdown has been enforced in most key areas. However, even during the peak of the lockdown, oil and gas operations being very critical to the national economy. We are allowed passage and so as a company, within the rules of managing the COVID pandemic, within the WHO rules, we still were able to carry out operations in a very measured manner that ensure that even during the peak of the crisis, our production operations and even drilling operations went ahead. So from an operational point of view, the COVID-19 has had very minimal impact on our operations this past 2 quarters. And so we've been able to deliver a little above 51,000 barrels oil equivalent per day over this period, well within guidance. We still remain low-cost producer, $7.6 per BOE, which is at average production cost. Balance sheet remains strong, $343 million in the balance sheet. As we said, oil price is recovering. Overall, average for the first half of the year, we realized $34.94 per barrel. Remember that we hedged out 60% of our production during this half at $45 per barrel. We have also hedged out -- now the $45 hedge goes on to the end of Q3. I'm going ahead to place $30 per barrel hedge for Q4, just to be sure that the entire year, the 2 halves of the year, we are covered. $86 million of CapEx invested in this first half of the year, and we'll start seeing the impact of these investments in our future revenues. Our well drilling -- that's a revised drilling program for the entire year as well on cost. In fact, most of the wells will be treated during this first half, which is why you also see that CapEx investment during the first half relative to the total budget for the year is quite heavy, which means it will be much lighter CapEx for the second half of the year. We keep focusing on cost reduction. That is key. As a matter of fact, we are now taking a close look at all our operations on the assumption that even if oil prices were to stay in the $30 to $40 range, we should be able to operate and still be cash positive. That's our target. So -- and the only way to achieve that is to focus on cost reduction and bringing all our costs down. So we are negotiating almost like a blanket 30% reduction savings from our suppliers, which, in fact, was a government request. In OML 40 well, we have highest cost because of budgeting their [ back ] operations. There, the logistics are quite expensive. We are reducing those costs rapidly until eventually, we deploy a pipeline solution that will bring the kind of low cost that we want to see in that asset. And as I said, the balance sheet remains strong even after CapEx and dividend remains, and all our deadlines are well within headroom. So we -- it's nothing at all to panic about. Our ANOH project, it remains on schedule. Even though it was a few weeks impact of COVID pandemic on our suppliers and contractors, but it's largely, as you see today, still on schedule for commissioning in Q4 of next year -- first gas in Q4 of next year. And the Amukpe-Escravos pipeline, I think, we're heading now very closer to the finish line. And we think we'll be putting crude oil -- we are exporting crude oil through that pipeline in the second half of the year. So those are the key highlights. Let me now invite Effi, the Operational Director, to give us the operations update. Thank you.

Thank you very much, Austin. Good morning, everyone, wherever you are. And I hope you're all keeping safe and well and fit. So I will run through the operations story. So overall, I think it's been pretty successful for us that we have managed the operations. Just like Austin did mention, at the onset of the COVID pandemic, we will have to trigger the crisis management team, which we term the COVID Monitoring Group, COVID mark. And based on that, we're able to assess all the risk to the business, following all the guidelines provided by World Health Organization and CDC, the local government authorities, the states. And I think we're glad and we're delighted to say that in spite of the challenges on complexity, which the pandemic brought into the business, we did not have 1 day of shutdown. So all our project activities -- production activities, drilling has been pretty much on plan on target, and we haven't had any case of the virus in our staff or work population space. So that's something we're very proud of. We've also been very active to support the government effort in terms of policies and all kinds of intervention through the IPPG and also the AMPC group as the overarching body providing support to the Nigerian government effort to contain the pandemic, which I think has been quite successful. So I think we're glad and we're proud, and I would pay that as we continue to manage this risk, it doesn't really impact our business. So production for first half is pretty much within guidance. I think we're in a much better position this year compared to when we had the same call as of mid last year. We're pretty much on the middle side of the guidance, roughly around just over 51,000 barrels of oil equivalent. And that we made possible through our continued operational excellence across all our production sites, short-term of duration. [ We have ] reservoir sovereigns management across the portfolio of wells. And now we were able to address the decline. We also successfully completed drilling a hookup of 7 new wells in the first half of the year. 4 of these wells around western asset, 1, Gbetiokun, and then 2 in the eastern assets, and then 1 gas well also in the western asset. And that's been the reason behind the numbers you're seeing. Eland integration is ongoing. If you look at our production volumes on the liquid side, Eland delivered roughly just over 30% of our group volumes as of mid-year. The other good news also is the export lines weren't actually too bad in East Brass and Forcados and Bonny terminal, where pretty much all the trunk lines leading to the Eastern terminal were quite stable. The only area we do have -- we did have a challenge was around the western asset in the famous Trans Forcados pipeline. But we made assumption, and that was pretty much in line with our plan. Thus, for Q2 was also ahead of us -- ahead of plan. The turnaround maintenance we completed in Q1 has been very successful. We have a much robust high availability Oben Gas plant now. And that's what's underpinned our gas production. And I know we will have this discussion in Q1. There was a question around why our gas volume is less. But we didn't make that provision in our business plan for this year that we will have to shut down the Oben Gas Plant for 2 weeks. And that turnaround maintenance was extremely successful on time budget and also quality. Looking forward, I'll say OpEx quota, which we all been tracking, post the OpEx plus maintain recently. I think we saw some bit of easing coming in, in the second half of the year. The assumption did advice help push our restriction in July, August offtake. And we have been able to manage that within the range of our normal deferment assumption. So there's been no impact on the OpEx push our restriction so far in the month of July. And we want to be able to manage that going forward. And also, we still kept our guidance within range as earlier advised, early in the year. I'll move on to the next slide, Slide 7. So I think I've called out what I had on Slide 7, but a few more granularity around Slide 7. So the Eland production very much now becoming an integral part of our business. You can see over 30%. Part of our production liquid comes from Eland now. The uptime on the Forcados terminal, the trunk line leading to the terminal, very much in line with our assumption. Reconciliation is also -- was around about 10%, so not as bad as 10%. I talked about the world I came in on time. We're driving cost reduction. And I think, so far, ever since we talk about the acquisition, we've made quite some significant progress. That remains a real big focus area for us. How do we drive the Eland asset towards top quartile in terms of cost performance. And then they were all driven by government. Now we're seeing big savings in terms of our cost ambition. Amukpe-Escravos line as well. We always talked about it. So far, I mean, we've tested that line, hydrotesting, which is part of your commissioning. And that has gone extremely well. What's remaining now in the Amukpe-Escravos pipeline is project scope within the [ Sapele ] terminal. And that scope covers large unit installation, integration, some pipeline connection. And once that is done, we'll then go to the full hog of commissioning that line. What's actually left to be done is pretty much straightforward. But the pandemic is also impacted access to terminal, and [ surely at Sapele ] is extremely, extremely conservative in terms of how they're managing that -- this pandemic, taking a lot of guidance from their global headquarters in the U.S. And that's why you then see the impact of that on the timing. Our gas business is doing very well. I did talk about being pretty much above plan in terms of target. I talked about the [ tolling ] maintenance is quite successful. We brought 1 well on stream, Oben-48. ANOH is also going very well. All the production sites in Italy, Dubai where the process vessels are being made, all where they're taking the equipment in Italy is pretty much on track. We're hoping that we should deliver first gas sometime in late next year. The team is also working on the financing part, the debt equity. Hopefully, we should land that conversion by second half of this year. But no showstoppers and especially with a lot of interest in that exercise. I'm sure Roger will touch a bit more on that as well. Well, Sapele Gas Plant decommissioning, we have kicked off the decommission of the plant. The idea then is to bring in the brand-new Sapele Gas Plant being built by JPS and DGS. Part of it has been probably cited in Houston. We're working towards a shipment of a lot of modules by India next year. And hopefully, sometime in 2021, '22, we will then commission and bring that gas plant on stream. The plant is designed to deliver roughly over 75 million standard cubic feet of gas per day and about 5,000 barrels of condensate. Looking forward for the rest of the year, we did share our scale back CapEx program with focus on cash reservation and managing our liquidity. So we'll to do just 2 more wells in the second half of the year to support our gas business. And those 2 wells are planned to be drilled in the next 3, 4 months. We've actually started remobilization with spots happening mid-August. And my last slide is on the safety incident we had on the asset we just acquired in Eland. So our thoughts and prayers with the families who've lost all their loved ones. It's been quite a tragic and very, very sad incident, which should cause really big across the organization. And just to put a bit of a caveat here, we're not the operator of this asset. NPDC operates the assets. By the JV, like you all know between Eland, by virtue of equity on Eland, Seplat is also in that whole relationship now between Eland, Start Crest, NPDC, which forms the JV called Elcrest. So what happened was on that one faithful day, the team was basically carrying out the fabrication work to modify a platform, which then allows much bigger base to comment on best for the part of the whole exercise around how we inject crude into the [ Gbetioku ] pipeline. So was the fabricational exercise on the platform, and there was also a plan to change out the 6 inch hose, and all these improvements were best improve on asset integrity and also to give us a bit more robust vesting arrangement so that much larger budgets can come in and inject and, therefore, reduce the whole logistics complexity around transporting production crude from early production facility to the injection point, the Brass -- or the Bonny Benin River station, the BRVS. That's the injection point. So on that faithful day, there was ignition, and then we did lose 7 contractor colleagues. So there was no impact to the environment, which was basically just an explosion. And only the fatality that was experienced. Following that exercise, we had a shutdown. All activities were stopped across the company. And then we did the normal GI. We brought in the regulators and then did a quick investigation. And following that preliminary investigation, a number of actions and activities have been triggered across the company in terms of how to address process safety, personnel safety, asset integrity. And also, some of the findings when we ran our investigation shows some bit of gaps around how do you manage change, job hazard analysis, coming to work system, work [ man ] system and also lack of gas detectors. All that has now led to a major improvement exercise around how we drive safety across the Eland asset. I think we will get a bit more details as the investigation progresses. And at some point, we will share that. But the idea is a lot of the deep learnings that have come out of that exercise will also be -- will be applied across all our portfolio in Seplat. So that was all. I'd like to pass it over now to Roger. Thank you very much.

Thanks, Effi. Okay. I'll just run through some of the financial highlights. So usual 3x3 metrics here. You can see our cash balance has increased. NPDC receivables have fallen, and we maintained the 2019 final dividend. So running through just on the far left column. So revenues, they're down on the equipment period last year, largely due to the oil price fall. It's about half of what it was last year. And so that's resulted in a $234 million revenues. Our OpEx, operating costs are $7.60 BOE. They're up from the equivalent period last year, largely because we've incorporated now the Eland asset into that, but there's a big cost reduction exercise underway. It's been very heavy in Q2. We'll start to see some of the benefits of that coming through in the other quarters. So that's $7.60. Still relatively a low-cost operation. Our gas revenue is down, and Effi has covered that. But obviously, the turnaround maintenance has had an impact in H1 -- or Q1 around that. Middle column, loss before deferred tax, we always report this because I've seen deferred tax movements sort of skew the story here. But we've got $145 million loss largely because we've booked a number of impairments in Q1. You have seen before. So that's $145 million loss against the profit last year. Earnings before interest and tax depreciation is $115 million this time and last year. I think CapEx is up in last year as we start to spend -- we spent $86 million of the $120 million so far this year around that. The final column is a cash to the bank. This is something that we've maintained strong and liquidity in our operations. So $343 million, slightly up at the year-end. So it's slightly up at the end of H1 compared to the year-end at $343 million. Net debt is pretty consistent around that. And so therefore, we have $800 million of gross debt on a net debt position of $457 million. And then the receivables something that's really focused on is obviously reduce those, and that comes down to the NPDC down $174 million. Next slide, Slide 11, just run through some of the financial results. So you can see the revenues we've covered. Cost of sales, obviously, the gross profits are down because we have hit probably the lowest, and certainly we host the lowest oil prices with a very low of $17.50 in Q2, but an average of $35 over the quarter. And in terms of gas sales, if you compare last year, last year, gas sales had a tolling in it, and this year's doesn't. In terms of cost of sales, crude handling and DD&A, depreciation, et cetera, we've got some additional cost through barging of Eland, and that's going to come down in the further quarters. In terms of finance costs, in line with what we expect, CapEx recovered. And obviously, we've talked there at the end of good relationships with NPDC, which has driven down receivables even in these difficult times. Slide 12, just running through the cash generation and spend. And you can see that, I think our cash from operations of $176 million. And then our spend to CapEx, we put another $30 million into the ANOH Gas Plant, and that's on track for early Q4 2021 completion. Interest dividends, we've maintained that dividend. And then, therefore, we have a strong cash balance at the year-end. Just covering some of our leverage, our capital structure. At the minute, we have effectively 3 facilities. We have the bottom of the left chart, I'm looking. You got the senior notes of $350 million, and they've been performing pretty well, have come up slightly above par today. The revolving credit facility, these both facilities are at Seplat plc. They're at $350 million, so that's [ $700,000 ] leverage. And then we have a reserves loan, which we inherited, and that sits below Eland, and that's $100 million. That's being redetermined in the half year. So the banks are comfortable with that position. And then the bottom right of that slide, you can see our debt maturities. And largely, the bulk is in 2022 and 2023. So we have no immediate debt maturity issues. Final slide, in here in terms of how do we then use our capital allocation priorities. We've got 4 areas here. So in terms of the low-risk capital investment program, in terms of the gas business, really, it's about growing our gas business. And this is obviously an excellent transition fuel today. So we've been putting a lot of money into developing the ANOH, which is quite a milestone project for us. Drilling gas wells, as Effi talked about, sort demand. And then in the oil business is really to obviously stop that decline but also grow the oil and looking at optimizing production, reducing costs and try to be as cost-efficient as possible in terms of that business. Then looking at -- in terms of reducing our leverage, we are looking to obviously pay down that revolving credit facility. We will probably look to do some of that in Q3. We're looking to obviously refinance Eland's RBL, which we believe we can put in place a more effective facility there. And then obviously, maintaining our optimal cash and debt balances and getting money back up through the Westport 11 to repay some of the investments we've made in Eland. And then in terms of shareholders, bottom left, it's key for us just to maintain our dividend payments. Even in these difficult times, we paid this year-end 2019 dividend. We're looking to target our core dividend. And then we're appropriate where we can, looking to top-up in that in terms of the special dividend. And then the final sort of box there is M&A potential. We still see opportunities in terms of growing our business. I think at the minute now, there are quite a lot of opportunities coming up. And we will then do our usual system through and looking for the right opportunities for us to increase value to the business. With that, I'll hand it back to Austin.

Thank you, Roger and Effi. Now my pleasure to announce that effective Monday, Monday, the third of August, we'll have a new CFO. And I'm sure you know why we're having a new CFO. We haven't fired Roger as CFO. So probably I'll start with regards to introduction. Effective Monday, Roger will be sitting here as the CEO. And to replace Roger, the Board has just hired Mr. Emeka Onwuka, quite a famous banker here in the Nigerian financial community. So he joined Seplat as CFO and Executive Director on Monday, third of August. He's had more than 30 years隆炉 experience in financial services across Africa. Most recently, he's been partner and Head of Private Clients and Family Wealth, Andersen Tax in Nigeria. He served on the Boards of Ecobank, Bharti Airtel Nigeria, previously on the Board of First Atlantic Bank in Ghana and the FMDQ and OTC trading platforms also here in Nigeria. Probably his most notable assignment was when he was Group Managing Director and CEO of the Diamond Bank. That's about 10 years ago. He was CEO from 2005 to 2011, and was also the Chairman of Enterprise Bank. He has a National Honour of Order of the Niger -- Officer of the Order of the Niger. So he comes in as Roger's replacement on Monday as the Executive Director of Seplat and CFO, while Roger steps in here as the CEO to complete the very smooth transition that we started a couple of years ago culminating these changes to happen on Monday. And okay. So quickly, I take you through the outlook and the outlook for 2020 and the key drivers for the immediate future and medium-term to long term. Our guidance remains to keep our guidance at $47 to $57 -- barrels of oil equivalent per day. Hedging, as I said earlier, we have 1.5 million barrels each quarter hedged. In the case of third quarter at $45, Q4 and Q1 2021, taking that out at $30 at 1.5 million barrels each. We keep watching very closely the hedging market, the hedging outlook. We intend to add more volumes in Q4 and Q1 of 2021 in terms of the hedged volumes. CapEx, full year CapEx, $120 million. We've already spent $86 million. We have 2 west [ model ] in the second half of the year. So the CapEx for H2 is going to be much less than H1, but we'll still keep our guidance of $120 million of CapEx. In terms of short-term value drivers over the next 2 years, we'll keep our production increase. That's a key focus, increase our production from -- particularly from Eland's OML 40 and Ubima field. Those will be liquid production volume drivers for us to add to what we have in our traditional western assets. We think there are more reliable outputs from our traditional western assets once we commission the Escravos pipeline in the second half. So that would drive down our reconciliation losses and downtime. So in terms of effective output from the West, we should see an improvement in that. And then we are working on something really critically dedicated export pipeline. And over the next 2 years, that is going to come into fruition. And when that happens, all of our production in the west, including OML 40, OML 4, OML 38 and OML 41, all of that will go through this dedicated pipeline and storage facility that will greatly reduce both downtime and reconciliation losses across our entire production in the West. Swamp operations from [ who else ] provided next 2 years. They are more prolific for us. We'll keep drilling this time. OML 40 has been added into our swamp operations. We're going to see over the next few years some more swamp drilling to maintain and increase our liquids production. And there is exploration potential. We've been talking about the exploration well in OML 40. It's high-grade for us. It's probably the one of our strongest, I guess, swamp exploration well. And that we think -- the success case in that place will improve not just our production, but our reserve base at OML 40. In the longer term, beyond 2 years, we -- gas comes in, somewhat Roger was presenting. By the end of next year, hopefully, we'll commission the ANOH Gas project. So into 2022, we'll start seeing substantial increase in our gas revenues, overall gas revenues. We start getting revenues about the ANOH Gas project. And the ANOH Gas project, we only just started our 300 MMscfd plant a day. As we see more increase in domestic gas demand and also more opportunity for gas around our eastern assets, and those opportunities are there, we'll add more modules and actually increase the capacity of our gas plant as we go forward beyond the next 2 years. And from 2022, we also start seeing the paying down of the $400 million Westport loan. So in addition to all of these cash generation opportunities, both from production and from our gas business, we'll start seeing some cash inflow from the repayment of the Westport loan. So about $400 million sits there and that increment will start coming out of improved production and lower costs in OML40 then we'll anticipate, following all of the activities we see throughout 2020 and 2021, by 2022, we'll start seeing that cash flow coming in. So that's the outlook over the next 2 years and beyond. And as I said from Monday, you have seen a very seamless and fearless transition out of the very top management team. And then -- so that's where we are. Thank you. I'll now hand back over to the operator. Thank you very much.

[Operator Instructions] And the first question comes from the line of Alex Smith of Investec.

Just a quick couple from me. Just a quick one on ANOH. As you mentioned, it's now a priority for the business and for the growth. We're less than 18 months away from first gas. Just looking at what are the key milestones for the project? And what should we see over the next 12 months for progress? And we've seen the first gas date slip, as previously reported, to Q4 2021. How confident are you on achieving first gas on time? And then second, just an update on the receivable position with the NPDC and how you're going to approach to reduce this going forward? Is it a case of holding gas revenues continuously to bring this down? And how is the dialogue with NPDC?

Okay. I'll handle the receivables part of the question. On ANOH, what we are going to be seeing from Q4 this year, you start seeing equipment actually arriving from manufacturers. Two key manufacturing bases, GPS in Sharjah in UAE and Baker Hughes out of Italy. And those equipment manufacturing is on schedule, albeit we're just about 10% behind schedule. That schedule is being monitored on a weekly basis, just a little bit a few weeks impact of the COVID-19. So when we talk about Q4 next year, that's because we are monitoring that region. Now if you physically go to the sites today, the civil works are ongoing, all the [ drills ] and routes and the foundations that we receive the equipment [ as is such ] arriving in Q4. So if you were to come in here in Q4 and come in again in Q1 next year, what you are going to see will be physical installation of equipment. And by Q2 next year, you will see installation getting to an end and the beginning of pre-commissioning and commissioning, leading to first gas in Q4. That's the schedule. And by the way, part of the reason we are so confident is that funding has never been an issue on this project because we have -- from the beginning, we front-loaded the equity contribution. As you know, we had $300 million of equity on the table and another $120 million being expected. The debt element of it, that's already been negotiated and that should be in place by the end of Q3, the debt element. So we're very confident. Funding is not a problem. The schedule of civil works well on target and manufacturing well on target, albeit a couple of weeks delayed. So yes, that's what you will see, Q4, Q1 and Q2 next year will be installation of equipment heading to us pre-commissioning.

Yes, Alex, I'll pick up your question on the receivable position. Obviously, with NPDC, the dialogue with NPDC is very good. So it's a true partnership. We are reducing that accordingly. And it's not just holding back gas revenues, we are doing that a bit, but the reality is we've received about $177 million so far from them and the bulk of that has actually been in USD. So certainly, over $100 million of it is in USD. So the money, [ the reap ] goes from NPDC through to the CBN, and the CBN has been approving payments right through every -- both Q1 and Q2. So that's working well at the minute. It's something that we're managing daily, but the [ bit ] receivable position is steadily coming down. We are obviously holding back gas revenues, but returning them when we make the [ narrowing cash core ] payments.

The next question is from Dragan Trajkov of ARC.

Just a couple of quick questions. When should we expect the gas production to -- the gross gas production to go about 350 MMcf per day? Second question. Are you seeing any opportunities in the margin around -- that's big enough that could attract your attention? And also, can you give us a bit more information? I mean 76% Forcados Pipeline down. What's the cost for it? Sorry, sorry. 76% up, I meant, sorry.

Yes. [ It's 100 ].

Okay. All right. On the gas production, the first one is -- so currently, we've been roughly around 260 million, 270 million, about 210 million, 220 million not -- nonassociated gas -- reservoir gas and about 40 million standard cubic feet of gas from the [ AG ]. So the 2 gas wells we plan to drill. We're spudding the first one in a couple of weeks' time. We should be done in about 2 months, so that adds about 40 million standard cubic feet of gas per day. So that already takes us to about 300 million. And then the second well comes in 2 months after the first well. So the second well should be onstream some time in October, November. And that then takes us to about 3 -- 340-ish. So ambition for [ IPC ] gas-wise is to be around between 300 million and 350 million by end of the year. So I hope that addresses your first question. And last one on Forcados. I think it's a bit of a combination. So we had assumed 30% downtime in the market guidance production that we shared. If you look at the numbers, it's actually slightly less than that. It's roughly around 25%, 26% -- 24%, 25%. Well, it's not just around the Trans Forcados Pipeline outage that did lead to that slightly lower downtime, but also the Shell timing out has also experienced a number of [ countertop ] situation. It was around [ trial car shuttling ], which also got to do with the pandemic and also offtakers' normal issues and also some injectors that haven't paid their statutory regulatory fees. The DPR did not grant export license. So it's a combination of [ countertop ] at the terminal and also some maintenance work on the Trans Forcados Pipeline that has led to that 76% uptime overall for asset availability. But I think it's slightly better than what we actually experienced first half of last year. I'll hand over the marginal field round back to Austin. Thank you.

Yes. You know we have a subsidiary called Newton, Newton Energy. That is actually in partnership with Pillar Oil. So every time we present our production -- our modest production out of the Igbuku field, that's actually a marginal field operated by Pillar where we have a 40% equity interest. So we have put in that platform on the table to take a good look at the marginal field rounds. And if we see marginal fields after a valuation that have the volumes -- the kind of volumes that cross our threshold, yes, we will show interest through the -- through that subsidiary, and in fact, then essentially grow that subsidiary as a stand-alone operator, including management of non-operated marginal fields. So yes, there is an opportunity to grow our small fields production through this vehicle to a significant volume. And yes, so we'll keep a close eye on this and participate as we need to with a view to probably develop in a small, compact, but very efficient marginal field portfolio.

The next question is from Michael Alsford of Citi.

I've just got a couple, please. It's good to see that you reiterated the full year '20 production guidance, but I was wondering if you could give a little more color as to the mix, given the OPEC quota cuts, as to how much you think will be oil production in the second half will be my first question. Secondly, just on costs, getting good progress on cost reductions. I think Roger mentioned $7.6 a barrel from production cost perspective. I just wonder whether you can give some sort of medium-term view as to how you see that trending over the next 12 months, 18 months, that would be great.

Okay. Maybe I'll take the one on production?

Yes, the mix of production, right.

So on the production, if you look at our midyear numbers, I think we're roughly around 67/33, that's the mix so far. And if you look at for the second half of the year [ the change module ] end up around 70% liquid and 30% gas. That's likely where we will end up the second half of the year with the 2 gas wells coming onstream because we're also optimizing and driving up production on the liquids side. That depends on how the OPEC restraint, how that evolves. We do have good capacity from all the wells we drilled and the existing wells from the old stock. So if in line with the OPEC slot that was in the public domain that by, I think, September, October, they will relax the constraint, if that gets translated down to operations from NNPC, that means [ lodging of ] liquid as well in addition to [ lodging of ] gas. So that 70:30 percent ratio will be pretty much intact for the second half of the year. Mike, I hope that answers your question on the mix for the second half. I hand over the cost to Roger.

And just on the operating costs, $7.60, you're right. We -- and that's for this, obviously, first half. Q2, there was a enormous work steam going on, reducing that cost base across the whole [ setup ] portfolio, but also focused quite heavily on the Eland asset and the [ on press ] OML 40, which has a barging operation, Gbetiokun, which is sized for higher production, and then obviously, with COVID-19, we've had to cut back the developments down there. So we've actually been working quite carefully with our contractors, and we've already seen at least 30% reduction. In fact, in that barging operation, it's higher than that. And you're going to start to see that come through in Q3 and Q4 and into future years. So we're confident it's coming -- well, if you actually reflect what we've done today already, it's coming down. But we'll continue to drive it down. If you look at H1 '19 with $5.41, I think that is where we want to target towards. So certainly, in the $6, hopefully in the $5 per BOE.

That's great. And just if you don't mind, just a couple of quick follow-ups. Just on the comment on the dividend, the core dividend, could you remind me if that -- was that $0.05 a share on a annual basis or on a interim basis for the core dividend? And just secondly, on the sort of differential, the realizations relative to Brent, there's clearly a lot of disruption in 2Q. I'm just wondering what you're seeing now in terms of your ability to sort of capture closer to Brent realizations?

Yes. I mean just in terms of the dividends, to be clear here, we have a dividend policy, which is core dividend of $0.05 a share, which is by $29 million. And then a -- we always look to see if we can top up with a special dividend, targeting at least sort of $0.05 a share in that. So the core dividend is, of course, for the year and we look to do an interim on the final and then the top up will obviously be on an interim basis or on a final basis. So if we had the $0.10, which we have done quite a number of years in the past, then really looking at a sort of $59 million to $60 million dividend in total.

Yes. There was a second question, but that was it.

Mike, did I answer your question? I think there's one other.