Seplat Energy Plc (SEPL) Earnings Call Transcript & Summary

Ladies and gentlemen, welcome to the Seplat Energy Half Year 2022 Presentation. My name is Stuart and I will be the operator for your call this morning. [Operator Instructions] I will now hand you over to Roger Brown, CEO. Please go ahead.

Good morning, everyone and welcome to Seplat Energy's H1 2022 results call. I'm in the room in London, I'm joined by Emeka Onwuka, our CFO and our new COO, Sam Zagury. And then we have a few other people also in the room here from the team. So if I go on to Slide 4 of the slide deck, this run through some of the corporate highlights. So the summary of the 6 months of 2022 is, we are running a very strong safety record at 28.4 million man-hours, with no lost time incident on our Seplat Energy operated assets, so we're really focused on ensuring that we are a safe operation. And in terms of looking at the production volumes, we are just short of 50,000 barrels of oil equivalent a day and liquids contribute to almost 30 of that and gas is the balance. And we have taken out Ubima when we sold Ubima as our interest in Ubima, we've taken out of the numbers here. Revenues are up 71% just over $0.5 billion and that's largely due to higher oil prices. EBITDA also up at 92% to $343 million and that's been adjusted for the cash -- non-cash items. Cash generation has been strong and is the strength of our business at $330 million, net cash flow from operations of $284 million. We had the Sibiri exploration well in OML 40 drilled successful and now we're working with our partner to get approval to go into extended well test and the sub-producing. And then the [indiscernible], we'll talk a bit more about it, but we are mechanically complete on that now and as we speak, we're doing a final dewatering of the line and then we would expect to interject, introduce volumes into the Chevron terminal and we said that's going to be early in the next week at the latest. In terms of then some of the strategic decisions, we divested in Ubima for a total sum of $55 million and that's going to be paid over a phased basis. And this is really what we're looking to do as a business is in addition to acquiring assets, it's actually divesting assets the longer we fit with our strategy. We have farmed into the Abiala Marginal Field as part of the marginal field basket and we've farmed into that, we got 95% of the equity and we're looking to develop that as an extension to [indiscernible]. And in terms of the Board, we've had quite a few changes in the Board during the half, Basil Omiyi was appointed our independent Non-Executive Chairman. We then had 3 new non-exec directors joining the Board in May. And then we looked at the leadership at Seplat. We brought in the Chief Operating Officer role and Sam has joined us. He joined us in 1 July, so he is just new to the team. In terms of Mobil Producing Nigeria acquisition, obviously, we reported that there's been some challenge with the government of Nigeria, but we still remain firm that we're following the laws in Nigeria and we're confident we will get to a favorable solution there. And then obviously, the Tree for Life we launched, which is our carbon initiative rewinding project. So I turn to the next slide, looking at our operational performance chart, so you can see there that on the far right or the second to the end, you can see Q2 2022. So we had a recovery in Q2 where we actually had an average of 52,385 barrels of oil equivalent a day as against sort of 48,000 in Q1. And overall in the 6 months, it's just the shy of 50 size in our guidance, it's just the lower end of our guidance and we're confident we will get back in through guidance. I won't follow going through the reserve movement, you can look at your leisure on that slide. On to Slide 6, looking the oil business and we've obviously seen some increases in Q2. So the average working interest is slightly up at 1.3%, just shy of 30,000 barrels of oil equivalent a day. The large lot of increases has been through our drilling activity in OML 40 as we hooked up some of the production there and that's up 4.3% overall bump from Q1 due to also improvements in uptime. If you look at downtime at 23%, Trans Forcados at 16%. It's been an issue for us that we've been working hard on is actually how we deal with our downtime unscheduled and third-party downtime, terminal loading restrictions, et cetera. So the Trans Forcados system is old and it's always challenging and we've seen some losses around that through the years. And in terms of the east -- Eastern assets, again we've had quite hard time in downtime in the East, but we are producing oil locally into the Waltersmith Refinery and we've had very little downtime on that. Overall, the group reconciliation losses, this is beyond downtime, it's just at 12.2%. And then our drilling activity, we have -- we say a minimum of 10 wells, we have some contingent wells, which we're looking to try and put in before the end of Q4. But in terms of activity to date, we've completed Amukpe-05 and Opuama-12 well and we actually obviously concluded the Sibiri exploration well. We have 3 wells spudded in Q2, that's Owu-02 is an appraisal well in the East. We got Opuama-12 Opahama 13 in OML 40 and Oben-52 in our Western assets and the drilling is progressing according to plan and we're actually looking -- we're getting some favorable results in drilling cost reductions. So a little bit around Sibiri exploration well. We drilled that to the TD in February. We've got 8 oil-bearing reservoirs there and we have 229 feet of net pay. So it's a discovery. There's oil there. Now we're doing is doing some more analysis of it and then obviously working to look at the extended well test, so we're going to run flow that well later on this year. And then in terms of the rigs, rigs -- we have looked at rigs acquired to move to Seplat well locations. We've worked on the Cardinal rigs, we're working with some inspection vendors. We're looking at some certification work and we're looking to, I think, certainly 2 of the 4, we should be able to get that into production pretty soon and we expect all the rigs commissioned by the end of 2023. Next slide, if we look then at the Escravos, let's talk a bit around that. So this is the -- I'll say the underground pipeline runs from our western asset to Amukpe into the terminal and production is around 50 feet. This has been a very difficult project to complete largely because we don't own it and we're relying on third parties. But we're delighted to say that it's all been in place, we've signed all those a month or so ago. There's a [indiscernible] going through the line at the minute to take up the final water and then hoping we'll be able to flow oil hopefully today. But certainly, we've said that we'll have constant oil flows next week. And what does that mean for us? What it means is that we then have a very good alternative and actually will be our primary routing for the Western assets volume, so in the longer relying only on the transfer cater system, I think certainly in our projections, we're going to see a lot less downtime and losses on that line. We are restricted, the line restriction is [ 50,000 ] a day into Escravos, the terminal Chevron, but we're looking to utilize and I think with the benefits of a new pipeline and less downtime, we should see some material improvement to our export. In that slide, it talks about all our options being opened up. You can see then we are doing a FEED study on AEP to Otumara manifold line, it's a very small 7k pipeline, we connect the Escravos into TEP, which is the line that takes our OML 40 production. And that gives us optionality, we're only feed at the minute, but will give us optionality to connect the lines. There is potential for longer-term FPSO solutions, but that's well into the future. Okay, next slide, in terms of our gas business, obviously -- our focus operationally is that we were seeing around 118 million scfs a day in terms of the gas production. We have actually been impacted by price negotiations when the PIA, the Petroleum Industry Act documentation came into place at set lower gas prices in that for industrial consumers. We've been in discussions with the offtakers and there's a lot of price pressure dimers, but delighted to say that our gas -- our obvious gas prices have remained constant. What we'll then do is, we revert to a willing barrel seller market in 2023. So we see this as a short-term phenomenon and then we should see obviously our gas production come back up. However, we've been busy and we have executed some short-term gas sales agreements. We've got 2 new customers for 66 million scfs a day and we're about to bring customer on stream in Q4 with 20 million scfs a day. So certainly, the demand for the gas we're not too concerned around that, just for the price pressure at the minute, but our average selling price has softened a bit, but not too much, it's $2.76 mscf. In terms of then flare reduction a very big focus for us as a business is to be flared out completely, beyond, obviously, the safety, operational flow you'll need. And we're targeting to be flared out by the end of 2024. There's a series of activities over the coming years to deliver that and we've seen some reduction in Oben and Amukpe in flares in June. Let me just talk briefly on the ANOH gas plant. In terms of the bit that we are in control of, we're making very good progress on the plant itself. Now all equipment fabricated with over 90% delivered to the project site. Overall, our stage of completion is 87%. So we are comfortable that the plant will be completed well in advance of our H1 2023 first gas date. Then there are 2 other elements to it, which is the Spur line and this is a 27k Spur line, which will link into the OB3 pipeline. The pipes that have been milled in China, they're now being coated and we're expecting them to be shipped in Nigeria during Q3. And then the other one is in terms of the OB3 pipeline. There's been a number of [ tents ] on the river crossing. There's a small section of that crossing, which has had some issues, largely because of the size of the pipeline, 48-inch. They're all alternatives that our partner can implement. And so we are still comfortable and they are very comfortable that they will meet the time line of that. So we maintain our H1 2023 estimate for first gas. Just on the final slide before I hand it back to Emeka. On the ESG side, in terms of COVID-19, I think we've largely got that under control from a business perspective. We have a very extensive and effective testing regime. And over 75% of our employees are actually vaccined, most of which have got double vaccines. So we still do our checks, but largely we learn to live with this as most companies do. In terms of safety, over 3 years operation with LTI, I think it's something we're very proud of and we're really focused on to continue that into the future and we've been doing a lot of upgrades in terms of health and safety and then looking clearly at things like crisis management and improvement. And then in the environmental side of things, really about measurement of our emissions and large -- a lot of our GHG emissions sit with the flaring and then -- so we'll actually have those taken down by the end of '24. And then we work through the business just setting additional ESG target. And then just to wrap up, just in focus for H2 is really looking at sustainable development plan included in the biodiversity action plan, rollout of our HSE framework road map, operationalize our accounting system for the GHG as we start to report them in the year-end results, which will come out Q1 next year. Okay. So let me hand it over to Emeka, who will run through the financial review.

Good morning all and thank you for joining us on this call, I'll start on Slide 11. We showed a very strong revenue for this half year of about $527 million, is on the back of realized oil price of $107.35 per barrel, we already said about a sustained price on gas about $2.75 per million scf. The EBITDA particular adjusted $342.7 million and we have shown also including cash turnout $350 million, then with a net debt of $418 million. During this period, our unit operating costs are about $8.1 and the CapEx spend for this period about $70.7 million, I'll talk about more the capital for rest of the year on the future slide. I'll take you to Slide 12, give some more details on the financial results, oil revenues up like I talked about earlier -- adjusted, if I adjust the revenue for [indiscernible] 403,000 barrels revenue adjusted to $569 million. Our tax charge for this period includes a tax liability of $90 million and a current tax charge of $36 million. The CapEx which I alluded to includes drilling, engineering and gas project for this period. The next slide is on our cash generation. This period we had very strong cash generation of $330 million. If you see the waterfall in terms of utilization of cash ending with $350 million during this below. This is despite about $140 million -- about $140 million. I want to hint on that deposit for the Exxon transaction and that will be $11 for the Abiala transaction we are undertaking currently. The next slide, Slide 14 also shows our current liquidity position, which is very strong, our debt profile, our bonds $350 million bond and our debt on the Eland asset, the RBL had also deterred that loan on the Eland asset. If we look at net debt to last 12 months EBITDA, it's about 0.78x. I'll take you to Slide 15, which is our outlook for the rest of the year. The MPNU transaction remain a transformational transaction for us, which is going to triple our production and double our results and also the production infrastructure for this asset is well secured with minimal curtailments and also minimal losses from that asset, one is concluded and as we talk about once we get the approval, it will definitely transform the outlook for 2022 for our company. We narrowed our production guidance to 50,000 to 54,000 barrels of oil equivalent per day for 2022. In this regard, we're looking at liquid 30,000 to 33,000 barrels per day and gas of 116 million to 122 million scfs per day. Roger spoke about the ANOH completion gas plant. We are focused on the completion for the rest of the year. Other major developments at Sibiri, the turnover, the appraisal we are going to undertake at Sibiri, we expect that to undertake that during the second half of the year. We're ahead of our 3.5 million barrel for the rest of the year for the next 2 quarters. On CapEx, CapEx guarantee $160 million. We spent about $7.7 million in first half and we tend to spend the rest for 2022 -- for the rest of the year. This -- in the areas of 40% reduction in gas flaring were installation of compressors, were -- one of our locations to achieve this. We are going to drill minimum of 10 wells in 2022. We drilled about 6 already for this first half. We are also going to invest in terms of security, [indiscernible] for the Eastern asset where we are softening some losses currently. We will continue to spend money on the Sapele gas plant that we're currently working on. We are now -- this concludes the presentation. With that, turning back to Roger to moderate the Q&A. Thank you.

Okay. So back to the operator for Q&A.

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

Just a couple of questions from me, please. Firstly, on Escravos, we had first oil lifting, hopefully, imminently. Do we expect this to incrementally grow quite quickly? And what should we expect as a percentage in 2023? And can you confirm, was it 45,000 or 50,000 barrels cap on Escravos? I know you better question is that when do you expect to reach that cap? Secondly, drilling activity accelerating, are you able to kind of continue this thematic into 2023, given current oil prices? And can you comment on cost of rigs and what sort of levels you're seeing here? Is there any inflation in the environment? Lastly, on the marginal Abiala field, it's a $12 million figure of bonus and what is the development cost to get to first oil next year, please?

Okay. Thanks, Alex. So just on the Escravos, so just we have -- the pipelines are 160,000 and Chevron have given us 50,000 outage of the Escravos terminal and that's not just us alone. And so we're working on somewhere between 35,000 to 40,000 volumes on it. So we won't be able to get all of the volumes in the West through it, but certainly a large portion of it. We should get up to pretty much up to sort of fill that full capacity quickly. We don't see a sort of general ramp-up because of the size of the pipeline. And we actually had pre -- oil into previously. So I think we will just run on a conservative say probably around 35,000 as a conservative assessment on our planning. And in terms of the 2023 drilling -- 2022 drilling and then what we're going to do next year, yes, I think we have got a lot of wells we can drill. We've got a lot of activity this year and they are pretty good [ flora ] particularly in the swap, we see over [ 40 ] swamp well coming in OML 4, 38,41 in the West. And I think we can see that continuing into next year as well. In terms of the rigs themselves, we have contracted a lot of the rigs anyway previously. So we're not seeing any price inflation yet going through that something we're monitoring. And obviously, we have these cardinal rigs is what we're looking at getting them up and running next year. So we can actually utilize them for some of our rig program. In terms of then just drilling costs, so we are obviously driving down a lot of savings with the team and looking at a fit-for-purpose equipment going to the wells, et cetera. So that looks like it's yielding fruit. We'll start to report that, obviously, towards the end of the year. And then in terms of Abiala development, what we're really looking at is that is of the -- that was part of the marginal field program, it's card. So we had if I remember 45% interest, buying in at 12% signature bonus economically makes a lot of sense. And the Abiala was already a discovery. So we're looking at that development not this year, but possibly next year depending where we get on the budget in 2023 budget. And it's really an extension of that deal. And so when you have all the infrastructure in place with -- it's a very short pipeline from Abiala dine into it. So it's a bit early, Alex, to give you all the sort of economics around it, but it should be around the same type of economics that we see at [indiscernible].

Next question is from the line of [ Josephine Rodriguez ] from MSIM.

Just a reminder for myself. If I understand correctly, your exports, you have to bring them back to Nigeria for tax purposes. First, we check if that's correct, then to reach your cash policy. So are you having any issues to repeating the cash out of Nigeria? When you take the money and do you have to translate into local currency or you keep it in dollars? Any color on that would be helpful on my side.

Thank you, Emeka.

Yes, thank you. As an oil and gas company, we don't have any restriction in terms of the tax [indiscernible] out of Nigeria. The regulation is our net report to fill our NSG form and the proceeds coming to the country, then you can utilize it the way you wish on our own path, ones coming to the country will translate them up because we have debt obligations and have dedicated account for that. So we don't have any issue force out of Nigeria. As a policy, we have to give about 70% of -- [ 52% ] of our funds in U.S. dollars and also us outside of the country. And currently, we are well ahead of that, almost all efforts after the contracts that are going to the JV accounts for repetition.

Just to add to that, at the minute, all the narrow which we get from our gas business, we're deploying it in our business. So actually, we are now short narrow and therefore, we are looking obviously -- we're going to have to eventually go out and buy narrow in the market, which I think is the right side we want to be.

[Operator Instructions] 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.

Just say, thanks very much for coming on the call this morning and it's business as usual for us and we look forward to Q3 results in October. Thank you very much and have a good day.

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