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. Following the presentation, we will go to the phone lines for the question and answer session. If you wish to ask a question, please make sure you dial in on the conference call. 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 Ezugworie. We have a few other people obviously in the room here from the team. If I go on to slide four of the slide deck, this runs through some of the corporate highlights. The summary of the six months of 2022 is we are running a very strong safety record at 28.4 million man hours with no lost time incidents on our Seplat operated assets. We're really focused on ensuring that we are a safe operation.
In terms of looking at the production volumes, we are just short of 50,000 barrels of oil equivalent a day. Liquids contribute to almost 30 of that and gas is the balance. We've taken out Ubima when we sold the Ubima asset or interest in Ubima, we've taken it out of the numbers here. Revenues are up 71%, just over $500,000 , 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's been strong, and this is the strength of our business at $330 million. Net cash flow from operations at $284 million.
We had the Sibiri exploration well on OML 40 drilled and successful. Now we're working with our partner to get approval to go into extended well test and to start producing. Then the Amukpe-Escravos, we'll talk a bit more about it, but we are mechanically complete on that now. As we speak, we're doing a final dewatering of the line, and then we would expect to introduce volumes into the Chevron terminal, and we said that's going to be early 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 gonna be paid over a phased basis.
This is really what we're looking to do as a business is in addition to acquiring assets, is actually divesting assets that no longer really fit with our strategy. We have farmed into the Abiala marginal field. It's part of the marginal field basket. We've farmed into that. We've got 95% of the equity, and we're looking to develop that as an extension to Gbetiokun. 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-exec chairman. We then had three new non-exec directors joining the board in May. Then we looked at the leadership at Seplat. We brought in the Chief Operating Officer role, and Sam's joined us.
He joined us in July 1, so he's just new to the team. In terms of Mobil Producing Nigeria Unlimited 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. Obviously, the Tree for Life we launched, which is our carbon initiative, rewilding project. If I turn to the next slide. Looking at our operational performance chart. You can see there that, on the far right or second from the end, you can see Q2 2022.
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. Overall in the six months, it's just shy of 50,000. Our guidance. It's just the lower end of our guidance, and we're confident we will get back in through the guidance. I won't bother going through the reserve movements. You can look at your leisure on that slide. On to slide six. Looking at the oil business, we've obviously seen some increases in Q2. The average working interest is slightly up at 1.3%, at just shy of 30,000 barrels of oil equivalent a day.
The larger load of increases has been through our drilling activity in OML 40 as we hooked up some of the production there. That's up 4.3% overall, from Q1 due to also improvements in uptime. If you look at downtime, we're 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. You know, the Trans-Forcados system is old. It's always challenging, and we've seen some losses around that through the years.
In terms of the east of the eastern assets, again, we've had quite a 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, is just at 12.2%. Then our drilling activity, we have we said minimum of 10 wells. We have some contingent wells, which we are looking to try and put in before the end of Q4. In terms of the activity to date, we've completed the Amukpe-0 5 and Upper Amukpe 12 well, and we actually obviously concluded the Sibiri exploration well. We had three wells spudded in Q2.
That's Uwuh, an appraisal well in the east. We've got Upper Hamat 13 in OML 40 and Uwuh 52 in our western assets. The drilling is progressing according to plan, and we're actually getting some favorable results in drilling cost reductions. A little bit around the Sibiri exploration well. We drilled that to TD in February. We've got eight oil-bearing reservoirs there, and we have 229 ft of net pay. It's a discovery. There's oil there. Now we're doing some more analysis of it and then obviously working to look at the extended well test. We're gonna transfer that well later on this year.
In terms of the rigs, you know, we have looked at you know, rigs required to move to separate 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 two of the four, 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 Amukpe to Escravos, and let's talk a bit around that. This is obviously the underground pipeline, runs from our western assets at Amukpe into the Escravos terminal, and the deepest section is around 50 ft.
This has been a very difficult project to complete, largely because we don't own it, and we're relying on third parties. We're delighted to say that it's all engaged and in place. We've signed all those, you know, a month or so ago. There's a pig going through the line at the minute to take out 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. 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 asset volume. We no longer rely wholly on the Trans-Forcados system.
I think certainly in our projections, we're gonna see a lot less downtime and losses on that line. We are restricted. The line outage restriction is 50,000 a day into Escravos, the terminal with 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 other options being opened up. You can see then that we're doing a feed study on the Amukpe to Otumara manifold line. It's a very small 7 km pipeline. It would connect the Amukpe to Escravos into the TEP, which is the line that takes our OML 40 production. That gives us optionality.
We're only at feed at the minute, but it will give us optionality to connect the lines. There is potential for longer-term FSO solutions, but that's well into the future. Okay. Next slide, in terms of our gas business. Obviously, you know, our focus operationally is that we're seeing around 118 million scf 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. It set lower gas prices in that for industrial consumers. We've been in discussions with the off-takers and there's a lot of price pressure downwards. But delighted to say that our gas, our average gas prices have remained constant.
What we'll then do is revert to a willing buyer, willing seller market in 2023. We see it 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 two new customers for 66 million scf a day, and we're about to put a third customer on stream in Q4 with 20 million scf a day. Certainly there's demand for the gas. We're not too concerned around that, just for the price pressure at the minute. Our average selling price has softened a bit, but not too much. It's 276 MMscfd.
In terms of the flare-out reduction, it's a very big focus for us as a business to be flared out completely, beyond, you know, obviously the safety operational flares that you'll need. 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 Uquo flares in June. Let me just talk briefly on the ANOH gas plant. In terms of the area, the bit that we're 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 with the plant will be completed well in advance of our H1 2023 first gas date. There are two other elements to it, which is the spur line, and this is the 27 km spur line, which will link into the OB3 pipeline. The pipes for that have been milled in China. They're now being coated, and we're expecting them to be shipped to Nigeria during Q3. The other one is in terms of the OB3 pipeline. There's been a number of attempts 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 in.
There are alternatives that our partner can implement, and so we are still comfortable, and they're very comfortable that they will meet the timeline of that. 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 vaccinated, most of which have got double vaccines. We still do our checks, but largely we learn to live with this as most companies do.
In terms of safety, you know, over three years operation with LTI, I think it's something we're very proud of, and we really focus on to continue that into the future. We've been doing a lot of upgrades in terms of health and safety, and then looking clearly at things like crisis management and improvements. On the environmental side of things, really about measurement of our emissions. You know, largely a lot of our GHG emissions sit with the flaring. We'll actually have those taken down by the end of 2024. We work through the business, just setting additional GHG targets. Just to wrap up, just in the focus for H2 is really looking at sustainable development plan, including the biodiversity action plan.
Roll out of our TCFD framework roadmap, operationalize our accounting system for this GHG, as we start to report them in the year-end results, which will come out Q1 next year. Okay. 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 show a very strong revenue for this half year of about $537 million. This on the back of realized oil price of $107.25 per barrel. As Roger already said, about our sustained price on gas about $2.75 per Mscf. The EBITDA for this period adjusted are $347 million, and we have shown also a closing cash of $250 million. That leaves us with a net debt of $480 million.
During this period, our unit operating costs are about $8.1, and the CapEx spend for this period was about $70.7 million. I will talk about more the CapEx for rest of the year on the future slides. I'll take you to slide 12. Here's some more details on the financial results. Oil revenue up like I talked about earlier. Adjusted, if I adjust the revenue for the underlift of 463,000 barrels to our revenue, we adjusted to $569 million. Our tax charge for this period includes a deferred tax liability of $90 million and a current tax charge of $36 million.
The CapEx, which I'll later includes the 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 about $230 million. If you see the waterfall in terms of utilization of cash, ending with $150 million during this period. This is despite about $140 million, $128 million of that, you know, deposit for the ExxonMobil transaction, and that's $12 million for the Abiala transaction we are undertaking currently. The next slide 14, also shows our current liquidity position, which is very strong.
Our debt profile, our bonds, $250 million bond and our debt on the Eland asset, the RBL, and also the trade debt loan on the Eland asset. If you look at net debt to last 12 months EBITDA, it's about 0.078x . I'll take you to slide 15, which has our outlook for the rest of the year. The MPNU transaction remains a transformation for us, which is like going to triple our production and double our results. The production infrastructure for this asset is well secured and with minimal contingencies and also minimal losses from that asset.
When it's concluded, and as we talked about, once we get the approval, it will definitely transform the outlook for 2022 for our company. We have narrowed our production guidance to 50-54 thousand barrels of oil equivalent per day for 2022. In this regard, we're looking at a liquid of 30-33 thousand barrels per day and gas of 116-122 MMscfd per day. Roger spoke about the ANOH completion on ANOH gas plants. We are focused on the ANOH completion for the rest of the year. Other major developments talked about Sibiri, the initial well tests at Sibiri, we are going to undertake on Sibiri. We'd expect that to undertake that this second half of the year.
We're ahead of our 3.5 million barrels for the rest of the year for the next two quarters. On CapEx guidance remains $160 million. We spent about $7.7 million this first half, and we tend to spend the rest of the CapEx for the rest of the year. This will be in the areas of 40% reduction in gas flaring. We are installing some compressors in one of our locations to achieve this. We are going to drill a minimum of 10 wells this 2022. We drilled about six already in this first half.
We are also going to invest in terms of security currently looking at alternative evacuation for the eastern asset, where we're suffering some losses currently. We'll continue to spend money on the Sapele gas plant that we're currently working on. This concludes the presentation. With that, turn over to Roger to manage the Q&A. Thank you.
Okay. Back to the operator, for Q&A.
Thank you. If you wish to ask a question, please press star followed by one on your telephone keypad. If you change your mind and wish to remove your question, please press star followed by two. When preparing to ask your question, please ensure that your phone is unmuted locally. To confirm, that's star followed by one to ask a question. Your first telephone question today is from Alex Smith from Investec. Please go ahead.
Thanks for the call this morning. Just a couple of questions from me, please. First on Escravos. We have first oil lifting, hopefully immediately. 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 the Escravos? And maybe a better question is, when do you expect to reach that cap? Secondly, drilling activity is 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 indication in the environment? Lastly, on the marginal Abiala field, it's a $12 million signature bonus. And what is the development cost to get to first oil next year, please?
Thank you.
Thanks, Alex. Just on the Escravos. We have the pipeline's 160,000. Chevron have given us 50,000 ullage at the Escravos terminal. That's not just us alone. We're working on somewhere between 35,000-40,000 volumes on it. 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 full, that full capacity quickly. We don't see a sort of general ramp up because of the size of the pipeline. We actually had put oil into previously.
I think we will just run on the conservative side, you know, probably around 35,000 as a conservative assessment on our planning. In terms of the 2023 drilling, 2022 drilling and then what we're gonna do next year, like we have got a lot of wells we can drill. We've got a lot of activity this year. They're pretty good flow rates, particularly in the swamp. We see in OML 40, we've got a swamp well coming in OML 41 West. I think we can see that continuing into next year as well. In terms of the rigs themselves, we had contracted a lot of the rigs anyway previously, so we're not seeing any price inflation yet, going through that.
That's something we're monitoring. Obviously we have these Cardinal rigs, which is what we're looking at getting them up and running next year. We can actually utilize them for some of our rig program. In terms of then just around drilling costs, we are obviously driving down a lot of savings with the team and looking at you know, fit for purpose equipment going into the wells, et cetera. That looks like it's yielding fruit. We'll start to report that obviously towards the end of the year. In terms of Abiala development, what we're really looking at is that was part of the marginal field program. It was carved out.
We had from almost 45% interest that we're buying in at a 12%, a signature bonus, you know, economically makes a lot of sense. The Abiala was already a discovery. We're looking at that development, not this year, but possibly next year, depending where we get on the budget in 2023 budget. It's really an extension of Gbetiokun . When you have all the infrastructure in place with Gbetiokun , it's a very short pipeline from Abiala down into it. 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 Gbetiokun .
Great. Thank you. Next question is from the line of Josefina Rodriguez from MSIM. Please go ahead.
Hi. Thanks for the presentation. Just a reminder for myself. If I understand correctly, your exports, you have to bring them back to Nigeria for tax purposes. First, to recheck if that's correct, then to recheck your cash policy. Are you having any issues to repatriate the cash out of Nigeria? When you take the money in, do you have to translate it into local currency or you keep it in dollars? Any color on that would be helpful on my side. Thanks.
Thank you. Emeka.
Yeah. Thank you. As an oil and gas company, we don't have any restriction in terms of a transfer account of Nigeria. The regulation is that on export, you fill an NXP Form, and the proceeds come into the country, then you can utilize it the way you wish. On our own part, once the funds come into the country, we transfer them out because we have debt obligations, and I have dedicated accounts for that. So we don't have any issue transferring funds out of Nigeria. As a policy, we try to keep our 70% of our funds in U.S. dollars and also as outside of the country. Currently, we're well ahead of that. Almost all our funds are outside the country, except those that only go into the JV accounts for expenditures.
Yeah. Just to add to that, at the minute, all our Naira which we get from our gas business, we're deploying it in our business. Actually we're now, you know, short Naira, and therefore we are looking obviously, you know, we're gonna have to eventually go out and buy Naira in the market, which I think is the right side we wanna be.
Got it. Thanks. Thanks a lot.
As a reminder, if you'd like to ask any questions, please press star followed by one on your touch tone telephone. 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 this business is 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.