Seplat Energy Plc

Thank you and good morning everyone and delighted to be coming out with our first half of 2023 results. So we just lay out on the first slide some of the metrics and you can see there that we are uplifting our quarterly dividend. This is our core dividend, so it's now up 20% to 3 cents a share. Our total production for the half was a 9.2 million barrels of oil equivalent which is slightly up on the present period. Revenue at 547, which again is slightly up. And net debt, which is slightly up again at 380 million, but at good levels. Look on the right side of that slide, just the highlights. You can see there in terms of operating uptime improving year on year, we're finding now that we're getting reduced losses and benefits from additional export routes. And certainly our COO will cover that in his slides. Progress on the new B3 pipeline with our partner. And this is quite a critical catalyst for the Anogas project. Revenue, you can see there in terms of 6.1 million barrels of oil lifted. Modestly improved production offset by lower realized oil prices. And then gas price is relatively stable through the period. And the volumes are slightly up. It shows that we are a cash-generative business, particularly at these commodity levels. MPNU, we'll talk about that in a sec, but really we announced that we extended that sale and purchase agreement in May, and we're now obviously engaging with the new administration with a view to getting that closed out this year. And the last one to say here on this slide is just in terms of a bit of a board update, In line with our good governance and flagging and notifying early of board changes, our current CFO will step down for retirement next year and the board has approved Eleanor, who's the current VP Finance, who will then be now appointed the CFO designate, and then we'll take over from Emeka when Emeka steps down next year. Okay, just want to talk, quickly about the new government. We see also in the 29th of May President Tanubu come into power and we've seen a lot of activity in the first two months. I think you'll see there, folks in the right hand side of the slide there, you can see from the 29th of May to the week of the 5th of June A number of actions were taken. The fuel subsidies were removed, and that had been talked about for quite a number of years, but no one had actually done it. That was quite a material step. There was four executive orders signed, and we highlight those on the left-hand side of the slide, and the special advisers were appointed, which we see as a real direction of this president, of this administration, is to really put in experts into the various ministries. On the 19th of June, there were appointments of service chiefs and dissolution of all the boards in preparation for what we're seeing now is the ministerial lists are coming out. They're not appointed yet, but they will be appointed in the coming weeks. And we certainly see some of those ministerial lists appear, I think, off yesterday. And we'll see that, we'll track that over the coming weeks. You can see there's a number of orders. The Electricity Act was quite critical in terms of sort of more of a deregulating of that market. The FX market was liberalised. You'll have seen that also being investors and where the narrow is at the minute. So a lot of activity. and aligns to where we're going as a business in terms of our transition. So let me hand over to Sam who will then go through the operating review.

Thank you very much Roger and good morning everyone. Our operational performance for the first half of the year has also been very solid, being the second highest in the last decade if you look at the numbers and the charts on the left hand side of this slide. This is underpinned by our excavators to Amokwe pipeline that continues to deliver value to the business. Since inception had delivered, we pushed through about 3.2 million barrels of crude through that line. And just to give you some context, the value loss, if we didn't have that line, is about 1.6 million barrels. So really delivering value to the business. Also, we've witnessed some reduced losses in the Western asset in particular, and then also improved gas performance in terms of operational efficiencies. If I just go down on asset by asset basis, the OMLs 4, 38, and 41 that we call the Western asset continue to produce, but we have not been able to already declined because of some wells that had not come on stream, and I'll talk to you subsequently about that. Our OML 53 evacuation continues via the Watersmith Refinery and our TNP, the evacuation line also hasn't come back since, and that actually negatively impacted our performance in the period. But overall, if you look at OML 40, production is up by 24%. And this is also supported by timely delivery of our wells and higher production up times. So in essence, when you pull all this together, you will see very strong production performance in the first half of this year. So if I go to the next slide, just to give you a bit of flavor on the drilling performance. Year to date, we've completed five wells, four of those on the OML 40, The rigs, we have two rigs currently in OML 438 and 41 in two of the locations. And then we have one rig on OML 53. So the wealth in terms of revised plan, you can see where we are headed to. But one of the most significant thing that you will see just to address the shortfall in OML 438 and 41 is that in this quarter that we've just entered, we are mobilizing three additional rigs to the asset to ensure that we recover fully by the end of the year. So if I just go straight into the midstream performance for surplus on urban, our vision continues to be for us to fully maximize the installed capacity in urban while our current performance in this period is our current performance in this period continues to be very strong. We've delivered 120 million cups of gas per day average in the first half of this year. And average gas price continues to be also very strong, $2.87 per thousand cups of gas. So overall, in the opposite asset, in urban, we continue to show very strong delivery. Arno, Roger has spoken too, but I just give you a bit more flavor So far we've completed, achieved 93% mechanical completion of the plant installation and the grouting process has also witnessed a very strong progress in the first half of this year with the engineers that build the London Underground on site in Nigeria, helping us to complete the grouting of the island section that we already put behind us. The spore line as well is making some good progress between the OB3 and spore line we now have quarter three 2023 as completion dates for those two major lines. And in terms of being ready for operations as well, one additional well has been delivered by SPDC while they are on location for the second well. The last that I would like to talk to is the Saple gas plant. If I just take you on early wind, commissioned the associated gas compressors that we have installed in the plant, which is what we used to call the accelerated AG solution. So we are now on cruise control to ensure that we deliver the overall supply of gas by next year. The project is about 75% complete. and this will bring in another 85 million scopes of gas into the local domestic market. And additionally, this will also improve and bring in an LPG product into the market. So overall, I would like to end by just highlighting that the strong operational performance that CEPLA has recorded in the first half of this year is also underpinned by very strong safety records. And on this point, I will hand over to Emeka who will take you through the financials.

Thank you very much, Sam and Roger. Good morning all. We have presented a very strong financial outcome for this half year for surplus. The revenue is up on the back of higher production despite lower oil prices for this period. You can see at $11.79 target $107 last year. We sustained gas prices and improved, achieved about $2.87 on gas prices. However, unit OPEX went up on account of AAPP utilization. AAPP costs about $2 higher than the TFP cost in terms of CO2. And also EBITDA went down on account of lower oil prices. Our closing cash of $380 million, yes, is down, but it is affected by the devaluation in terms of the NARA balance of about $14 million. The devaluation effect and also a higher dividend paid out for this half year, I guess, 2022. And then the 380 is still strong, though it went up. Our leverage is still very good. I'll speak to that on the following slide. It's up to 1.2 times in terms of net debt to EBITDA. On the next slide, you see the details of the financial, particularly on the P&L side. We have, as we go to the revenues, we go to the cost also in terms of higher CHF on the AAPP line. AGI will not be flat, except for unexpected legal costs to defend the company against the assumption of that action, which was quite intense this half year. The exchange rate I've spoken to, about $40 million. This is on Naira balances. I have a slide on exchange rates. I will speak to that when I get to that. In terms of other financial assets and Naira diabetes, we are fairly matched. So where we saw the impact of the valuation in terms of the cash we are holding at the end of month of July. The tax expense, you can see just about $2.8 million. We have a single-car tax credit component of acres that has moved their tax move from a 6% tax bracket to its 5% tax bracket. And that helped us to stabilize the profit after tax during this period. I thought about cash generation, quite strong, $404 million, and also there is about $269 million from operations, digitalization of the cash, capital, capex, dividend payments, and also during this period on the aircraft side, the credit paid by the Arabian, about $11 million during this period. I will close that, $181 million cash. The Naira currency in the country is experiencing fluctuations due to the violation of the market, unification of rates, and also the limitation of a single window for FF transactions, the I&E window. As such, the rates have gone up about 466. It's moving every day, but I think we ended up at about mid-700s for the end of June. In terms of its impact on our business, for gas revenues, it's flat because the gas price is in dollars, but it's paid based on our new windows. So we expect that we'll continue to receive increased Naira for our gas sales. J&A is going to go down for Naira expenditure. In terms of its conversion, it will be lower. So we're going to have a positive impact on DNA going forward on account of the exchange rate devaluation that we've seen. Cash balance is going to be negative, and of course, in terms of trade disturbance and other financial assets, however, this is like, it goes to positive. We will continue to optimize our contracts, align local currency, later transaction to be settled in Naira. And that is the way we can manage foreign currency risk out of our balance sheet. I don't know what I, You are aware that in terms of production, liquid and gas, on average about 60% liquid and 40% gas, and also in terms of revenue, on average about 80-20% in terms of foreign currency and Naira. We'll use Naira to settle Naira obligations, so it's still going to have to become Naira balances to expose up to devaluation going forward. On the capital structure, we have $1,650,000,000 bought out in the market and payback of $11,000,000 on the RBL side. Our leverage is still strong at 1.2 times in terms of net debt to EBITDA. Basically, we'll say that we'll continue to manage the finances of surplus and continue to mitigate the risk, we'll see the economy in Nigeria get more active, because we've had a passive economy in the past eight years, but we believe that we'll continue to show strong performance. I'll hand over to Roger.

Thank you. Okay, so let me go to the final two slides. The first slide is really setting out the priorities for the second half of this year. Obviously, we're in that now. So it really is to... With the wells delivery, it's a focus to get us back on track of delivering those remaining wells. And again, that drilling will then actually address the natural decline we have and then focus on the export route system to make sure we continue to get revenue performance improvements. It really will be focused on the annual gas plant. for the final part of this year and get it into First Gas. And then obviously a real focus on NPNU, the acquisition with this new administration. Just on the sustainability side of the business, or not side of the business, but overall, we're obviously looking at the new energy pillar and looking at a number of opportunities. We are obviously going to work through those in due diligence with a view to getting to FID. through the board. Flaring out our gas, obviously that's quite a big part of our CO2 emissions and all of those projects are on track and focusing on that. And we have some solar power up being deployed in our communities as part also as our focus on delivering access to energy to our schools and hospitals in the areas that we operate. In terms of CAPEX guidance, We give you a range there, 160 to 190, and in the half year, we're on track in that range, and that's why we've put it here. We expect the second half capex to be similar to the first half. So on the final slide, we just lay out our three by three in terms of our metrics. So obviously, the first one there is delivering guidance. We left the guidance at 45 to 55. slightly to the positive on the middle there, and we expect that to continue. In terms of the capital investment, I've just talked about that, and the drilling, again, we've talked about that. Really, it's the get from five wells in the first half to 16 wells overall. In the middle three areas, we want to look at gas monetisation, first gas, look at NPNU, which we've talked about there, and also the new energy, some of these opportunities, and really those opportunities about maturing the best ones for our overall strategy. And then the final three, there's on fiscal strength. So you can see that we are a cash generative business, 259 million of cash, and we expect that obviously to continue through the year. Net debt, again, that is to really reduce that, bring it down. it's reduced on 318 million and our low net debt to EBITDA ratios to continue those. And then the final one for obviously for shareholders is, you know, we've got a core dividend increase by 20%. That doesn't of the talk through the special dividends, which we still retain. And we would make obviously the decision that when we know the year end results. So the 12 cents is a core committed and we're paying 3 cents this quarter. Okay, so let me just, hand it back to the operator for questions. 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 yourself from the question queue, please press star followed by two. When preparing to ask a question, please ensure that your phone is unmuted locally to confirm that star followed by one to ask a question. The first question comes from the line of Alexander Syvek with GSAM. Please go ahead.

Hi, gentlemen. Thank you very much for the presentation. I have a few questions. I'll go one by one, if you don't mind. So, for KASOS Terminal, there were headlines that it was out for two weeks in July and the recent attempt by Shell to bring it back online was unsuccessful. I'm just wondering if you had any engagement with them on the terminal and what was their outlook to bring it back online? And if you mind sharing how much oil did you ship via that terminal in the first half, please?

Okay, just one question.

Okay. Yeah, that's the kind of first and second one, probably.

Okay, thank you.

Sam? All right. Thank you very much for that question. Yes, indeed, you are absolutely correct. The Focados terminal went out due to some absorption around one of the loading platforms. We are in constant engagement with SPDC. and they are working towards the delivery and recovery of that line. We will also confirm that we engage with them almost on a daily basis. They have lined out activities that they need to carry to repair and restore evacuation via the terminal. The only negative impact they are having at the moment is the weather condition that is affecting the divers that go underwater to fix the leak. And they've given us a timeline to restoring the terminal into operation. The second part of your question is how much volume we exported via the terminal in the first half of the year. We exported a total of roughly about 2 million barrels of crude through the terminal in the first half of this year.

Thank you. Thank you so much. My second question is on gas business. Just looking at the segment breakdown, it seems gas business is loss making in the first half. Can you elaborate on the reason behind it and if we expect it to come back to being profitable going forward.

Yeah. Okay. Let me just hand that across the microphone. You talked about the... Peter maybe didn't hear it. Okay. So he's just saying in the first half the gas business looked like loss making as part of the, when we do separate reporting of it. So that's the first question around that.

And the second question is just how does it look like going forward in terms of... Yeah, well, the gas business, as you say, remain profitable. I'm trying to see exactly the Let's come back to it.

I think when we strip out quarterly our segmental reporting, sometimes you get anomalies in it. I think just fundamentally underlying the gas business, it is a profitable business. A lot of the expenditure obviously has been committed in the urban plant. With these gas prices sitting at an average around uh 285 thereabouts to 290 um an mscuf it's it is a profitable business so sometimes you can get anomalies into it but we'll certainly look into and revert back before the end of the day thank you thank you and uh and my last one on on gna uh so um just you know uh for for modeling purposes so i i do understand that

there's been a one-off this quarter with litigation and since last year there is also some some element of additional costs related to MPNU transaction. But if we are thinking about long-term trend some normal quarterly level probably for that line is around 20 million ballpark. I'm just wondering with FX rate movement we've seen and assuming one-offs are gone, what should be the kind of normal level we'll be looking at going forward?

Yeah, maybe I'll answer that quickly. I mean, just, yeah, I mean, we saw, yeah, last year we did have NPNU costs going through there, the bulk of those, and the GNA this year, you rightly identified, is obviously litigation, which we, you know, we We did not foresee any of that. And that's probably put the quarter up by about 20 million in total, or 15 to 20 million. So we'd strip that out. And I think you'll start to see that is probably, and then annualize that. That's kind of the levels we would expect. We've driven through a lot of G&A changes on the back of the last year. Our G&A levels were, you know, in our view, too high and therefore we brought a lot of cost saving through there in terms of cost control around travel, training and everything else, other cost line items. So you just need to take a look at that $15 million to $20 million anomaly out for the first half and then that should give you a sort of run rate going forward.

Understood. Thank you so much.

Yeah, Roger can come back to the gas question.

Oh, sorry. I think we're going to answer an eye on the specific segment on the gas.

Yes, it's just the devaluation on the impact. That's what we have because gas is priced in dollars but received in naira. So also the receivable as well. will have to be repriced based on the current rate. That's what led to that.

Just adding to that, obviously with the timing of the one-to-one exchange rate, there was a massive move from the CBN rate to where the IEA window is. That then meant in the half year you had a translation of the balance sheet effectively And because of the timing of that, you have a one-off hit through the accounts. When you get to the end of the year, you'll see probably more of an averaging of that happening because you'll be doing it over the year in question. So that's just exemplified and just magnified that. But as I said before, the underlying gas business is profitable.

Understood. Thank you. Thank you so much.

Once again, to register for a question, please press star and one on your telephone. The next question comes from the line of Nicola Stefanou with REDD. Please go ahead.

Gentlemen, hi, it's Nic Stefanou from REDD. Can you hear me? Yeah, we can hear you. OK, brilliant, brilliant. Good to chat again. It's been a while. So I've got three questions to ask. I'm going to ask two and then a follow-up. The first is on the dividend policy. Roger, I remember maybe a couple of years ago, you had this policy that the dividend would move in line with gas revenues. And obviously, you know, last year you kind of like that, the core dividend. And now you make mentions that, you know, I mean, there might be kind of like, you know, a more regular like special dividend as well. So I'm just trying to understand, you know, if there's kind of like a deviation from what I thought was maybe, you know, a past sort of like policy that, you know, when ANO is kind of like up and running, you know, that's when you're going to start giving big dividends. Or is that still kind of, is that still like, you know, a part of the plan? That's the first question. And then the second question is on the CAPEX. I'm a bit confused about what happened there because initially you're going to drill 18 wells, and now it looks like it's going to be 16 wells for the year, and yet CAPEX is, you know, I mean, the range is up by $30 million. So what happened there? Because, you know, especially after the evaluation of the Nile, I would expect it to actually be even lower, not higher. So, you know, if you can comment on that as well, please. And I'm going to ask the follow-up later.

Okay, let me just go to Emeka for that first question. Yeah, thank you, Nick. Nice to talk to you again. When we went to the market, our dividend policies that we communicated is a core dividend of $0.05 and a top-up, depending on the performance, of another $0.05. And that has been what we've done over the years. This year, last year, we then moved to the quarterly dividend. and move that dividend to 2.5 and so that meant really at the time we communicated our core dividend were going up to 10 last year and then this year we are taking up to 12 what we did in the first quarter in terms of dividend policy communication we will do that later on in the year where we will reveal a capital allocation framework we're thinking about that and you will see a more definitive and precise communication on its relation to cateneration at the time.

I'll deal with the CapEx one. Just to add to that, Nick, in terms of what we've been trying to do for a long time is tie part of that dividend to the gas business. You're absolutely right in terms of Anno. I mean, obviously Anno is not up and running yet. It's not hit first gas yet, but we would expect Anno to be a very big, long-term, stable contributed to that dividend, and we'll certainly be looking in that direction. As Micah said, we're coming out with capital allocation later, and it really will be sort of showing the sources for that dividend going forward. So therefore, in the short term, we kept our core and special as our dividend policy, but obviously upping the core. And then I would expect that to change probably next year once we come out with a new pulse. In terms of your question on the capex, what we define is, we talk about 16 wells, that means we talk about spudded, completed, hooked up and producing in the year. And so what you'll find is if there's delays, you'll be spending a lot of money spudding wells and everything else, but they won't be hooked up and producing in that year. And that's what we'll see. We'll see in the back end of this year a lot of activity, but because we won't be able to complete it, you'll still be concurring the capex. The capex number will be in there, but actually the production won't happen probably until next year. We won't count it in that 16. So the 16 is going to be more than 16 is the answer, but for our accounting purposes, we only say what's actually producing.

Okay, but the increase in the CapEx range, is that just, you know, some elements of the drilling operations were a bit more expensive than initially anticipated? Is that, you know, just normal cost inflation? Just want to kind of like get an idea.

Yeah, specifically in the range, because obviously there's a range in that drilling activity. Okay, so it depends what we can get in, in what timeframe. We thought it was better rather than go with a fixed number. We'd actually put a range on it. just to give you a bit more guidance around that. But as I said earlier, we would expect it to be in around the levels of H1, but actually you may well find that it's a bit more, which is 160 to 190. Okay, fair.

And my follow-up is pretty much on the Naira. I think, you know, now that it's kind of like being floated and... And, you know, the first, I would say, maybe humans might be a bit turbulent in terms of, you know, where the Naira is. There's going to be quite a bit of those FX adjustments, FX movements, kind of like in your cash flow statement there that will impact the cash balance. And I want to understand, as a sort of like rule of thumb, how much cash you want to keep as Naira and how much in, you know, other currencies? just to be able to get an idea of how much that impact would be quarter over quarter and depending on where the Naira is.

Okay, I'll speak to that. As a policy, we try to keep to 5% of our balances in foreign currency and the 5% in Naira in a stable period. But also, As a matter of contracting and invoicing, you will notice that because of the big differential between the fisher rates at the time or the multiple exchange rates, most of the contracts will be done in dollars so as to protect the cost of those contracts. Otherwise, the contractors cannot perform. So you find that going forward, because of the adjustment rates, we'll be able to pay out more. We'll be able to pay out more in the era. But it's also important for us, we are looking at our policy to adjust our NARA holding going forward, at least at this turbulent period until it stabilizes. That's something that we are doing. But then, you also know, currency, and we continue to make a lot of payments in NARA. So we may be holding balances from time to time, but we will, we're trying to see if we can drop it from there to inside percent. Whatever that is practicable, whatever is possible, you know, that we can achieve to keep the balance level. We'll do that going forward. But also, you talked about the turbulence. We believe that the turbulence has settled after a while. This is a point of the market, yes.

Sorry, you said, what's the percentage you want to keep in Naira as a kind of like a staple sort of?

We currently keep 25%. 25%. We are going to adjust that going forward while we are looking at our current requirements and see how much lower we can get that to.

OK, OK, so thanks so much.

The next question comes from the line of meeting Ivanov with Jeffries. Please go ahead.

Good morning gentlemen. Can you hear me?

Yep, we can hear you.

Yeah, thank you very much for the update and presentation. I have a few questions. Maybe the first one on this NPNU transaction, right? So I guess like my kind of question is kind of provided that the transaction is greenlighted, let's say tomorrow, how do you plan to approach the funding of the transaction? Because I remember we discussed you had some commitment from banks before. So like, I'm curious to understand in terms of the funding and the deal valuation, how did it change in the past several months? So are you ready to fund the transaction if like the relevant regulator highlights after getting like the transaction? That's my first question. The second question would be on situation with this evacuation of oil through Forcado's terminal. If I understand correctly, you mentioned that the evacuation of oil is currently suspended, but what is the current timeline? I think you mentioned that there is a timeline to fix this issue, and how is it possible to use IEP pipeline at the moment to evacuate oil from OML 4.38 and 4.41. So how should we look at the alternative routes at the moment? And my last question would be on your kind of capital structure strategy. So you kind of mentioned in the press release that you're looking at different opportunities to to kind of to optimize capital structure, including potential buybacks of the bond. So would it be possible just to provide more color on your view on the capital structure? Do you want just to reduce the absolute amount of debt? Which instruments of the capital structure you would like to target and et cetera? So it would be kind of helpful for us. Thank you.

Okay, thanks for those questions. Okay, so I'll just kick off the first one. So in terms of NPNU, we have obviously we've signed and extended the sale and purchase agreement. There's still a court process underway between, not us, but between NNPC and NPNU or Exxon. That will continue and everything else around that. So look, what we've done is what we're in control of, so obviously we have those funders for the transaction or existing providers of capital to it, so naturally we've kept them warm around that, so we don't foresee any issues in hitting the execute button and that once we get the go-ahead from the president or from the administration. In terms of the evaluation, and again we monitor that regularly, Our view has not changed. It is a very accretive transaction around that in terms of value. Sam?

Okay, thanks, Ivanov, on your second question on the Focados terminal. In terms of timeline, the absolute timeline that we have discussed with SPDC to restore the FOG terminal is one to two weeks in terms of actual number. but we put a caveat on that because of the weather conditions. It has to be a safe operation and we have divers going underwater to go and fix it. So from time to time you get negative weather impact and the divers are not able to go down. So that is why we put some margin on it. But overall, in terms of assessing the actual work to be done is in a matter of one week, two weeks maximum. Now, the second question is, are we using AEP to evacuate crude out of the OMS 438 and 41? And the answer is yes. And that is also in my report out, I shared that since commissioning of the AEP, at the times when focados had been down completely, that our production could have been zero, we have seen evacuation of up to 1.6 million barrels of crude from July last year to date. So this is one of those moments. We are currently evacuating our production out of OMS 438 and 41 via the AEP while Focados is down because evacuation through the AEP goes to the Esclavos terminal. Thank you.

Okay, I'll take a bit here about the utilization of excess cash or capital. Our major focus currently is on the APNU transaction. So we're keeping cash for that transaction. We're going to look at all options. And like I said, later in the year, we will guide the market on the capital allocation framework. We'll give more color to the options at the time. We're going to look at all options for excess cash.

Understood. So basically, thank you very much. So you understood correctly that the funding in terms of the bank's commitment to provide funding is still there. So you don't have just to go and kind of attract the new financing. So you have standing commitments from banks to fund this transaction if it's green lighted tomorrow.

Yes, before we sign the SPA, we are fully funded and committed to the market. And we're keeping all the banks, we're not aware of any bank that is at the club currently. However, we'll continue to keep money depending on the speed at which we want to complete the transaction. We could use our own liquidity to complete and then rebalance with the bank. So the bank commitments are there.

Understood. Yeah, thank you very much. Appreciate it.

The next question comes from the line of Nikhil Path with JP Morgan. Please go ahead.

Good morning. I just have a couple of questions left, probably quick ones. I'll ask all of them. Going forward, what do you see as your run rate capex that you think the business needs in order to maintain your current production levels? That would be my first question. The second question you mentioned about the MP&U transaction and the court cases. Are you aware of any hearing date that has been set for the court case about the MP&U transaction? And the last one is more of a modeling question in terms of by when should we expect your tax expenses to sort of return to more normal levels? That's it for me.

Okay, I'll get Emeka to answer one and three together, and then I'll do the MP&U. I didn't get the very last one. The tax, when do we expect the tax to kick in, obviously, in terms of the deferred tax? When do we see that running out? Oh, okay.

Okay, we expect on the CAPEX level, we expect the CAPEX level to normalize to a normal annual CAPEX of about $160 million, but that will spend every year. The second question on the audit effect that way. We currently know that because the aircrafts on that side have come into profitability, we'll start amortizing that shortly. I know we have these balances, but it will take us over five years to get them out.

So, yeah, it's a lot of affairs. Okay. Just in terms of the NPNU transaction, so Just on this benefit, there are two things. One is that there's a court ruling, which is a preserved status quo court ruling between, it was an ex-party ruling between the government and Exxon. That's really just a preservation court ruling. The real focus is an arbitration between, under the joint operating agreement between the two partners. And we understand that's likely to be heard next year in terms of that overall process. In terms of the timeline, how long that will take, we know we're not privy to that. But, you know, arbitrations, I think there's a point of principle here in terms of is there preemption under the joint operating agreement or not? And certainly Exxon's position is aligned with our position that because this is an acquisition of Mobile Producing Nigerian Unlimited, which is a share transaction. We're acquiring it from two Exxon subsidiaries based out of Delaware, because that is a shared transaction where you're actually buying not just the interest in the JOA, but you're actually acquiring people, you're acquiring liabilities, buildings, a fully fledged and operating business. In that aspect, we don't see that triggering preemption rights under the JOA and that's certainly Exxon's view of it. But anyway, that'd be subject to an arbitration likely to be heard next year.

Follow up on that one. If the arbitration will only begin next year in terms of the hearing, does your extension of the SPA cover that timeline? And is there any guidance you could possibly give us I think the extension mentioned that you're sharing some of the economic benefit with Exxon. Is there any guidance you can provide us in sort of what proportion that might be?

Yeah, OK. So in terms of, we expect this to get resolved before that arbitration is where our sort of operating position is at the minute, but certainly SBA does allow it to go beyond in terms of how that gets determined. So we're comfortable in that aspect. In terms of the actual sharing arrangement, and again, that's subject to nondisclosure with the seller. So we can't say that much, but we can guide in terms of the level of that. All we can say is that it's an interactive transaction. even with that sharing basis. And the reason being is that, obviously, there was an early 2021 effective date. Obviously, what you need to do is, to the extent that it extends and it has done to where we are today, there needs to be sharing arrangements, obviously. But that sharing arrangement is something we're very comfortable with. It's not giving up in a material part of that production. which has obviously been enjoyed by MP and new shareholders today. So I can't give you any more direction than that, obviously, because it's subject to non-disclosure.

Understood. Thanks a lot.

If you would like to ask a question, please press star and one on your telephone. There are no more audio questions. I hand back the conference to Roger Brown for typed questions. Thank you. Excuse me. I can see we have a last minute audio question from the line of Ayodehi Dawodu with Bank Trust and Co. Please go ahead.

Hi, good morning. Thanks very much for the call. I'm just a quick question on the gas side. I just want to just I guess an idea has there been any pushback? I guess from the government in terms of pricing gas at the higher official rate. My second question is, has there been any discussion in terms of actually increasing the dollar price of gases as well? Last question, I guess just for clarification in terms of the financing for the acquisition. Has that been locked in? I mean, was it locked in back, I think, 2021 in terms of the pricing, or is that something that would reflect more of today's elevated interest rate environments? Those are my questions, please. Thank you.

Okay, thanks for that. Let me just deal with that. So in terms of the gas pricing, obviously when we had the PIA come in initially, there were different pricings for industrial consumers. We saw a softening of the gas price. but the whole intention of the PIA is really to move on to a willing buyer, willing seller model, and we're seeing that. So what we will see is market forces, which will drive the gas price going forward, and you'll see that our gas prices are being quite consistent around that, and we don't know how the market's going to go into the future, but we do expect more demand on the gas side and therefore we hope for higher gas prices. In terms of the way the mechanism works is it's the underlying contracts in the gas are dollar denominated, but they're actually physically paid in NARA. And so what you have is we had a, obviously the reference rate was CBN rate. We're now moving on to obviously the higher exchange rate And so the future flow back will be of the higher narrow coming back in and sort of neutralizes. And so therefore you do effectively get dollar on the gas, dollar prices on the gas, but it's physically paid and narrow. And in terms then, you asked the question of the acquisition financing. Banks, we would expect the banks to maintain that pricing. And obviously there are market forces that impact pricing, but certainly on the dollar side for the acquisition, we don't see that really changing. You never know with banks until the final day, but we've looked at it and we expect that pricing to maintain.

Thanks.

This concludes our question and answer session. I would like to turn the conference back over to Roger Brown for any typed questions.

OK. So I believe I'm reading this out, but I'm going to read it out for you, Sam, to your benefit. So the question comes in regarding our oil production. Is the drilling schedule designed to replace natural decline only? do you see an opportunity for growth in oil production, particularly looking into 2024 and 2025, and which license blocks hold the most promise in this regard?

No, thank you. Indeed, the drilling program as we see them today, we essentially drill to arrest the decline on one hand, And then depending on the capital program as well, we probably can accelerate a few wells for growth. And in terms of split, the OMLs 438 and 41, the western axis, are actually where we hold the most value going into the future, 2024, 2025. Because if you also look at the split of our overall equity and production today, we do oil and gas put together in the neighborhood of 75-80% of those come from those three OMLs. So that is where we concentrate our efforts because that is where also the future lies in response to your question. Thank you.

Okay, thanks for that. I believe that brings an end to this webcast. I just want to thank everyone for attending. The questions are very good. particularly when you only got these results at 7am this morning. So clearly there's a lot of quick readers and some good quality questions. So look forward to speaking to you again