Seplat Energy PLC

LSE:SEPL

Earnings Call Analysis

Company Maintains Stable Performance

The company's gas revenues remain flat due to dollar-based pricing, and they anticipate increased local currency receipts due to exchange rate fluctuations, positively impacting general & administrative expenses going forward. The capital structure remains solid with leverage at 1.2x net debt to EBITDA. For the second half of the year, the focus will be on well delivery to address natural decline and improve export routes, specifically targeting the Anogas plant for gas and the MPNU acquisition. The company has maintained its capital expenditure guidance between $160 to $190 million and aims to normalize annual CapEx to $160 million. They expect to resolve MPNU transaction concerns before arbitration next year and are comfortable with the economic sharing with Exxon. They foresee market forces driving gas prices and expect demand to increase. On the financing side, acquisition pricing has been stable despite market conditions. The current drilling schedule is designed to manage natural declines and may also target growth, with licenses 38 and 41 being most promising for the future.

Moderate Revenue Increase and Higher Net Debt

The company has reported a moderate revenue increase, reaching $547 million, which marks a slight uptick from previous figures. However, investors should note that there has been a rise in net debt, now standing at $380 million. The management has described this level of debt as 'good', indicating that despite the increase, it remains within a manageable range for the company's finances.

Operational Highlights and Mixed Production Performance

The company has highlighted reduced losses and benefits accruing from additional export routes. In terms of production, there is a modest improvement to report, with a mention of 6.1 million barrels of oil lifted. This has been largely offset by lower realized oil prices, with gas prices remaining relatively stable. The overall production volumes saw a minor increase.

Steady Financial Leverage and Strong Cash Flow

One key metric that stands out is the net debt-to-EBITDA ratio, which is reported to be 1.2x. This ratio is a common measure of financial leverage and suggests that the company isn't overly burdened by debt relative to its earnings before interest, taxes, depreciation, and amortization. Additionally, the company generated strong cash flows, specifically highlighting cash from operations at approximately $44 million as of July, pointing to a healthy operational efficiency.

Second Half of the Year Expectations and Capital Expenditure

Looking forward, the company has set out its priorities for the second half of the year. This includes a focus on delivery of wells and boosting revenue performance. The company is committed to energy sustainability efforts and expects to continue its operational momentum. Specifically, they have provided a capital expenditure (CapEx) guidance range for the second half at $160 million to $190 million, which is in line with expenditures from the first half of the year.

Maintaining Fiscal Strength and Rewarding Shareholders

In terms of maintaining fiscal discipline, the company aims to continue displaying strong net debt-to-EBITDA ratios and has reported a reduction of debt by $38 million. Notably, shareholders can expect an increase in dividends by 20%, which reflects the company's confidence in its cash-generating capabilities and commitment to delivering shareholder value. The declared dividend is $0.12 per share, with a quarterly payment of $0.03 for this period.

Earnings Call Transcript 2023-Q2

[Operator]

Ladies and gentlemen, welcome to the Seplat Energy 2023 Half Year Results Presentation. My name is [ Jotin ], and I will be the operator for your call this morning. [Operator Instructions] I will now hand you over to Roger Brown, CEO.

[Roger Brown, executive]

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 a continuing -- this is our core dividend. So it's [ not ] up 20% to $0.03 a share. Our total production for the half was 9.2 million barrels of oil equivalent, which is slightly up on the equivalent period.

Revenue of [ $547 ] million, which again is slightly up, and net debt which is up again at $380 million, but at good levels. And looking 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 that we're getting reduced losses and benefits from additional export routes -- and certainly, our COO will cover that in his slides.

[ Progeste3 ] pipeline with our partner, and this is quite a critical catalyst for the [ Anigas ] project. Revenue, you can see there in terms of 6.1 million barrels of oil lifted and 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 these commodity levels, MPNU, we'll talk about it in a second. But really, we announced that we extended that sale and purchase agreement in May, and [ Bruno ] engaging with the new administration with a view to getting that closed out this year.

And the last 1 to stay here is on this slide is just in terms of a bit of a board update in line with our good governance and flagging and fine early, upward changes, our current CFO will step down for retirement next year. And the Board has approved Elanor, who is the current VP Finance who will then be now appointed to [ see site ], and then we'll take over from [Indiscernable] next year.

Okay. Just want to talk quickly about the new government. We see obviously in the 29th of May, present [ Tonga ] come into power. And we've seen a lot of activity in the first 2 months I think you'll see there focus on 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 we're taking the petrol subsidies where the fuel subsidy were removed, and that's been talked about for quite a number of years, but no 1 has actually done it. That's quite a material step -- there is 4 executive orders signed and we highlight on the left-hand side of the slide and the special advisers were appointed, which we see is a real direction of this President 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 Minister [ of lists ] are coming out. They're not appointed yet, but there will be appointed in the coming weeks. And we're starting to see some movement [ to a list here, I think ], obviously yesterday, and we'll see that more attractive over the coming weeks.

You can see there's a number of orders. There's -- just the act was is quite critical in terms of sort of more of a deregulating of that market. The FX market was liberalized and you'll have seen that on [ invested ] and where the narrower at the minute. So lot of activity and aligns to where we are going in the business in terms of our transition. So let me hand over to Sam, who will then go through the operating review.

[Samson Ezugworie, executive]

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 of this slide. This is underpinned by our Escravos to [ Amobe ] pipeline that continues to deliver value to the business. Since -- the [ exception ] has delivered will push 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 noticed witnessed some reduced losses in the Western asset, in particular, and then also improved gas performance in terms of operational efficiencies. If I don't go down on [ other asset ] basis, the for 38 and 41 that we call the Western assets continue to produce, but we have not been able to already decline because of some wells that had not come on stream, and I'll talk to you subsequently about that.

Our OML 53 evacuation continues value to the Watermarefinery. And our TNP,[ 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 firewalls and higher production of times.

So in that sense, 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 have completed 5 wells, 4 of those on the OML 40. The rig -- we have 2 rigs currently in OML 4, 38 and 41, in 2 of the locations -- and then we have 1 rig on OML 53.

So the world -- in terms of our revised plan, you can see where we are headed to. But 1 of the most significant things that you will see just to address the shortfall in OML 4, 38 and 41, is that in the coming -- in this quarter that we just entered, we are mobilizing 3 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 Seplat. -- on open, our vision continues to be for us to fully market manage the installed capacity in broadband. While we -- our current performance in this period is -- our core performance in this period continues to be very strong. We've delivered 120 million [ scores ] 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 scores of cash. So overall, in the operated assets, and we continue to show very strong delivery -- and Roger has spoken too, but I don't give you a bit more flavor.

So far, we've completed achieved 93% mechanical completion of the plant installation and the grounding process has also witnessed a very strong progress in the first half of this year with the engineers that build in London underground on site in Nigeria, helping us to complete the [ routing ] of the [ airline section ] that we already put behind us. This [ power line ] as well is making some good progress between the OB3 and [ sport ] line. We now have [ Potat2023 ] as completion date for those 2 major lines.

And in terms of being ready for operations as well, 1 additional well has been delivered by SPDC while they are on on location for the second well. The last that I would like to talk to is the Seplat gas plant -- if I just take you on [ Eivind ], we have 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 by -- next year. The project is about 75% complete, and this will bring in another $85 million cost of gas into the local domestic market. And additionally, this will also improve and bringing an LPG product into the market.

So overall, I would like to end by just highlighting that the strong operational performance that Seplat recorded in the first half of this year is also underpinned by very strong safety record. And on this point, I will hand over to Emeka who will take you through the financials.

[Emeka Onwuka, executive]

Thank you very much, Tom. And Roger, good morning all. We have presented a very strong financial outcome for this half year for Seplat. [ Darien is up ]. Back of higher production despite the lower oil prices for this [ pot ]. You can see our [ lipid last ] target, 1 was several last year.

We sustained gas prices improved achieved about $2.87 on gas prices. However, unit so tax went up on account of utilization AAP. APP cost about $2 higher than the CFCs in terms of [ CH ]. Also, EBITDA went down on account of on account of lower oil prices, closing cash of $280 million, the U.S. is down, but is affected by the devaluation in terms of the note balance of about $14 million.

The deduction effect and also a higher dividend paid out for this half year, I guess 2022. Our net debt is still strong [Indiscernable] [ Valerie ] very good. I'll speak to that on this following slide.

I would say 1.22x in terms of net debt-to-EBITDA. On the next slide, you'll see the details of the financial, particularly on the P&L side, we have -- we have [ spotty ] revenues, [ rectory cost of cars ] of higher CHF on the ATP line. [ At the slide ] except for unexpected legal cost to defend the company against the assumption that actually, which was quite intense this half year. The [ stent I've spoken ] to about $40 million. This is on to balance sheet. I have a slide on the exchange rates. I will speak to that when I gave to that.

In terms of what our financial assets. Narrow other financial assets and Nevada. We are very much. So where we start the impact also in terms of the cash we are holding at the month of July. The tax expense just about $2.8 million. We have [ Scatarino ] acres that has moved the tax go from [ reenact at ] market.

And I have as to stabilize the profit after tax during this period. [ Matolabarcar generation ] were quite strong, we about [ $44 ] million and and also about $259 million from operation, digitalization of the cash CapEx dividend payment -- and also during this period on the [ aircraft side ], it's translated the RBL and $11 million during this period. And we'll close that $81 million cash.

The currency in the country [Indiscernable] fluctuations due to the valuation of the market [ unification ] of rates and then also the implementation of a single window for FS transaction of the window. And as far as we have gone up about for the 6 to is moving every day, but I think we met [ hundreds ] for the end of June.

In terms of our impact on our business for gas revenues, it's flat. -- because the gas price is in dollars, but is based on our new windows. So we expect that we'll continue to receive increased [ nao ] for our gas sales. [ Googong for a expenditure ] in terms of its conversion, it will be lower. So we would have a positive impact on G&A going forward on account of the exchange rate evaluation that we've seen.

Cash balance goes negative. And of course, in terms of trials and [Indiscernable] other financial assets. However, ladies like go to positive. We will continue to optimize our contracts to align look at currency retail transaction to be set with in [ Mara ]. And that's the way we can manage the foreign currency risk out of our balance sheet. I don't know what 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 the average about 80-20 in terms of foreign currency and [ Ana ] will use [ era ] to settle other obligations to a have come at balances to pull out the devaluation going forward.

On that capital structure, a as big to this, we have [ 281,000,650,000,000 ] out in the market and paid back of $11 million on the RBL side, our -- our leverage is still strong at 1.2x composites in terms of net debt to EBITDA. -- [ bear would ] say that we continue to manage the finances of Seplat continue to mitigate the risk, we see the economy in Nigeria gets more active because we will hand the passion in the past it or we believe that will continue to show our performance. I'll hand over to Roger.

[Roger Brown, executive]

Thank you. Okay. So let me go to the final 2 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. -- in those remaining wells.

And again, that will -- that drilling will then actually address the natural decline we have and then focus on the export routes is to make sure we continue to get revenue performance improvements. It really will be focused on the Anogasplant the final part of this year and get it into [ First ] Gas. And then obviously, a real focus on MPNU 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 due diligence with a view to [Indiscernable] getting to through the Board. Flaring out our gas, obviously, that's quite a big part of our CO2 emissions. And all of those lose projects are on track and focusing on that.

And we have some solar power being deployed in our communities and as part of also as our focus on delivering access to energy, to our skills and the hospitals in the areas that we operate. In terms of CapEx guidance, we'll give you a range there, $160 million to $190 million in the half year, we're on track in that range, and that's why we have put it here. We expect the second half CapEx similar to the first half.

So on the final slide, we just lay out our 3x3 in terms of our metrics. And so obviously, the first 1 is delivering guidance. We've left the guidance of $45 -- $55 million right slightly to the positive on middle there. 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. And really, it's to get from 5 wells in the first half to 16 wells overall. In the middle, 3 areas. We want to look at gas monetization, [ frustgas ]. -- look at MPNU, which we've talked about there and also the new energy, some of these opportunities and really there's opportunities the best ones for our overall strategy.

And then the final 3 there is 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 $38 million and our low net debt-to-EBITDA ratios to continue those.

And then the final 1 for shareholders we've got a core dividend increase by 20%. That doesn't fly talk through the special dividends, which we still retain. And we would make obviously a decision that at the moment of the year in results. So the $0.12 is a core committed, and we're paying $0.03 this quarter. Okay. So let me just hand it back to the operator for questions. Thank you.

[Operator]

[Operator Instructions] The first question comes from the line of Alexander Siwek with GSAM.

[Unknown Analyst]

Gentlemen, I have a few questions. I'll go one by one, if you don't mind. So [ for Cardos ] terminal, there were headlines that it was out for 2 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's their outlook to bring it back online? And if you mind sharing how much oI'll did you ship via the terminal in the first half, please.

[Samson Chibogwu Ezugworie, executive]

Thank you. Sam -- all right. Thank you very much for that question. Yes, indeed, you are absolutely correct. The Forcados terminal, we out due to some of action around 1 of the loading platforms. We are in constant engagement with SPDC and they are working towards the delivery and a recovery of that line. We will also confirm that -- we engaged with them almost on a daily basis. They have lined out activities that they need to carry to repair and restore or have a [ question ] via the terminal.

The only negative impact they are having at the moment is the weather condition that is affecting the diverse that go underwater to fix the leak. And they've given us a time line 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 to tell roughly about 2 million barrels of crude through the terminal in the first half of this year.

[Unknown Analyst]

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?

[Roger Brown, executive]

Yes. Okay. Let me just hand that across the [Indiscernable] you talked about the Peter moves in here.

Okay. So you're just saying in the first half, the gas business, it looked like loss making as part of the -- when we do a separate reporting of it. And the second question is just how do look like going forward in terms of .

[Emeka Onwuka, executive]

Yes. What the gas business, as I say, in an urban [ profits a ] book. I'm trying to see exactly the segment let's part come back to .

[Roger Brown, executive]

I think like I say this generally, I think when we strip out quarterly segmental reporting, sometimes you get anomalies in it. I think just fundamentally underlying the gas business, it is a profitable business for us. A lot of the expenditure obviously has been committed in a [ upon ] plant -- and with these gas prices sitting at an average around 285 thereabout to 290. And [ Ensco ], 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 year. .

[Unknown Analyst]

Okay. And my last 1 on G&A. So just for modeling purposes, so I do understand that -- there has been a one-off this quarter with litigation. And since last year, there is also some element of additional costs related to MPNU transaction. But if we are thinking about long-term trends, some normal quarterly level probably for that line is around 20 million ballpark. I'm just wondering with 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?

[Roger Brown, executive]

Yes. Maybe I'll answer that quickly. I mean, just -- yes, I mean we saw -- last year, we did have MPNU costs going through there the [ bogus ]. And the G&A this year, you're rightly identified as there's obviously litigation, which we did not foresee any of that. And that's probably put the quarter up by about $20 million in total, $15 million to $20 million.

So we strip that out -- and I think you'll start to see that as 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 last year, our G&A levels were, in our view, too high. And therefore, we brought a lot of cost savings through there in terms of cost control around travel, training and everything else, other cost line items.

So you just need to take 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.

[Samson Chibogwu Ezugworie, executive]

I go back to a question. Yes, it's just a devaluation impact. that's what we have because as price in dollars were received in [ naira ]. So also the level as well, we have to be repriced based on the current and that's what led to that here.

[Roger Brown, executive]

And just obviously adding to that. Obviously, the timing of the one-to-one exchange rate, there was a massive move the CBN rate to where the IA window is. And that is our iA [Indiscernable] or whatever. The that then meant in the half year, you had a translation of the balance sheet effectively because the timing of that, you have a one-off hit through through the case -- when you get to in the year, you'll see probably more of an averaging of that in case you'll be doing over the year in question. .

So therefore -- so that's just exemplified and just magnified that. But as I said before, the underlying gas business is profitable.

[Operator]

[Operator Instructions] The next question comes from the line of Nikolas Stefanou with Red.

[Nikolas Stefanou, analyst]

Gentlemen, -- it's Nick Stefan from Redknee. Can you hear me?

[Roger Brown, executive]

Yes, we can hear you.

[Nikolas Stefanou, analyst]

Okay,[ liberate ]. Good to chat again. It's been a while. So I've got 3 questions to ask on last then a follow-up. The first is on the [ Devon ] policy. I was trying to remember, it was maybe a couple of years ago, you had this the [ police ] dividend in line with cash revenues. And obviously, last year, you kind of liked up the core dividend. And now you make mention that, I mean, it might be -- there might be kind of like more [ equal ] special dividend as well. So I'm just trying to understand if this is kind of like a deviation from what I thought was maybe past sort of like -- policy that when 1 is kind of like up and running, that's when you're going to start giving big dividends? Or is that still kind of -- is that still like 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 you initially want to drill 8 wells -- and now it looks like it's going to be 16 wells for the year, and yet CapEx is -- the range is up by $30 million. So what happened there? Because especially after a valuation of the in, I would expect it to actually be even lower not higher. So if you can comment on that as well, please. And I'm going to ask a follow-up later.

[Roger Brown, executive]

Okay. Let me just go back to the first question.

[Emeka Onwuka, executive]

Yes. fact, Nick, let talk to you again. When we went to the market, the -- our dividend policies that we communicated is a core dividend of $0.05 and the top up depending on the performance of [ Anda ]. And that has been what we've done over the years, that this year -- last year, we then move to quarterly dividend and move our dividend to $ 2.5.

So that meant related we [ committed a coding up ] to 10% last year. And then this year, we are taking up to 12 or we did it in the first quarter. In terms of dividend policy communication, we will do that later in the year, where we reveal a capital [ recession ] framework. We are thinking about that, and you will see a more definitive and precise communication in relation to cash generation at the time.

[Roger Brown, executive]

I'll deal with the CapEx one. Just to add to that, Nick, in terms of the -- what we've been trying to do for a long time is type part the dividend to the gas business. You're absolutely right. In terms of [ Anno ], in [ Asians ] not up and running yet, not hit first gas yet, but we would expect [ Ana ] to be a very big long-term stable contributor to that. Dividend, and we'll certainly be looking in that direction. As Mike 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 -- so therefore, in the short term, we kept our core and special as our dividend policy, but obviously up in the core. And then I would expect that to change probably next year once we've come out with a new policy.

In terms of your question on the CapEx, what we define as -- we talk about 16 wells, that means we talk about spudded. -- completed hooked up and producing in the year, okay? And so what you 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. So -- and that's what we'll see. We'll see in the back end of the this year, a lot of activity -- but because we won't be able to complete it, you'll still be incurring the CapEx. The CapEx number will be in there.

But actually, the production won't happen probably until next year, we won't point it in that 16. So the 16 is going to be more than the 16 as the -- but we just for our printing purposes when you say what's actually producing.

[Nikolas Stefanou, analyst]

Okay. But the increase in the CapEx range, is that just some elements of the drink operations who have been more expensive than initially anticipated? Is that just normal cost inflation? Just want to kind of like an idea of June.

[Roger Brown, executive]

Specific in the range because, obviously, there's a range in that drilling activity, okay? So it depends what we can get in in what time frame. We thought it better and go with a fixed number. We 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 million to $190 million.

[Nikolas Stefanou, analyst]

Okay, fair. And my follow-up is pretty much on [ deli ]. I think now that it's kind of like being floated. And -- and the first say maybe a few [ mass ] might be turbulent in terms of where the [ Lara ] is -- there's going to be quite a bit of a low effect adjustments if its movement is kind of like in your customer [ tenant ] will impact the cash balance. And I want to understand, as is sort of like rule of farm, how much cost you want to keep us [ Lian ] how much other currencies, just to be able to get an idea of how much that impact would be quarter-over-quarter and depending on what the is? .

[Emeka Onwuka, executive]

I'll speak to that. As a policy, we try to keep a 5% of our balances in foreign currency, [ 1 ]5% in [ Marais ] period. But also as a matter of contracting and invoicing, you will notice that because of the big differential between the official and added time [ thematically change ] rate. Most of the contracts were done in dollars. So to protect the cost of those bond. Otherwise, the contractors cannot perform. So you find that going forward, because adjustments, we'll be able to pay us more we go [ to pay for 1 ] area. But it's also important for us, we are looking at that policy to adjust our[ Naraholding ] going forward, at least this double peristabilizes. That's something that we have been -- but then you also know that [ force and ] will continue to make a lot of payments in [ era ]. So we will maybe holding balance sheet from time to time, but we will -- we're trying to see if we can drop for 9 to 5%. What test is profitable [ waterwise ] is possible that we can achieve to keep the balance sheet lower we'll do that going forward. But I also believe you talked about the top lens we believe that the problems start last a while and this is a point of rent market, yes.

[Nikolas Stefanou, analyst]

Sorry, you said what's the percentage you want to keep in [ Naraha ] kind of like a stable sort of .

[Emeka Onwuka, executive]

We currently 25%. we are going to adjust that going forward. We are looking at our [ nararequirements ] and see how much lower we can get that to.

[Operator]

The next question comes from the line of Mike Ivanov with [ Checkers ].

[Unknown Analyst]

A few questions. Maybe the first one, on the MPU transaction, right? So I guess like my kind of questions kind of provided that the transaction is [ being ] light, let's say, tomorrow? How do you plan to approach the funding of this transaction? Because I remember we discussed -- you had some commitments from banks before.

So 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 the relevant with later highlights [Indiscernable] transaction for my first question.

The second question would be on the situation with the evacuation of oil through [ Forcados ]? -- terminal. If I understand correctly, you mentioned that the [ liquation ] of oil is currently suspended. But what is the current time line? I think you mentioned that there is a time line to fix this issue? And how is it possible to use IP pipeline at the moment to evacuate oil from OML for 38 and 41? How should we look at this as the eternity of 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 with the bond. So would it be possible just to provide more color on your view on the capital structure -- we want just to reduce the absolute amount of debt, which instrumented the capital structure you would like to target and et cetera. So it will be kind of helpful for us.

[Roger Brown, executive]

Okay. Thanks for those questions. Okay. So I'll just kick off the first one. So in terms of MPNU, we have, obviously, we signed and extended the sale and purchase agreement. There's still a court process underway between not us, but between NNPC and [ 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 provides the capital to it. So no natural we've kept them warm around that. So we don't foresee any issues in having the execute button on that once we get to go ahead from the President. -- other from the administration. In terms of the evaluation. And again, we monitor that regularly , but we -- our view has not changed as it is a very accretive transaction and in terms of value.

[Samson Ezugworie, executive]

Okay. Thanks, Ivan. On your second question on the [ Forcados ] terminal. In terms of time line, the absolute time line that we have discussed to restore the FOC terminal is 1 to 2 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 on the water 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 1 week to 2 weeks maximum. Now the second question is are we using AEP to evacuate crude out of the OMS for 38 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 Forcados has been down completely, that our production could have 0.

We have seen a valuation of up to 1.6 million barrels of crude from July last year to date. So this is 1 of those moments -- we are currently evaluating our production out of me 48 and 41 via the AEP while [ Forcados ] is down because the question through the AEP goes to the [ Escravos ] terminal.

[Emeka Onwuka, executive]

Okay. [Indiscernable] utilization of excess cost of capital. Our major focus parents on transit -- so we have to be cash for that transaction. We got to look at all options. And like I said, later in the year, we will guide the market on the capital -- capital [ pit on the France work ], we'll give more color as to the options at the time. We're on to look at all options for our excess cash here.

[Unknown Analyst]

Understood. So basically -- so I understood correctly that the funding in terms of the bank's commitment to provide funding is still there. So you don't have just a goal and kind of attract the new financing. So you have standing commitments from banks to fund this transaction if it's being live tomorrow.

[Unknown Executive]

Yes. before we signed the SPA, we are fully funded competitors to the market. and we keep it other banks we are not aware of any bank that is it currently. However, we'll continue to keep money depending on the period at which Water completed transaction. on liquidity to coin and then the balance with the bad. So but back from that are there.

[Operator]

The next question comes from the line of Nikhil Bhat with JPMorgan.

[Unknown Analyst]

I just have a couple of questions left. -- probably quick ones. So I'll ask all of them. Going forward, what do you see is your run rate CapEx that you think the business needs in order to maintain your current production levels -- that will be my first question.

The second question, you mentioned about the MPNU transaction and the court cases. Are you aware of any hearing date that has been set for the cold case about the MPNU transaction? And the last 1 is more for 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.

[Roger Brown, executive]

Okay. I got a [ Makoto ] answer 1 and 3 together, and then I will do the MPNU. [Indiscernable] -- the tax, when do we expect the tax to kick in in terms of the deferred tax. When do we see that running at?

[Emeka Onwuka, executive]

Okay. I would expect on the CapEx level, we expect the CapEx level to normalize to an annual CapEx of about $160 million, so that every year. The second question on the defect [ Asure ]. We currently know that -- because the aircraft on that side are coming to profitability with that will start amortizing that shortly. We know we have [Indiscernable]

[Roger Brown, executive]

Okay. Just in terms of the MPNU transaction, so just to benefit, there are 2 things. One is that there's a court ruling, which is observed so in between the next party ruling between the government and Exxon. That's really just the preservation. Court ruling. The real focus is an arbitration between under the joint operating agreement between the 2 partners. And we understand that's likely to be heard next year. In terms of that overall process.

In terms of the time line on long that will take, we're not privy to that. But our [ cations ], I think there's a point of principle here in terms of is there a preemption under the joint operating agreement or not. And certainly, excellent position is aligned with our position that because this is an acquisition of [ Mobi ] producing [ gun ] Unlimited, which is a share transaction we're acquiring from 2 [ Exxon ] subsidiaries based out of [ Delaware ]. -- because that is a shared transaction, where you're actually buying not just -- you're not just the interest in the JOA, but you're actually acquiring people, you're retiring liabilities, buildings are fully fledged and operating business.

In that aspect, we don't see that triggering preemption rights under the way, and that's certainly excellent view of it. But anyway, that will be something arbitration likely be heard next year.

[Unknown Analyst]

Sorry, Roger. A follow-up on that one. If the arbitration will only pick in next year in terms of the hearing, does your extension of the SPA covers that time line? And is there any guidance you could pause a bit give us in sort of I think the extension mentioned that there is -- you're sharing some of the economic benefit with Exxon. Is there any guidance you can provide us on sort of what proportion that might be?

[Roger Brown, executive]

Yes. Okay. So in terms of -- look, we expect this to get resolved before that arbitration is we're sort of operating position at the minute. But certainly, SBA does align it to go beyond so that the -- 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 that's subject to nondisclosure with the seller. So we can't say that much. But we can't guide in terms of the level of that. All we can say is that it's an attractive transaction even with even 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 extends and it has done to where we are today in the need to be sharing arrangement, obviously. But 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 MPNU and shareholders today. So I can't give you any more direction than that, obviously, because it's subject to nondisclosure.

[Operator]

[Operator Instructions] There are no more audio questions. I hand back the conference to Roger Brown for typed questions. we have a last minute questions from the line of Ayodeji Dawodu with Bank Trust & Co.

[Ayodeji Dawodu, analyst]

Good morning. Thanks very much for the call. Just a quick question on the gas side. I just wanted to just get an idea. Has there been any pushback, I guess, from the government in terms of pricing gas at the higher official rates -- my second question is, has there been any discussion in terms of actually increasing the boiler 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 environment? Those are my questions, please.

[Roger Brown, executive]

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 was -- there were different prices for industrial consumers we saw softening of the gas price. But the all intention the PIA is really to move on to a willing-buyer-willing seller model. And we're seeing that -- so look, 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 is 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 on the gas are dollar denominated, but actually physically paid in [ narrow ]. 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 flowback will be obviously 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 a [ narrow ].

And in terms then you asked a question on 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, to the acquisition. We don't see that real changing. You never do a bank until the final day. But we've looked at it and we expect that pricing to maintain.

[Operator]

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

[Roger Brown, executive]

Okay. So I believe I'm reading this, but I'm going to read it out for you, [Indiscernable] your benefit. So -- the question comes in regarding our oil production is the drilling schedule designed to replace natural decline only? Or 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.

[Samson Ezugworie, executive]

No, thank you. indeed the drilling program, as we see them today, we essentially drill to arrest decline on 1 hand. And then depending on the [ Captur ] program as well, we probably can accelerate a few wells for growth. And in terms of split, the OMs for 38 and 41, the Western Axis 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 number of 75% to 80% of those come from those 3 MLs. So that is where we concentrate our efforts because that is where also the future lies in response to your question.

[Roger Brown, executive]

Okay. Thanks for that. I think that the that brings an end to broadcast or webcast. I just want to thank everyone for attending. The questions are very good, particularly when you only got these results at 7:00 a.m. this morning. So clearly, there's a little quick readers. And and some good [ goal to questions ]. So we look forward to speaking to you again late October for our Q3 results. Thank you.