Kosmos Energy Ltd. (NYSE:KOS) Q3 2024 Earnings Call Transcript

Kosmos Energy Ltd. (NYSE:KOS) Q3 2024 Earnings Call Transcript November 4, 2024

Operator: Good day, everyone. And welcome to the Kosmos Energy’s Third Quarter 2024 Conference Call. As a reminder, today’s call is being recorded. At this time, let me turn the call over to Jamie Buckland, Vice President, Investor Relations at Kosmos Energy.

Jamie Buckland: Thank you, operator, and thanks to everyone for joining us today. This morning, we issued our third quarter 2024 earnings release. This release and the slide presentation to accompany today’s call, are available on the Investor’s page of our website. Joining me on the call today to go through the materials are Andy Inglis, Chairman and CEO; and Neal Shah, CFO. During today’s presentation, we will make forward-looking statements that refer to our estimates, plans and expectations. Actual results and outcomes could differ materially due to factors we note in this presentation and in our U.K. and SEC filings. Please refer to our annual report, stock exchange announcement and SEC filings for more details. These documents are available on our website. At this time, I’ll turn the call over to Andy.

Andy Inglis: Thanks, Jamie, and good morning and afternoon to everyone. Thank you for joining us today, for our third quarter results call. I’ll start today’s call by looking at the operational momentum, and enhance financial resilience we have built across the business, during the quarter. I’ll then hand over to Neal to look at the numbers in more detail, touching on some of the key financial objectives we completed in the last few months. Neal will then look forward to 2025, where we’ll discuss our CapEx plans for the year ahead, before I wrap up. We’ll then open the call for Q&A. Starting on Slide 3. Two years ago, we set our target to grow production by 50% from around 60,000 barrels of oil equivalent per day, to around 90,000 barrels of oil equivalent per day.

As this slide highlights, we’re making good progress towards that goal. In the Gulf of Mexico in the third quarter, we achieved first production at Winterfell, and completed two production enhancement projects at Kodiak and Odd Job both of, which are performing well. In Equatorial Guinea, the drilling campaign is underway, with the first of two wells online in October, the second one expected online later this month. We expect to spud Akeng Deep ILX well imminently, with a result by year-end. In Mauritania and Senegal, the partnership has made good progress over the last three months, with the project now nearing startup. I’ll talk more about that shortly. In Ghana, we finished the three-year drilling campaign mid-year, and are now optimizing the activity schedule for 2025.

On the finance side, we’ve done a lot this year, to enhance the financial resilience of the company by extending maturities, enhancing liquidity, and simplifying the capital structure. Neal will go into more detail on these points, later in the presentation. So in summary, we’re making good progress towards achieving our year-end goals. As production rises, we will remain focused on disciplined capital allocation, with a plan to significantly reduce growth CapEx year-on-year. As we look ahead to 2025, we plan to prioritize free cash flow, to enhance the value of the company for our shareholders. Turning now to Slide 4, which looks at the quarter in more detail. Gross Jubilee production in the quarter was around 87,600 barrels of oil per day, with year-to-date production at just under 90,000 barrels of oil per day.

FPSO uptime remained high at 99%, whilst voidage replacement although water injected to replace produce fluids, and maintain reservoir pressure was approximately 90% below the 100% target. This was a result of lower than planned uptime, of the generators supplying power to the water injection pumps. As I’ve discussed in previous quarters, to get maximum performance from the field, it’s critical to sustain water injection at levels that achieve voidage replacement in excess of 100%. Water injection has now been restored to record levels of around 300,000 barrels of water per day, which should enhance voidage replacement going forward. Third quarter gross gas production averaged 12,700 barrels of oil equivalent per day, which was lower quarter-on-quarter reflecting the planned downtime.

The onshore gas processing plant, we planned last quarter. During the quarter, the partnership contracted a new 4D seismic survey, over the Jubilee field starting in early 2025. The survey will be the first 4D that the partnership has conducted in almost eight years, having missed the cycle during COVID. It will utilize the latest processing techniques, and should generate a significantly improved image of the reservoir and fluid movements, further enhancing our understanding of this world-class field. The results of the survey should help to high grade well locations for the next phases of drilling. On TEN, the field is performing slightly ahead of expectations, with gross oil production of 18,500 barrels of oil per day in the quarter, and 18,800 for the year-to-date.

FPSO uptime remains high around 99%. An Equatorial Guinea gross production averaged around 23,000 barrels of oil per day. The infill drilling campaign is underway, with the first well online increasing gross production, to around 30,000 barrels of oil per day. The second infill well, is expected online later this month. These two wells combined should add around 3,000 barrels of oil per day, net to Kosmos by year-end. Following these two infill wells, we expect to spud the Akeng Deep ILX well imminently, with a result by year-end. In the U.S., Gulf of Mexico, production in the quarter was ahead of expectations, at 17,000 barrels of oil equivalent net to Kosmos, despite an active hurricane season. In early 3Q, we saw the start-up of the Winterfell project with two wells online in July, followed by the third in early October.

We successfully confirmed the extension of the main Winterfell reservoir to the South. It also confirmed the 20,000 barrel of oil equivalent per day gross production capacity, from the first phase of drilling. However, shortly after start of the third well, production of the field was curtailed, due to sand production from the third well seen as production facility. We’re currently working with the operator, to restart production from the first two wells, which collectively produce around 13,000 barrels of oil equivalent per day gross, and are evaluating options to remediate the third well. In the quarter. We also completed two important production enhancement projects, with a successful workover of Kodiak and start-up of the subsea pump projects of Odd Job, both of which are operated by Kosmos, by performing ahead of expectations.

Current production in the U.S. Gulf of Mexico has increased to approximately 20,000 barrels of oil equivalent per day, in line with expectations and around 50% higher than the first half of the year. On Tiberius, our next ILX project where Kosmos is operator, we’ve agreed with our 50-50 partner Oxy to defer sanctions to the second half of 2025, to prioritize cash generation in 2025. We continue to progress the farm down the field and have good levels of interest. Turning now to Slide 5, which provides an update on GTA. As the operator noted on their earnings call last week, good progress has been made across all the major work streams during the quarter. An LNG cargo has been brought in, and the carrier is currently berthed alongside the Hub terminal.

LNG from the carrier, is being introduced into the tank for the floating LNG vessel, to accelerate the cool down process, and commence commissioning of the LNG trains. The image on this slide and on the front cover of the presentation, show the carrier at the Hub Terminal. After successful mooring operations last quarter, the FPSO is expected to be ready for startup shortly, with a handover from the contractor Technip Energies to BP operations. The subsidy infrastructure is mechanically complete, which will enable first gas to flow from the field following FPSO startup. First LNG is expected around the end of the quarter, which is when we start to recognize production. So in summary, significant progress over the last three months towards project startup.

An important event for the GTA partnership, and the people of Senegal and Mauritania. I’ll now hand it over to Neal, to take you through the financials.

Neal Shah: Thanks Andy. Now turning to Slide 6, which looks at the third quarter in more detail. Production for the quarter of 65,400 barrels of oil equivalent was up 5% versus the prior quarter, but towards the bottom end of our guidance range, reflecting the first infill well in Equatorial Guinea coming online around two months later, than initially planned and slightly lower Jubilee production. This is partially offset by the higher production in the Gulf of Mexico that Andy mentioned earlier. Sales volumes were as expected with three cargoes in Ghana and one in Equatorial Guinea. Costs were largely in line with guidance with OpEx slightly better helped by lower than anticipated costs in Ghana for the quarter. CapEx came in slightly above the guidance range, which was a result of higher-than-forecasted spend, on the EG drilling campaign in 3Q.

We now expect CapEx to be around $800 million for the year. This equates to around $100 million in 4Q, a significant reduction from previous quarters in 2024, and a good guide on where we expect quarterly CapEx to be in 2025. Finally, as we mentioned last quarter, the working capital benefit from the first half of the year, reversed in the third quarter, reflecting completion payments associated with projects delivered across the portfolio. This working capital movement, was largely responsible for the cash outflow in 3Q. Turning to Slide 7. During the quarter, we made significant progress to enhance the financial resilience of the company, as we head into 2025. In September, we successfully issued $500 million of new senior notes due 2031 at 8.75%.

Alongside the new issue, we completed a series of tender offers to repurchase $500 million of our outstanding senior notes, across multiple maturities, paying down the majority of our 2026 notes, while also reducing the outstanding amounts of our notes due 2027 and 2028. The result of these transactions is that we have no maturities in 2025, and only a small stub in 2026, which we would anticipate paying with free cash flow from the business. Also during the quarter we added two new banks to our RBL syndicate, increasing our total commitments to the facility size of $1.35 billion. Post quarter end, we also canceled our undrawn revolving credit facility ahead of its year-end maturity, simplifying the capital structure. In addition, we continue to actively manage future price volatility through our rolling hedging program.

We currently have around 45% of our first half of 2025 oil production hedged, with downside protection of approximately $70 per barrel. We expect to continue this through end of the year, layering in more hedges for 2025, as our 2024 hedges roll-off, providing solid protection to our cash flow, from potentially volatile oil prices in 2025. Moving to Slide 8. As mentioned previously, as products are delivered, we expect to see a material step down in CapEx with around $100 million expected in 4Q. This level of quarterly CapEx, is a good representation of where we expect to be in 2025. As Andy talked about earlier, we plan to prioritize free cash flow next year, and have therefore high graded our maintenance capital to focus on drilling at Jubilee and Winterfell, to mitigate decline in Ghana and the Gulf of Mexico.

Equatorial Guinea will benefit from this year’s infill drilling program, and we anticipate very low maintenance capital on GTA once the project is online. We will be disciplined in allocating capital to growth opportunities in 2025, ensuring we only spend what is needed to preserve our deep pipeline of growth options, which remains a key differentiator for our company. The growth options listed in the appendix, consist of both high quality oil and gas projects spread across our different business units. Importantly, many of these are Kosmos operated such as Tiberius, Yakaar-Teranga and Akeng Deep, which gives us much greater control over both pace and spend, than we’ve had on projects in the past. With that, I’ll hand it back to Andy to conclude today’s presentation.

Andy Inglis: Thanks Neal. Turning now to Slide 9. We’ve achieved a lot so far in 2024, with the start of new projects and more to come as we close out the year. Production is now ramping up towards our target of approximately 90,000 barrels of oil equivalent per day, around the end of the year. As Neal said on the previous slide, we expect CapEx to fall sharply in the fourth quarter, then continue at this lower level through 2025. With this disciplined capital allocation, we plan to prioritize free cash flow delivery in 2025, which should allow us to paydown debt and reduce leverage. And finally, our differentiated operated growth projects portfolio, provides significant optionality for the future, with high quality oil and gas investment opportunities, with a much greater degree of control. Thank you. And I’d now like to turn the call over to the operator, to open the session for questions.

Operator: Thank you. [Operator Instructions] Our first question is from Charles Meade with Johnson Rice. Please proceed.

Q&A Session

Charles Meade: Good morning Andy, Neal and to the whole Kosmos team there. Andy, I want to ask a question about the 2025 CapEx outlook, and the changes there. I recognize that that $550 million indication you had given was, I took this more of a kind of a guideline. It wasn’t necessarily a specific roster, or perhaps it wasn’t a specific roster of projects. But can you talk about the moving pieces? What may be moved out of ’25, and how much of that delta of $150 million is related to Tiberius, sliding through the back half of the year?

Andy Inglis: Yes. Hi Charles. Yes look, you’re right. The $550 million was more of a guideline and we characterized it as saying it’s around $200 million to $250 million going forward in growth on average, and around maybe $300 million, $350 million in the base going forward. So as we look towards ’25, as we said in the remarks, our focus is on free cash flow delivery next year. And therefore the CapEx $400 million is ensuring that we put sufficient CapEx into the base. We have drilling projects in the Gulf of Mexico, in Winterfell with two additional wells, and we have the restart of the Ghana or infill program in Jubilee. In EG, there’s not a lot of maintenance capital. We’ve had the drilling program in ’24, and there’s little maintenance CapEx in GTA, because we’ve got more than sufficient well capacity.

So that’s where the base spend is going to maintain the base. And then, we are spinning down the growth CapEx. The primary mover is the one that you’ve identified, which is Tiberius. So essentially that slides by about a year. The project’s obviously still there – under our operatorship. We’re aligned with Oxy around the timing, so that’s the primary delta. And then you’ve got a little bit of additional growth CapEx, just keeping everything ticking over. So the other message of course from this is that in deferring that growth CapEx, we’re not actually damaging any of the growth options. It’s simply about a shift, probably in about a year in terms of the Tiberius timing.

Charles Meade: Got it. That’s helpful detail. And then on the ’25 Jubilee drilling, I wonder if you could talk a little bit more about what the priorities are there? I mean obviously, you’re trying to get the FPSO up to capacity. But I imagine that whatever you learn from this – from your 4D seismic shoot, it’s going to be – not going to have enough time to – for that to inform your ’25 drilling, but would maybe confirm that and just talk about the goals of the ’25 drilling program are?

Andy Inglis: Yes. Well, sort of so. We’ll start at the next phase of drilling on Jubilee, Charles. And as we’ve sort of remarked, I think that I believe the 40 is going to have a big impact on that. And it’s – the actual line – the acquisition techniques, it’s a towed streamer. It’s not – haven’t actually moved massively. But clearly, the processing has both in terms of the quality of want you get and actually the timeliness of it, you get the product a lot earlier, yes. So we have a sort of a challenge to manage when we start, the earlier we start the better, but how do we ensure that we’re fully incorporating that learning. Now there are a couple of wells where we know that the 40 is not going to have a big impact. So we have sort of a couple of wells that are secure, from that perspective.

And then, you start to feather in the additional information that you get from the 4D seismic. So in a way, it’s just getting the right balance of how do you ensure you’re taking full advantage of the seismic, but not waiting too long, by where you’re diminishing the impact of the infill program. So I think, we’ve gotten the balance of that right now.

Charles Meade: Great, thank you.

Andy Inglis: Great, thanks, Charles.

Operator: Our next question is from Bob Brackett with Bernstein Research. Please proceed.

Bob Brackett: Good morning. I had a question around Akeng Deep, and then one around Tiberius that are somewhat related. We’ll know something around Akeng Deep by year-end, I think you guided to. What are the implications for success case on capital for 2025? And I’ll follow up with Tiberius?

Andy Inglis: Yes, you’re right, Bob. Look, I think the Akeng Deep has an important well, because it opens up a whole new play that enables us to use existing infrastructure, it’s ILX, tie back the wells. I think when you look at ’25 with success in the Akeng Deep, we won’t rush at it. I think what we want to do is make sure that we’re high grading the right opportunities that exist across Equatorial Guinea. So we’ve had an infill program in Ceiba and Okume. There’s more of those wells. With success of the Akeng Deep, you have a deeper target that you can bring in. So I would see it actually impacting ’26 forward when we’re actually high-grading the capital that we planned before for ’26 in Equatorial Guinea. And actually, it will be about debating an infill while and say Okume or Ceiba versus Akeng Deep.

Now the good news is, if you remember that we extended the leases in the blocks to out beyond 2040, all right? So we’re not in a big rush. So this is about ensuring that we get the right hydrating of the opportunity set. I’m actually – I’m excited because I think we’re we’ve drilled, we finished the first well on Ceiba, because we just finished the second well on Okume. The rig is literally moving as we speak to go and drill the Akeng Deep. But I think that between the success of the infill program, we’re going to create quite a lot of optionality now. And with success, we will have some choices to make. I think, around the future infill program. So that’s really going to impact ’26, Bob, rather than ’25.

Bob Brackett: Very clear. And that almost ties well into my question on Tiberius. Given the 2H ’25 FID it gives you potentially more time, to look at the farm down. And if there’s less interest, then your desire to retain a greater working interest, which I know we’ve talked about in the past, does the farm down have to go forward? Or if the FID comes late, would you keep a greater working interest?

Andy Inglis: Look, even I have debated this, we like it a lot. And nothing has changed. This is about prioritizing, I think, the pace at which we move forward on some of our growth options. So I think this is not about not liking it. I think we believe working interest around the 40% level, it’s probably right for us. I think Oxy is about the same place of bringing in a partner is the right thing to do. And we’re clearly going through that process now. So we’ll let the process run Bob. I don’t think it changes our intent. And ultimately, we see – it’s a good prospect. We want to ensure there’s alignment on the development plan, which we can now create that alignment going forward. And so with ourselves is tied back to an Oxy-operated platform, it’s a very clear project. So I think no change of plan simply deferral, and the farm up process is working as we speak.

Bob Brackett: Very clear. Thanks.

Andy Inglis: All right, thanks Bob.

Operator: Our next question is from Matt Smith with Bank of America. Please proceed.

Matthew Smith: Hi there. Good morning, Andy. Good morning, Neal. A couple of questions from me. I’ll just start with the first perhaps, and that would be on Tortue if I could. And really, just could you remind us around the commissioning process for the FLNG sort of is that sort of set in stone. I believe you referred to a six-month period of commissioning before? Or is that an expectation? And then really just – can you remind us of the implications sort of during that stage? What do you expect from production and cargoes, but also your exposures to the commercial arrangement that you have with BP? So I’ll start there with the first?

Andy Inglis: Okay. Right. So in terms of the commissioning process of the FLNG vessel, we’re accelerating that process by bringing in the carrier, and starting the process with gas coming from the LNG cargo. That allows us to cool down the tanks. It allows us to enable us to run the first – the compressors at the front end of the process, and then actually spin the key compressors in the FLNG trains themselves. So that’s the process we’re going through at the moment. And then that allows us when we introduce gas, from the FPSO essentially very quickly to start making LNG. So that’s the process. And that’s when we actually recognize production. I think the six-month program that you’re talking about is actually to do, with the contractual arrangements associated with the finalization of the agreements that we have with Golar.

In terms of them meeting all of the criteria that they have to meet, as part of their contracts, yes. So I think you have to sort of separate those out, from the actual physical representation of the production and the revenue, which comes as soon as we start putting gas through the FLNG, and start producing gas and then exporting it, yes. So I think, what I’m sort of explaining there for, is the process from the introduction of gas to the production of our LNG revenue recognition is, going to be a lot shorter than you described. And in terms of the marketing arrangements with BP sort of nothing changes, they would lift the gas and sell the gas.

Matthew Smith: No. Thank you for the clarification. And just a follow-up. Was whether the commercial agreement that you have with BP, Am I right in thinking that’s tied to the six-month commercial commissioning process that you have with Golar i.e., you’ll be free to sell your cargoes on the spot market during that time frame. Is that correct?

Andy Inglis: No. No. BP will lift the cargoes. So we wouldn’t be selling anything on the spot market in that time period.

Neal Shah: There’s essentially, Matt, go under the long-term pricing frame. There’s a slightly different option in where there’s an MVP reference potentially, but as a base case sort of it’s off-brand on the same terms as the long-term contract or in commissioning.

Matthew Smith: Okay.

Andy Inglis: Yes, really precise about in that six-month period, only in that six-month period, there’s a price market versus MVP, and there’s a price market versus Brent, okay? So the – that’s the only sort of difference between that six-month period and then the long-term period.

Matthew Smith: Okay, understood. I think that’s consistent with my understanding. Then that makes sense. Okay, well thanks for clarifying all of that. And then hopefully the second – understood.

Operator: Our next question is from Mark Wilson with Jefferies. Please proceed

Mark Wilson: Thank you. First question, just a clarification point on the U.S. Gulf of Mexico. You say that current production levels at 20,000 barrels of oil a day. I just wondered, is that current level include those two Winterfell wells you’re looking to restart? That’s the first question.

Andy Inglis: It’s around 20,000 without those, Mark, yes. So we’re – we benefited really from the production on the Odd Job subsea pump, being better than we thought and the Kodiak workover doing better than we thought. So, we’re slightly ahead of where, we would have been. But in essence, it’s around that 20,000 barrel a day, Mark.

Mark Wilson: Okay. Very good. And then, so those provided that the same thing, is sorted those wells four and five next year, you’d expect to be able to maintain or even slightly higher than these current levels through ’25?

Andy Inglis: Yes, be slightly higher Mark, yes, exactly. Yes. We’re building production there rather than it going down. And clearly, again, we benefited from a couple of the production enhancement projects, doing slightly better than we forecast, which is good. So the base in a sense is stronger, and then you’re adding the wells from Winterfell.

Mark Wilson: Okay. Thank you for that. So then into ’25 with the lower CapEx, as you’ve spoken to already, and the focus on getting leverage down. Could I ask, is there a leverage point or a target you done to get to where shareholder returns, or a buyback could be something you’d look at?

Andy Inglis: Yes. I’ll turn it over to Neal.

Neal Shah: Yes. Thanks, Mark. Yes, I don’t think our views change. We’re very much focused on getting leverage down to less than one and a half times. And once we get beyond sort of that one and a half times, then we’ll look at shareholder returns, which is clearly an option that we’re keeping on the table. And so – but like I said, I think from our perspective ’25, will be around prioritizing free cash flow, using that cash flow to paydown debt and accelerate that point. So I don’t think it will jump, but it’s very much still on our minds, and we’re accelerating the pathway to get there.

Mark Wilson: Okay. Very good. And then final question. So you’ve asked about the carrier and FLNG vessels seem, to accelerate the commissioning time of the FLNG vessel at Tortue. Could you just speak to the final steps for the FPSO that, has crept into 4Q for first gas getting through that? What are the final steps that need to be taken to get that first gas, please?

Andy Inglis: Yes, good point, Mark. I think clearly – the FPSO is an important part of the chain and we’re close. I think just to add a little bit of color, Technip Energies has a contract where they actually perform the commissioning of the vessels. So all the work is ongoing at the moment, is under Technip watch, and they’re commissioning the vessel. The next step then is handed over to BP operations. So it goes from Technip Energies as a project, to BP ops who then undertake the – we’ll take undertake the operations. At that point, it sort of moves into the sort of the big ops world, where that’s under their control of work and their control of work, you can then energize the subsea system, which then allows you to introduce gas.

I think as we go down that journey, maybe an important milestone was actually when the Flotel that was supporting the work that Technip Energies we’re doing offshore, it’s now departed. And I think that’s an indication to you, I think, that we’re very close in terms of the few remaining punch list items that need to be performed that allow that process ready for startup to occur. And clearly, that’s the defining sort of criteria so I think, I have to finish all that work, which is those final punch list items, and then it gets handed over. Flotel has already gone, which signals the amount of work to be done is not very much.

Mark Wilson: Excellent, thank you for that. Very clear. I shall hand it over now.

Andy Inglis: Great, thanks Mark. Appreciate it.

Operator: Our next question is from Neil Mehta with Goldman Sachs. Please proceed.

Neil Mehta: Thank you, Andy and team. So I guess the first question is just on the 90,000 barrels a day equivalent. When do you think you get there in, as you think about the next couple of years targeting. And then in your Q4 volume guide. Is there any assumption for volume contribution from GTA from Tortue in there?

Andy Inglis: Yes. So sort of two-part question, Neil. Sort of going forward, I think, if you start to think about the company, it’s obviously invested heavily to sort of grow the production now. It’s about a focus in on sort of maintaining that level. As I discussed on a prior question, the maintenance CapEx is sort of low in GTA. You’ve built the wells. There’s very little CapEx to go. So you got a sort of flat production curve from that. The production that goes into the Gulf of Mexico, as Mark alluded to in his question, you sort of with GTA with Winterfell 4 and 5, we have probably a small amount of growth there. I think, we’ll sort of see Equatorial Guinea relatively flat. And therefore, and then back to drilling in Jubilee, which again is about sort of maintaining a flat, and then starting to increase.

So I think if you look through ’24, ’25, with ’24 CapEx aimed at the base, it’s about maintaining. And then beyond, then you start back into the cycle in ’26 of seeing the growth projects, but you won’t see the impact of Tiberius until ’27 now. So I think relatively flat and then post – you’re seeing some growth in ’27. So I think that’s the way I’d think about it. And clearly, we’re prioritizing the investment level in the base, to ensure that we keep it robust. Yes. And then look, in ’20 – the production guidance in ’20 – in the fourth quarter of ’24. There’s a very small amount of GTA in that. We said around the end of the year. Production is recognized when it goes – when actually we get gas flowing from the FPSO into the FLNG vessel, yes.

So, we’ve said that’s around the end of the year. So you can assume there’s a small amount of gas there, a small contribution.

Neil Mehta: Perfect. Okay. That’s very helpful. And then what is the assumption you recommend for 2025 for your LOE, per barrel as you think about the pro forma company for GTA in 2025? Just how do you think this project is going to change the consolidated cost structure?

Andy Inglis: Yes, Neal, do you want to take that up?

Neal Shah: Yes so. And then again, it’s easier to think about it on a per BOE basis. But again, I don’t see a meaningful change on the oil side of the business. We’ve been increasing the run rate on the LOE, for the gas side of the business. We said sort of we expect this quarter to be sort of, between $60 million and $80 million for the quarter. There’s a number of things going on there. But when you think about it in a normalized sense, there’s, I’d say, when – on a per Mcf basis for the gas business, the normalized recurring OpEx is around $4 per Mcf in – on the gas side, and that includes the FLNG toll, and then sort of the upstream costs. So plus or minus, it’s around in that range. And then, again, I think – and we’ll get into this in terms of guidance for ’25 in February.

But there’s also – if you recall, in 2021, we sold the FPSO to BP, and we’re working on the refinancing of that. So that’s currently in OpEx as well. And so, there’s a little money associated with that that will come down, as we get that piece refinanced next year.

Neil Mehta: Okay, thanks Neal. Appreciate it.

Neal Shah: Sure.

Operator: [Operator Instructions] Our next question is from Stella Cridge with Barclays. Please proceed.

Stella Cridge: Hi there. Afternoon. If you don’t mind, if I could just follow-up on the previous question. In terms of this gross OpEx for Tortue, could you just talk about how much of this in Q4 are some of these one-off items, just in absolute dollar terms, and what the quarterly OpEx would be in dollar terms for 2025?

Andy Inglis: And Neal, do you want to take that up?

Neal Shah: Yes. Let us get back to you, sort of off and I don’t remember exactly, because there are some moving parts in that Q4 number. So sorry, we’ll get back to you on that in terms of the exact breakdown on that Q4 number.

Stella Cridge: Okay. That would be great.

Andy Inglis: What I said, Stella, is that the Q4 number includes the pre-commissioning cargo. So it includes the expense associated with bringing the carrier in and so on. So you’ve got a one-off item associated with that. And then, you do have some pre-commissioning costs associated with the BP team, as they go through the process now of the handover from Technip Energies. All of that occurs, obviously, ahead of the production going forward. So the two big items are those two items. Obviously, once production is running, and then it normalizes into the – basically the $2 per Mcf number that Neal talked about. So that’s probably the simplest way to look at it. We can come back and give you the exact breakdown, but the – spend ahead of production is around those two items. And then as soon as you get into production, then you’re around $2 an Mcf for OpEx, and about $2 for the lease cost.

Stella Cridge: Okay. That’s fantastic. Thanks. And could you just talk a little bit more about this refinancing of the leaseback that you talked about before? Just what do you mean by that exactly?

Andy Inglis: Yes, Neal?

Neal Shah: Yes. So just – so when we – so we sold the FPSO to BP in 2021, then so it’s leased back to the partnership. It was always sort of envisioned post first gas in the project, then we’d look for put in a permanent financing, or permanent solution around the FPSO. And so that’s what we’re working collaboratively with BP on at the moment. And so it’s not – it’s starting to – we are seeing the FPSO in the OpEx lease today, depending on either if we end up doing the refinancing, which we’re working on that amount in terms, of what we see in the OpEx line will come down pretty substantially.

Stella Cridge: Okay. That’s fantastic. Thanks. And if you don’t mind if I just ask 1 final thing. In Senegal, is there any update on discussions that you’ve had with the authorities there regarding your outlook for Yakaar-Teranga, your business in the country and some of the mentions also we heard during the first election about taxes. I mean, I’m aware there’s a second election coming up, so things may be in the air, but any comments on that side would be good?

Andy Inglis: Look, it’s now over six months actually since the new administration has come in. So they’re a new party in power. There’s been a process of them putting people in the key positions within the administration. And that process has sort of been lengthened as a result of the decision to go to the election of the parliament, which is later this month. So I’d say in the first sort of six months of the journey, it hasn’t really had – we haven’t seen really any impact on our sort of daily operating business. We’ve continued to progress GTA, and we continue to work very closely with the Ministry of Energy and the NSC in terms of PETROSEN. I would say it has slowed down the Yakaar-Teranga a little. And that’s partly as you get into conversations there for around the growth CapEx, you can sort of see that sort of probably moving slightly later.

And that sort of natural, new government coming in, they’re picking it up. They’ve got new people within PETROSEN. They’ve got new people within the ministry that are handling those conversations. My sense of all of that is going to clear in the sort of end of the year, beginning of the following year. And ultimately, it’s an important project for their national plan. It’s about creating a low-cost gas that really replaces a few oil wells currently being consumed for power. It also is a source of export. And therefore, in combination, you’re creating an important new revenue stream in terms of development of that resource, but you’re also creating an important domestic gas supply, which creates energy, security and it enables a lower cost of power to the country.

So it’s an important project. So the conversations are ongoing as we speak. But I just think things are going to take slightly longer, just because of that transition of power. And then further complicated bind the decision, if you like, to go with a national election. But I think the message to take out of it, nothing has really impacted the important work on GTA, which is obviously our primary focus at the moment.

Stella Cridge: Superb. Thanks.

Andy Inglis: Great. Thank you.

Operator: Since there are no further questions at this time, I would like to bring the call to a close. Thanks to everyone for joining today. You may disconnect your lines at this time, and thank you for your participation.