Kosmos Energy - Q3 2024

Transcript

Operator (participant)

Good day, everyone, and welcome to 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 of Investor Relations at Kosmos Energy.

Jamie Buckland (VP of Investor Relations)

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 Investors 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 G. Inglis (Chairman and CEO)

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 enhanced 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've 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 three, 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 of 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 and 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 four, which looks at the quarter in more detail. Gross daily production in the quarter was around 87,600 barrels of oil per day, with yesterday's production of just under 90,000 barrels of oil per day. FPSO uptime remained high at 99%, while voidage replacement, or the water injected to replace produced 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 of 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 at around 99%. On Tiberius, 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 study 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 startup of the Winterfell project with two wells online in July, followed by the third in early October, which successfully confirmed the extension of the main Winterfell reservoir to the south. It also confirmed the 20,000 barrels of oil equivalent per day gross production capacity from the first phase of drilling. However, shortly after startup of the third well, production of the field was curtailed due to sand production from the third well seen at the production facility.

We're currently working with the operator to restart production from the first two wells, which collectively produced around 13,000 barrels of oil equivalent per day gross, and they are evaluating options to remediate the third well. In the quarter, we also completed two important production enhancement projects with a successful workover at Kodiak and startup of the subsea pump project at Odd Job, both of which are operated by Kosmos and are 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 five, 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 tanks of the floating LNG vessel to accelerate the cooldown 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 subsea 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 D. Shah (CFO)

Thanks, Andy. Now turning to slide six, 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 was 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 Q4, 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 Q3. Turning to slide seven, 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 eight. As mentioned previously, as projects are delivered, we expect to see a material step down in CapEx, with around $100 million expected in Q4. 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 the 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 G. Inglis (Chairman and CEO)

Thanks, Neal. Turning now to slide nine. We've achieved a lot so far in 2024, with startup 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 pay down 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 (participant)

Thank you. We will now be conducting a question-and-answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. And for participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Our first question is from Charles Meade with Johnson Rice. Please proceed.

Charles Meade (Research Analyst)

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 indication you had given was I took it as 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 maybe moved out of 2025 and how much of that delta of $150 is related to Tiberius sliding to the back half of the year?

Andy G. Inglis (Chairman and CEO)

Yeah. Hey, Charles. Yeah, look, you're right. The 550 was more of a guideline. And we characterized it as saying it's around 200-250 going forward in growth on average and around maybe 300-350 in the base going forward. So as we look towards 2025, as we said in the remarks, our focus is on free cash flow delivery next year. And therefore, the CapEx 400 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 infill program in Jubilee. In EG, there's not a lot of maintenance capital. We've had the drilling program in 2024, 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 thinning down the growth CapEx. The primary mover is the one that you've identified, which is Tiberius. 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 (Research Analyst)

Got it. That's helpful detail. Thank you. And then on the 2025 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 your 4D seismic shoot, it's not going to have enough time for that to inform your 2025 drilling. But maybe confirm that and just talk about what the goals of the 2025 drilling program are.

Andy G. Inglis (Chairman and CEO)

Yeah. Well, sort of, we started the next phase of drilling on Jubilee, Charles. And as we've sort of remarked, I think that I believe the 4D is going to have a big impact on that. And the actual acquisition techniques, it's a towed streamer. It's not having to actually move massively. But clearly, the processing has, both in terms of the quality of what you get and actually the timeliness of it. You get the product a lot earlier, yeah? 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 4D is not going to have a big impact. So we have sort of a couple of wells that are secure from that perspective.

Then you start to feather in the additional information that you get from the 4D seismic. 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. I think we've got the balance about right now.

Charles Meade (Research Analyst)

Great. Thank you.

Andy G. Inglis (Chairman and CEO)

Great. Thanks, Charles.

Operator (participant)

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

Bob Brackett (SVP and Senior Research Analyst)

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 too. What are the implications for success case on capital for 2025, and I'll follow up with Tiberius.

Andy G. Inglis (Chairman and CEO)

Yeah. No, you're right, Bob. Look, I think Akeng Deep well is 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 2025, with success in 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 Tiberius and Akeng. There's more of those wells. With success at Akeng Deep, you have a deeper target that you can bring in. So I would see it actually impacting 2026 forward when we're actually high-grading the capital that we've planned for 2026 in Equatorial Guinea. And actually, it'll be about debating an infill well into Akeng or Tiberius 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 high-grading of the opportunity set. I'm excited because I think we've drilled. We finished the first well on Tiberius. We just finished the second well on Akeng. The rig is literally moving as we speak to go and drill 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 2026, Bob, rather than 2025.

Bob Brackett (SVP and Senior Research Analyst)

Very clear. And that almost ties well into my question on Tiberius. Given the 2H 2025 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 G. Inglis (Chairman and CEO)

Look, you and I have debated this. We like it a lot. And nothing's changed. This is about us 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 a working interest around the 40% level is probably right for us. I think Oxy in 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, it's tie 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 (SVP and Senior Research Analyst)

Very clear. Thanks.

Andy G. Inglis (Chairman and CEO)

All right. Thanks, Bob.

Operator (participant)

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

Matt Smith (Small Business Consultant)

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 of 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 G. Inglis (Chairman and CEO)

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, yeah? 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, yeah? So I think what I'm sort of explaining therefore is the process from the introduction of gas to the production of LNG and the revenue recognition is going to be a lot shorter than you've described. And in terms of the marketing arrangements with BP, sort of nothing changes. They will lift the gas and sell the gas.

Matt Smith (Small Business Consultant)

No, thank you for the clarifications there. And I suppose just to 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 G. Inglis (Chairman and CEO)

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

Neal D. Shah (CFO)

Those essentially go under the long-term pricing frame. There's a slightly different option where there's an NBP reference potentially, but as a base case, sort of it's off Brent on the same terms as the long-term contract during commissioning.

Matt Smith (Small Business Consultant)

Okay. Understood. Thank you for the clarification.

Andy G. Inglis (Chairman and CEO)

Yeah. Really precise about it. In that six-month period, only in that six-month period, there's a price marker versus BP, and there's a price marker versus Brent, okay? So that's the only sort of difference between that six-month period and then the long-term period.

Matt Smith (Small Business Consultant)

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.

Andy G. Inglis (Chairman and CEO)

Done.

Matt Smith (Small Business Consultant)

Understood.

Operator (participant)

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

Mark Wilson (Oil and Gas E&P Senior Research Analyst)

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

Andy G. Inglis (Chairman and CEO)

It's around 20,000 without those mark, yeah? So we've benefited really from the production on the Odd Job subsea pump being better than we thought and the Kodiak workover being 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 (Oil and Gas E&P Senior Research Analyst)

Okay. Very good. And then so those provided that the sand thing is sorted, those wells four and five next year, you'd be expected to be able to maintain or even be slightly higher than these current levels through 2025?

Andy G. Inglis (Chairman and CEO)

Yeah. It'd be slightly higher, Mark. Yeah. Exactly. Yeah. We're building production there rather than it going down. And clearly, again, we've 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 (Oil and Gas E&P Senior Research Analyst)

Okay. Thank you for that. So then into 2025 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'd aim to get to where shareholder returns or a buyback could be something you'd look at?

Andy G. Inglis (Chairman and CEO)

Yeah. I'll throw that over to Neal.

Neal D. Shah (CFO)

Yeah. Thanks, Mark. Yeah. So 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, 2025 will be around prioritizing free cash flow, using that cash flow to pay down debt and accelerate that point, so I don't think it'll jump, but it's very much still on our minds, and we're accelerating the pathway to get there.

Mark Wilson (Oil and Gas E&P Senior Research Analyst)

Okay. Very good. And then, final question. So you've asked about the carrier and FLNG vessels 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 G. Inglis (Chairman and CEO)

Yeah. No, good point, Mark. I think clearly the FPSO is an important part of the chain, and we're close. I think to add a little bit of color, Technip Energies has a contract where they actually perform the commissioning of the vessel. So all the work that's ongoing at the moment is under Technip's watch, and they're commissioning the vessel. The next step is then it's handed over to BP Operations. So it goes from Technip Energies as the project to BP Ops, who then will undertake the operations. At that point, it sort of moves into the sort of the BP Ops world where it's under their control of work. Under 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 were 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 of ready for startup to occur. And clearly, that's the defining sort of criteria is Technip have to finish all their work, which is those final punch list items, and then it gets handed over. Flotel is already gone, which signals the amount of work to be done is not very much.

Mark Wilson (Oil and Gas E&P Senior Research Analyst)

Excellent. Thank you for that. Very clear. I shall hand it over now.

Andy G. Inglis (Chairman and CEO)

Great. Thanks, Mark. Appreciate it.

Operator (participant)

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

Neil Mehta (Head of American Natural Resources Equity Research)

Thank you, Andy, team. So I guess the first question is just on the 90,000 barrels a day equivalent. When do you think you get there 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 G. Inglis (Chairman and CEO)

Yeah. So sort of two-pronged question, Neal. It's sort of going forward, I think, as 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 2025 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 get a sort of flat production curve from that. The production that goes into the Gulf of Mexico, as Mark alluded to in his question, sort of with GTA with Winterfell four and five, there's probably a small amount of growth there. I think we'll sort of see ex-GOM relatively flat, and therefore and then back to drilling in Jubilee, which again is about sort of maintaining it flat and then starting to increase.

So I think as you look through 2024, 2025, with 2024 CapEx aimed at the base, it's about maintaining. And then beyond, then you start back into the cycle in 2026 of seeing the growth projects, but you won't see the impact of Tiberius until 2027 now. So I think relatively flat, and then post, you're seeing some growth in 2027. 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, yeah? Yeah.

And then look, the production guidance in the fourth quarter of 2024, there's a very small amount of GTA in there. We said around the end of the year, production is recognized when actually we get gas flowing from the FPSO into the FLNG vessel, yeah? So we've said that's around the end of the year, so you'd assume there's a small amount of gas there, a small contribution.

Neil Mehta (Head of American Natural Resources Equity Research)

Perfect. Okay. That's very helpful. And then what is the assumption that 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 G. Inglis (Chairman and CEO)

Yeah. Neal, do you want to pick that up?

Neal D. Shah (CFO)

Yeah. So 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, I'd say on a per MCF basis for the gas business, yeah, the normalized recurring OpEx is around $4 per MCF on the gas side. And that includes the FLNG toll and then sort of the upstream cost. 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 2025 in February, but there's also, if you recall, in 2021, we sold the FPSO to BP, and we're working on a refinancing of that. So that's currently in OpEx as well. And so there's a little money associated with that. That'll come down as we get that piece refinanced next year.

Neil Mehta (Head of American Natural Resources Equity Research)

Okay. Thanks, Neal. Appreciate it.

Andy G. Inglis (Chairman and CEO)

Sure.

Operator (participant)

As a reminder, this is Star One on your telephone keypad if you would like to ask a question. Our next question is from Stella Cridge with Barclays. Please proceed.

Stella Cridge (Analyst)

Hi there. Afternoon. Yeah. 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 G. Inglis (Chairman and CEO)

Neal, you want to pick that up?

Neal D. Shah (CFO)

Yeah. Let us get back to you sort of offhand. I don't remember exactly because there are some moving parts in that Q4 number. So all right. We'll get back to you on that in terms of the exact breakdown on that Q4 number.

Stella Cridge (Analyst)

Okay. That would be great.

Andy G. Inglis (Chairman and CEO)

What he said, Stella, is 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, then it normalizes into 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. 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 (Analyst)

Okay. That's fantastic. Thanks. And could you just talk a little bit more about this refinancing of the lease back that you talked about before? Just what do you mean by that exactly?

Andy G. Inglis (Chairman and CEO)

Yeah. Neal?

Neal D. Shah (CFO)

Yeah. So when we sold the FPSO to BP in 2021, then it's leased back to the partnership. It was always sort of envisioned post first gas of the project, then we'd look for putting a permanent financing or a 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 (Analyst)

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

Andy G. Inglis (Chairman and CEO)

Yeah. Well, 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, we haven't seen really any impact on our sort of daily operating business. We've continued to progress GTA, and we've continued to work very closely with the Ministry of Energy and the NOC in terms of petrol sales. I would say it has slowed down Yakaar-Teranga a little.

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. That's 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. Ultimately, it's an important project for their national plan. It's about creating a low-cost gas that replaces fuel oil that's currently been 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 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 by the decision, if you like, to go with a national election. But I think the message you should take out of it, nothing's really impacted the important work on GTA, which is obviously our primary focus at the moment.

Stella Cridge (Analyst)

Super. Thanks.

Andy G. Inglis (Chairman and CEO)

Great. Thank you.

Operator (participant)

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.