KOS - NYSE

Good day, everyone. Welcome to Kosmos Energy's Third Quarter 2025 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.

Thank you, operator and thanks to everyone for joining us today. This morning, we issued our third quarter 2025 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.

Thanks, Jamie. And good morning and afternoon to everyone. Thank you for joining us today for our third quarter results call. I'll start off the call by taking you through Kosmos' priorities, reinforcing the consistent messages I gave last quarter, before updating you on progress across the portfolio. Neal will then walk through the financials and the work we've done recently to enhance the resilience of the balance sheet before I wrap up with closing remarks. We'll then open up the call for Q&A. Starting on Slide 3. As we navigate the ongoing commodity price volatility, our key priorities have not changed. In our first and second quarter results, I talked about growing production and reducing costs to prioritize free cash flow, while continuing to strengthen our balance sheet. We've made important progress across all 3 of these areas this quarter. Starting with production. At Jubilee, the partnership brought the first producer well of the 2025/26 drilling campaign online in July. We continue to see strong performance from the well, with gross production around 10,000 barrels of oil per day. The drilling rig is now back in Ghana, following a period of scheduled maintenance, and has just spud the second producer well in the campaign -- which is expected online around the end of the year. Through drilling efficiencies, the partnership has increased the number of wells in the '26 drilling campaign from 4 to 5, while staying within the original budget, which I'll talk more about shortly. On GTA, production has continued to ramp up with the partnership, lifting 13.5 gross LNG cargos through the end of October, along with the first condensate cargo -- a new source of revenue for the project. By the end of the year, we're targeting production to increase to the FLNG nameplate capacity of 2.7 million tonnes per annum. In the Gulf of America, production remains consistently strong, and we continue to progress future developments, such as Tiberius and Gettysburg. Finally, in Equatorial Guinea, production is set to increase with the partnership installing repaired subsea pumps at Tiberius, with the first pump complete, the second in country and the third due to be delivered in the first quarter of 2026. We're pleased to see production near record highs for the company with further near-term growth expected quarterly through 2026, as we push GTA towards nameplate capacity and bring on additional wells at Jubilee. Turning to costs, we're focused on three areas and making good progress across all. First, on CapEx. CapEx continues to fall, and we now expect CapEx for the year to be below our $350 million forecast, an absolute reduction year-on-year of around $500 million. Second, on overhead, we remain on track to deliver the $25 million targeted savings by the end of the year with the full benefit being seen in 2026 and beyond. Third, on operating costs, they're coming down across all of our businesses. As discussed last quarter, the biggest opportunity for additional OpEx reduction going forward is on GTA, where we're seeing unit cost improve as production ramps up and costs come down. We're targeting the refinancing of the GTA FPSO by year-end and are working with the operator to implement a lower cost operating model, which should further drive down costs across the project. Finally, the balance sheet, where we've done a lot in recent weeks. On liquidity, we've taken important steps to address our upcoming debt maturities through the $250 million term loan from Shell, with the proceeds being used to repay the outstanding 2026 bond maturities. On the RBL, we successfully completed the semi-annual re-determination in September, and passed the maturity test for the 2027 bonds at the same time. We also added more hedges for 2026 during the period. Neal will talk about all of this in more detail later. But in summary, we're making good progress against our financial objectives. The combination of rising production, lowering costs and lack of near-term maturities, gives us the resilience to weather a period of volatility. I remain confident that we have a unique, world-class portfolio of assets, and we remain focused on maximizing long-term value for our shareholders. Turning to Slide 4, which looks at operations for the quarter. Starting with Ghana, total net production was around 31,300 barrels of oil equivalent per day. Jubilee gross oil production in the third quarter was around 62,500 barrels of oil per day, 13% higher quarter-on-quarter, helped by the first new well of the 2025/26 drilling campaign coming online in July. Gross gas production was around 15,000 barrels of oil equivalent per day in the third quarter, sequentially lower due to a period of extended scheduled maintenance of the onshore gas processing plant. At TEN, gross oil production in the quarter was around 16,000 barrels of oil per day. At GTA in Senegal and Mauritania, third quarter net production was around 11,400 barrels of oil equivalent per day, an increase of just over 60% from the previous quarter. The partnership lifted 6.8 gross LNG cargos during the quarter, in line with guidance. We also lifted the first gross condensate cargo early in the fourth quarter. There were some start-up maintenance on 3 of the 4 LNG trains during the third quarter, that slightly curtailed production. But with all trains online, we're now running around 2.6 million tonnes per annum equivalent and on the path to nameplate production this quarter. Work on the last LNG train is planned for this quarter and has been incorporated in our guidance. In the Gulf of America, net production was around 16,600 barrels of oil equivalent per day, in line with guidance, driven by strong performance from Odd Job and Kodiak, and no major storm activity during the quarter. This was offset by some unplanned facility downtime and the abandonment of the Winterfell-4 well, which I'll talk about in more detail in a following slide. On Tiberius, we executed the production handling agreement with Oxy -- our 50-50 partner on the project and also the operator of the Lucius production facility -- which will host the volumes from the development when it comes online. We expect to take FID and farm down our interest to around a third in 2026. Equatorial Guinea net production was around 6,200 barrels of oil per day, down quarter-on-quarter due to the subsea pump issues flagged in May. As I mentioned, we're making good progress on the repair of those pumps with normalized production expected in the first half of 2026. Turning to Slide 5. We talked in depth last quarter about Jubilee and the opportunity to deliver the field's full potential as we return to drilling. As the chart on the slide shows, the first well of the 2025/26 drilling campaign was drilled in the second quarter and came online in July. The well continues to perform in line with expectations, delivering around 10,000 barrels per day of gross oil production. Drilling of the second producer well has commenced and is expected online around the end of the year, and we anticipate it will also be a strong producer. The next 12 months is an important period of activity for the field with a committed drilling program of 5 more wells in 2026. We initially plan to drill 4 producer wells next year but have worked with the partnership to drive a more efficient program that allows for a fifth well, a water injector, to be added in 2026, while maintaining the same budget. The blue dots on the chart show production may be higher through 2026 as the new wells come online. And while this upward trajectory won't be linear as individual wells contribute different volumes, we expect Jubilee production to be materially higher than current levels as we finish the current drilling program in late 2026. With improved water injection and a regular follow-on infill drilling program, we're targeting sustained production at those higher levels. The other important point to note on the chart is the OBN seismic acquisition, which is taking place this quarter. This state-of-the-art imaging technology, that I talked about last quarter, will further enhance our understanding of the subsurface, providing better data on historical fluid movement and help identify more undrilled lobes and unswept oil. This is a step change in imaging technology, which we expect will support optimum well selection in future drilling campaigns, ultimately enhancing resource recovery over the remaining life of the field. With the license extension expected to be completed by year-end, the partnership can now plan on long-term investment in Jubilee, which should drive a material uplift in 2P reserves. All the required documentation of the extension has now been prepared for submission to the government for their approval. Turning to Slide 6. At GTA, we continue to see a lot of positive progress as we work with BP, the national oil companies and the governments to improve profitability. As the green line in the chart shows, production continues to rise with net production of 11,400 barrels of oil equivalent in the quarter. This equates to 6.8 gross LNG cargos during the quarter, in line with guidance. The partial cargo number reflects the cargo that was loaded over the quarter end with the remainder of the cargo recognized in the following quarter. The project has now lifted 13.5 gross cargos through October with 7.0 to 8.5 cargos expected in the fourth quarter. Last month, the first gross condensate cargo was lifted, another important milestone for the project and was priced at a small discount to Brent. Looking ahead, we expect production to continue to rise, targeting the 2.7 million tonne per annum nameplate towards the end of the year. With this higher production level, we see the potential for the cargo count in 2026 to be almost double what we expect to see this year. On costs, the blue bars on the chart show the absolute operating expenses continue to fall. We expect further progress into 2026 with the re-financing of the FPSO and as we work with the operator to implement a lower cost operating model. Through rising production and its focus on costs, we expect unit cost to fall by over 50% next year. That said, we continue to advance Phase 1+ expansion targeting online in 2029, materially increasing the volume from our existing infrastructure. With that growth in production, we expect the unit economics to improve substantially. On CapEx, Neal will talk more about it in the financials, but the working capital outflow in the third quarter was largely related to the crude GTA CapEx post project completion that was due in the third quarter, effectively marking the end of the capital outlay for Phase 1 of the project. Turning to Slide 7. In the Gulf of America, third quarter performance was in line with expectations with continued strong performance from Odd Job and Kodiak, and a lack of storm activity, offset by some unplanned facility downtime and the abandonment of the Winterfell-4 well. As we communicated in this morning's earnings release, Winterfell-4 was abandoned in September by the operator due to challenges encountered during completion operations arising from the collapse of the production casing. Unfortunately, the operator has recently struggled with completion issues. So while we love the resource upside at Winterfell, which contains around 100 million barrels oil equivalent of potential, we plan to focus next year's activity just on restoring production from the Winterfell-3, Winterfell-4 block. This will allow time to better plan and design the future wells to capture the full resource potential of the field. On our development activities, we continue to progress Tiberius with Oxy with an improved lower cost development plan and an executed PHA, which locks in attractive commercial terms; FID and farm-down are planned for next year. We also continue to advance Gettysburg with Shell, which is a discovered resource opportunity we acquired in a previous lease out. We're progressing a single well development that will be tied back to Shell's operated Appomattox platform. That concludes the review of the portfolio, and Neal will now take you through the financials.

Thanks, Andy. Turning now to Slide 8, which looks at the financials for the third quarter in detail. Production was again higher sequentially due to the first new well on Jubilee and GTA ramping up, offset by expected downtime in the Gulf of America and EG, and lower gas volumes in Ghana. Current production is now in the low 70s, with more to come in the fourth quarter as GTA approaches nameplate, and the second producer well on Jubilee is expected online around the end of the year. Operating costs were down almost 40% quarter-on-quarter with improvements across all our business units, reflecting the focus on costs that Andy talked about earlier and also the 10 lifting costs that fell in the second quarter. G&A was also lower, highlighting the progress we are making in reducing overhead. CapEx of $67 million came in lower than guidance and with year-to-date CapEx of just under $240 million, we are firmly on track to close out the year with full year CapEx below our $350 million forecast. Last quarter, I flagged an expected working capital outflow in 3Q, largely associated with the final accrued CapEx on GTA. With Phase 1 now delivered and the CapEx behind us, we don't expect any material capital outflows at GTA for several years. So to summarize, production is growing and approaching record high levels, while CapEx, OpEx and overhead have all fallen quarter-on-quarter, reflecting our efforts to improve the overall cost base of the business and enhance profitability and cash flow generation. Turning to Slide 9. As Andy said in his opening remarks, one of the priorities for the company this year is enhancing the resilience of the balance sheet, and we've made progress in several key areas recently. On liquidity, we announced a full-year senior secured term loan with Shell for up to $250 million with attractive terms for Kosmos. We used the first tranche of the facility to repay $150 million of our 2026 unsecured notes early in the fourth quarter and anticipate using the remainder to repay the outstanding $100 million in the first quarter of 2026. On the RBL facility, we completed the semi-annual redetermination with the borrowing base remaining in excess of the $1.35 billion facility size. Alongside the exercise with our lending banks, we updated the liquidity test for the 2027 bonds, which was successfully passed. Our lenders remain supportive of the company as we complete our project delivery phase, and we appreciate their continued support. With the Shell transaction complete, we have created more space until our nearest maturities as can be seen on the top right chart. We remain proactive in securing additional sources of liquidity that enables us to repay some of our other upcoming maturities. On hedging, we have continued to increase downside protection against near-term commodity price volatility. For the remainder of 2025, we have 2.5 million barrels of oil production hedged with a $62 per barrel floor and a $77 per barrel ceiling. We also took advantage of higher prices in the third quarter to add more hedges for 2026. We now have 8.5 million barrels of oil hedged next year with a floor of $66 and a ceiling of $73 per barrel with more than 50% of oil sales hedged through the first half of 2026. We've talked on today's call about our focus on costs and the chart on the right shows the progress we're making with quarterly CapEx reductions over the last year. As we start to look ahead to next year, the capital program is largely focused on Jubilee drilling, and we are confident we can stay within this year's budget or below to maximize near-term cash generation and reduce leverage. At current prices, backwards leverage remains elevated given the ramp-up in GTA and lower production in Jubilee in the first half of the year. We expect that to improve quickly into 2026 as production and cargo sales increase and the lower first half 2025 EBITDAX is adjusted out of the trailing 12-month leverage calculation. As you will see with our fourth quarter guidance, we remain close to our revised year-end covenant, but are actively working solutions such as the 10 FPSO purchase to remain compliant. So to conclude, we will continue to be proactive in improving our financial position by reducing costs, raising new liquidity to manage our maturity schedule at attractive rates and adding new hedges. While we have more to do, I'm pleased with the progress we have made, and we will continue to focus on delivery of that agenda. With that, I'll hand it back to Andy.

Thanks, Neal. Turning now to Slide 10 to conclude today's presentation. As I stated in my opening remarks, we have 3 clear near-term priorities. We are growing production with current production approaching record highs with more to come through the end of the year and into 2026 with the Jubilee drilling campaign in GTA at nameplate. Longer term, we have an attractive portfolio of growth opportunities across both oil and gas within our existing discovered resource base, both internationally and in the Gulf of America. On costs, we're seeing solid progress across our 3 main areas of focus: CapEx, OpEx and overhead; and continue to work hard on further reductions. Finally, Neal just talked about the work we're doing to protect the balance sheet to ensure we have a sustainable business in a lower price world while retaining the significant opportunities for future upside. We look forward to delivering on these near-term objectives to support long-term value creation for our investors. Thank you. And I'd now like to turn the call over to the operator to open the session for questions.

[Operator Instructions] Our first questions come from the line of Matthew Smith with Bank of America.

Perhaps a couple. Could I first start with the reference to the 10 FPSO and the sale and repurchase agreement that you're finalizing. I mean, could you give us any sort of further details on the financial implications here? And also, just remind us on the timing for that lease finishing, please? I mean that would be the first one. Then perhaps the second one, just sort of taking a step back, I guess, a million-dollar question, production sort of finally now ticking higher costs coming down, as you've alluded to. Could you give us a bit of a sense of the cash flows and perhaps the deleveraging that you might expect for 2026?

Yes. Sure, Matt. This is Neal. I'll take those. So if we start on TEN, again, one of the themes we talked about today is sort of reducing the cost across the business. When we look at TEN specifically, it's been high operating costs at the field. A large portion of that is because of the lease. The lease makes up more than 60% of the operating cost at TEN. And so it's been naturally an area for us in the partnership to focus on how do we get that cost down. And so we've been working the purchase option together with the rest of the partnership and the FPSO owner to get that concluded here in the fourth quarter. In terms of specific details on consideration and things, we can't disclose those terms until it's signed. But what I can tell you is what we're trying to do, what we've agreed to is sort of no additional payments in terms of what we're paying for the lease until a sort of closeout payment in 2027. And that payment would be basically a reduced buyout payment for the FPSO. And it would be done on very attractive terms with paybacks similar to what we've seen on M&A transactions like Oxy, Ghana, et cetera, that we've looked at. And so no additional cash up front. We serve out the lease until '27. We have a discounted purchase option at that point, which lowers the operating cost and allows us to get access to the extended life of the field and additional sort of upside and opportunities in the future. And so again, it's a good transaction. We're happy to see it progressing and hope to see more news on that here before the end of the fourth quarter. On your second question, just in terms of cash generation, you're absolutely right. We're sort of getting to that point to where production quarter-on-quarter, we can see it increasing and costs across the business are coming down. In terms of where we get to in terms of free cash flow into '26 and beyond, I don't think it's very different in terms of what we've said. We've talked about a company that can breakeven in the mid-$50 per barrel range across all of the costs and then how much excess free cash flow we generate will really be a function of oil prices beyond that. And what we've tried to do is remain proactive on the hedging side to ensure that there Is some price floors at rates ahead of that, that would ensure that we're generating some free cash flow into '26 and then have the optionality in the portfolio for the future. So again, I think directionally, everything is headed the right way across both the production side and the cost side, which you'll see progress both in the 4Q and sequentially into subsequent quarters into '26.

Our next questions come from the line of Bob Brackett with Bernstein Research.

I'd like to talk a little bit about GTA OpEx. You've disclosed a little more this quarter. It looks as if, if I got my math right, running around $60 a barrel, and you talking about taking half of that roughly away. Is that the right way to think about it, getting towards $30 of OpEx?

Yes. So again, I think 2025 is a tricky year to baseline off of, Bob. But if when you look at sort of the quarterly OpEx, we're at $70 million in 2Q, $60 million in 3Q, and we're expecting at the midpoint of guidance about $50 million per quarter net to Kosmos in 4Q. And beyond that, we see upside or downside there in terms of being able to run at a slightly lower operating cost into '26. I'd say today, we're closer to -- and again, we're referencing in gas terms, but closer to a $6 per million-ish breakeven on just where we are from a production perspective with the goal to get that a bit lower.

A follow-up -- any lessons learned on Winterfell? Is there a common theme to some of the challenges? Or is it too early to know?

Yes, Bob, I'll take that. I think the first thing to say these are operational issues, not reservoir issues, yes. So we've had 2 mishaps. The first was placing the screen in the horizontal wasn't fully packed off and therefore, we had the screen collapse. So that's one issue. I think the issue of the casing collapse sort of on exit itself, actually, is a little early to come to a final conclusion on the root cause. But what it does when you step back from it is we need to be very, very rigorous now about the future operations. We are, as Kosmos focused on a single activity in 2026, which will be coming back to the Winterfell-3 fault block, probably re-using the wellbore to recomplete the well, but it will be a very simple completion. And I think if you were to just go to a very high-level view of it, I think, a lesson learned is to "keep it simple", make sure you've got rigorous planning and then you execute. So I think there isn't anything new in that, but I think it's something that we need to come back to.

Our next questions come from the line of Charles Meade with Johnson Rice.

Andy, on Slide 5, thank you for all this detail on Jubilee. But I want to ask a question about what's going to drive 2 cargos versus 3 cargos from Ghana in 4Q. Is the big variable, just the performance or how well this J-72 well holds up, or is there a 10 cargo that may or may not fall in 4Q? Can you give us a sense of what the drivers are there?

No, Charles, it's just really just around, this is a year-end cargo, so it's a timing issue. And ultimately, the timing of that will be dictated by performance. It's sort of holding flat at the moment where we can sort of see a relatively flat profile in Jubilee as we end the year. But it's going to be just literally around the timing effects of that on a year-end cargo.

Great. And then another cargo question, but from GTA, the condensate cargo that you mentioned you sold, how does that fit in your guidance? And how is that going to appear when you report 4Q?

Right. I'll let Neal handle the detail of that, Charles.

Yes. And it's a bit tricky, because you don't get them all the time. There is probably lifting on a gross basis out of the field, maybe quarterly, but this is the first one for the partnership until we split it evenly. Again, the thinking going forward is they'll all be allocated on a entitlement basis going forward. And so again, I think between us and the NOCs potentially lifting every one out of or 2 out of every 5 condensate cargos. So there'll be a bit regular, Charles. But there will be, again, a nice source of additional income for the partnership.

So if I understand you correctly, Neal, you're taking turns the way you are at Ghana. And so even though you've lifted this first cargo to someone else's cargo, and it's not going to have no financial impact on Kosmos for 4Q. Is that right?

Yes. This one, we listed altogether. I'm saying going forward. So we'll get our pro rata piece of that cash flow in 4Q. Going forward, we'll list it like, as you mentioned, which is sort of taking turns between us and the NSCs.

Our next questions come from the line of Neil Mehta with Goldman Sachs.

There's obviously a lot of focus on the balance sheet and credit hasn't traded very well here because of the macro, but also because of some of the challenges you guys talked about. So maybe you could just take some time for investors who are worried about the balance sheet to talk about how you are feeling about liquidity, why you have confidence? What are you doing to mitigate some of the risks and spell it out into detail?

I'll get Neal to talk through it. But I think the first point actually to make is sort of how much progress we've sort of made actually this quarter. Neal will talk you through the term loan, the RBL redetermination. That's allowed us to do with the most immediate issue, which is the '26 bond maturities. But then thereafter, what are the steps we're going to take to address the upcoming maturities beyond that. So I think it is a real growth focus for the company, and it's one where I believe that we're genuinely making the right progress at the right pace. But Neal, just the details?

Yes. And just like Andy said, I think, we continue to be proactive in terms of getting in front of the refinancing issues. The Shell term loan was important to get to early repay the '26s. We've gotten through the redetermination liquidity test that people have some questions around. So hopefully, we have addressed some concerns on that side. And then now we're being proactive around the '27s and looking at, as I mentioned, secured debt options, potentially at the MS level to early attack clear the maturities and create a bit of runway, so that we can focus on with the near-term volatility in the oil price. We've created a lower cost company without any debt maturities, we can use all the free cash flow to repay debt on the revolver and then create more financial resilience through that process. So again, I think, we're doing all the things we said we would. We're going in a step-by-step fashion and continue to look for cost-effective ways for us to get ahead of issues, while we're finishing out the project delivery phase. And again, like I said, I think, the most important thing for us as well as the creditors and the equity holders is we're seeing the benefit of rising production coming through as well as the lower of the overall cost structure. So again, I think we're doing the right things in the business will continue to be proactive around securing the financial resilience of the company as we go through sort of a bit of a wobble in the macro.

Yes. What I'd add, Neil, is in addition to looking at secured debt against the GTA asset, I think, we're also looking at divestments of non-core assets. We're through the build phase, we have some very strong assets, both in Ghana, in MS, Gulf of Mexico. So what are the options we have now to sort of high grade the portfolio and use that as an additional source of debt reduction. So I think that's another area where we're being proactive. So I think there are 2 bigger agenda items that Neal is working on both secured debt against MS and the non-core assets.

Then the follow-up is just -- can you talk about the upfront investment required for the GTA expansion? And how do you think about the differences in leaps rates for a 5 MTPA floating LNG facility versus the Golar facility you had previously?

Yes. Thanks, Neil. I think it's sort of maybe that is an important question. I think it would be good to give you a little bit of detail. I'm fresh back from a meeting where I think last week in Paris, where we spent a lot of time with the NOCs and governments of Mauritania and Senegal sort of thinking through the future needs. And it's clear in both countries, but in particular, in Senegal, the need for additional near-term domestic gas. So I think that we see the next phase, the Phase 1+ expansion actually targeting the domestic market. I think we're sort of almost ambivalent to the pricing there. We were sort of looking at pricing that would be equivalent to the FOB of the LNG without the liquefaction cost. So ultimately, it's a win-win for everybody at that point. The government gets a source of gas, which is very competitively priced and we can secure the expansion of Phase 1+ without having to go through complicated redesign of the facilities. So I think that's the way to think about it, Neal. I think the other thing I'd add to you on the cost side is that actually, the FPSO and the current well stock can supply around 200 million standard cubic feet of additional gas without any investment with 0 investment. And that means that from the government's perspective, they could get domestic gas earlier. And they need to build out the infrastructure to do that. There's a pipeline system being built in Senegal to get access to the power stations, the power stations are being both new build and modifications to gas burning. And their view would be is that they could probably accelerate their demand to pull gas earlier than the '29 date that we talked about. So actually, one of the things that we talked about in Paris was getting on with an early negotiation of a gas sales agreement. So I think if you think about it, there's sort of 200 that you can get at 0 cost today, that's the way to think about it, then there's another 100 that you would get if you debottleneck the FPSO. And that is just debottlenecking. That is small modifications to the gas system to give you that extra 100. So I think the great thing about GTA is you can expand it now at very, very low costs. So there is no additional cost to go in other than the FPSO debottlenecking. And then at some point, you will need additional wells, but that's sometime in the future. So it is about an aligned agenda, I think, with both how do you get the most out of the infrastructure with the least amount of capital going in and then how do you get the most benefit actually for the host countries and build a true win-win. So that for me is the way to think about the project, Neil, rather than -- I think Phase 2 and Phase 3 can be more biased towards LNG, but I think, that initial sort of expansion as we call it Phase 1+ of the existing facilities being more targeted to the domestic gas. Now there is some debottlenecking you can do on the Gimi as well, to move it beyond the 2.7 nameplate. So I think there's an increment of LNG to come there. And so, when you think about it, there Is a piece of it goes to that increment of the Gimi, but it's not 5 million tonnes. It's an increment on the Gimi. And then there Is the residual amount that would go to domestic gas. So all in all, this essentially comes at very, very low CapEx.

Our next questions come from the line of [ Christopher Bake ] with Clarksons.

I have three questions today if I may. So the first is on Jubilee performance. First of all, could you briefly touch upon the underlying decline rates at Jubilee right now? And what exit rate should we expect from Jubilee in 2025? The second question is related to CapEx. CapEx came in below expectations this quarter and full year guidance is now below $350 million. This primarily driven by timing and deferrals? Or is it real cost savings? And in addition to that, related to the FPSO lease refinancing for GTA, what kind of cost savings could be realized once completed? I think we can start with these two.

There's a lot there, Chris. I'll do the first one on Jubilee and then probably I'll hand over to Neal. Yes, on Jubilee, I think, the way to think about it, Chris, is this and how to keep it sort of simple but straightforward. What I would say, surfing around sort of 62,000, 63,000 barrels of oil per day today. We've got a new well coming on we just started drilling, by the way. We're drilling the 26 in section as we speak. And pleased to get back to drilling and sort of actually getting back on the timeline that we targeted. So we expect that well to be on at the end of the year. And so you're going to exit at sort of around sort of 70,000 barrels of oil per day on Jubilee. So as you go to 2026, the question is, of course, well, what's going to happen? And what's your view of the future? We've got 4 more producers to drill. We've always talked about them doing between 5,000 and 10,000 barrels a day. So if you sort of say, okay, 7,500 or something on average, if you add it up in a simplistic sense, that gets you to around 100,000 barrels a day. Then you got to put on the decline rate. So let's say, you put on decline rate of 20%, which is both on the new wells, which is probably a little high on aggregate, if you apply that 20%, then it brings you down to the 80s. And that's the rate we'd anticipate getting to as we go through the year. So I think we've got a clear path going forward. We're clear about the well selection. I'd say that the producers where we're targeting in the main part of the field, they're targeting areas where we've got good pressure support. Challenges we've had in the past at the end of the last drilling program we're in Jubilee Southeast area where there is less concentration of injectors. And therefore, I think we had challenges around the connectivity in particular on one well. So you've got to be careful when we talk about decline rates as you've got to think about it, both the 2 dynamics, where you put in the wells, what's the pressure support and also the difference in the -- as you change the well, the production between the new wells and the existing wells here. But I think that's the right way to sort of think about Jubilee. So I think there are things to monitor going forward. First thing, have you started drilling? Yes, we have. The objective then will be to get the well on production around the end of the year, what production rate do we get there and then you start to build it up as you drill the next. So it's 12 producers in '26. And as I said in the remarks, we've actually sort of high-graded the program a bit to optimize it so we can squeeze in a water injector, which is important for the next program all within the original capital budget.

Yes. And with that, Chris, it goes to your second question, which is what are the savings. Again, I think there's a bit from Ghana, which is, as Andy alluded to, is from drilling efficiencies and some lower contract rates for the program in Ghana. And again, that's part of what allows us to squeeze an additional well into '26. And so those are real savings in '25. And then there's part in terms of lower costs in the Gulf in terms of the '25 program in terms of why we think we'll be lower than the $350 million in terms of what we're projecting for this year. So those are real savings, not just deferrals of capital from.

Yes. And maybe the thing I'd add to that is, Chris, is it's a lot of small things that add up. And I think one of the big messages we want to get across, I think, today in the results is we're really managing our cost base rigorously. So every dollar counts, whether it's CapEx, whether it's OpEx, and you can see the momentum on the OpEx side. You can see us continuing to make progress on CapEx. And then how do we sustain that as we go forward into the '26 program. But it's about the rigor and discipline, and I would say, both in Ghana and the Gulf, it's adding up small things that ultimately allow you then to make savings of $10 million to $20 million overall in the year.

Yes. And again, that sort of feeds to your third question as well around sort of the FPSO lease costs and we're spending about $60 million this year, $15 million a quarter on the lease. And the goal would sort of get that into sort of the $40 million to $50 million range. So again, I think there's still some work to be done to figure out where exactly we get an instrument priced, but it would be a material CapEx savings or an OpEx savings as we get that complete.

One last question on GTA, if I may. And I know you touched upon this earlier, but with the Phase 1 nearing nameplate now, how do discussions or evaluation for Phase 1 look like? And what are the key factors for FID timing? And to follow-up on that as well, what upside do you see on Gimi from current nameplate capacity?

Okay. Yes. I don't want to sort of repeat everything I said in answering Neal's question. But if you go back to Phase 1+ your last question about FID timing, the point I'd like to make is that you can get $200 million today of extra gas without spending any money. So no FID required on that, actually, the big driver is you need to get a GSA signed and that was a big action item that came out of the conversation in Paris with the NOCs and the government, in particular, in Senegal is they want to accelerate that. They've got a very strong domestic demand. Those of you who are Senegal watches will know that the President and the Prime Minister have been clear about the importance of getting domestic gas. And therefore, this is a real win-win where you're able to leverage that. So that comes sort of without any extra money. The last 100 does require us to do some work on the FPSO. What we've got to do is do the FEED work to do that. FID is probably within the next 12 months. What happens is that you've got to get the work done in the 2028 turnaround, yes. So you need a lead time to get you to that time period. So when the FPSO has a normal shutdown, that's when you do the work, then that means that the additional $100 million would be available in '29, yes. In terms of the Guinea it can do -- we're targeting getting up to nameplate, and I think we're demonstrating that. So I think the progress we're making really month-on-month, quarter-on-quarter, we will get to that position at the end of this year. Beyond the nameplate, you really have to do some modifications to the Gimi, which is really about better cooling and more power. That are the 2 things that influence LNG plants. And that work is ongoing with Golar at the moment. So I don't want to give you a hard number, Chris, until we get through that work. But it's probably in the range of maybe 10% to 20% depending on where that work comes out. So you can get more out of the Gimi, but the two things you've got to work on -- the power and the cooling. And again, when would you do that, you probably do it at the turnaround time so that you did at the same time as the FPSO work was going on. So I don't think in terms of sort of putting out spreadsheets, I wouldn't include anything until sort of '29 on that.

Our next questions come from the line of Stella Cridge, Barclays.

I wondered if I could just follow-up on the point of looking at secured borrowing on GTA. And could you just say what you think the borrowing capacity of this business may be at the moment? And what sort of structure might be possible given that it has a different profile to the more kind of liquid businesses that you have elsewhere? That would be great.

Yes. So without sort of getting too far ahead of ourselves, we think there's enough capacity there to take care of the '27 bonds from a secured capacity perspective at, like I said, relatively attractive rates. And we're looking for sort of more bond-like solutions for that access. And again, we're pretty dead. We test the options before we look at anything and go live. But I think I feel pretty good about our ability to go do something there at the right time.

Our next questions come from the line of Nikhil Bhat with JPMorgan.

I have a couple. First one, the second quarter report mentioned that your net leverage covenant on the RBS will be raised to 4x as of September 2025, and the quarter end leverage is higher than the threshold. Can I check if Kosmos is under a cure period or the covenant has been waived? Has this affected the March 2026 covenant test as well. There's also a question I had on the liquidity test for the 2027. Does this by any chance need to be redone in March 2026? Or now that you've completed the test in September, there is no more of redoing this test?

Correct, Nikhil. So just to your two questions. So the waiver we got through 4x was for the September test, which uses the June financials on an LTM basis. And so the June financials, we were at 3.8x. We increased it to 4x from the banks. So that gets officially tested as of September 30, not using the September 30 financials. So the September 30 financials don't technically get tested from a leverage covenant perspective. So again, I think we got the waiver in advance of any breach to avoid any issues. The 4.25% is the relevant test at the end of this year, which gets tested using December 31 financials that actually gets tested by the end of March. And that's what I referred to on the call that we're pretty close to that. And we're working some mitigation options to stay to make sure we're compliant with that. But there wouldn't be any test of that covenant until all the way until the end of March from a timing perspective. Does that make sense?

Our next questions come from the line of Mark Wilson with Jefferies.

Most of my questions have been answered already, but I would like to know just to check, a big drilling program now underway at Jubilee and there was the additional ocean bottom seismic that was being taken and reprocessing of other seismic. I just wonder where that is, do you have all that and what it has given you in terms of new knowledge.

There's a lot going on at Jubilee. We've started the current drilling program. As I said in the earlier remarks, we're targeting that at the main field areas where we have very good well control. And therefore, we're drilling low-risk targets. We've used the fast track of the nets for that. So it's an early product but incredibly good when I look back in my days at what a fast track look like to what you're getting today. So in essence, we have been able to leverage that NAS data, which is the 40, therefore, the comparator of the 40 on a 2025 back to 2027. So I think that drilling program is well underpinned by the nature of the targets that we picked, the well control and the ability to leverage the early products of the NAS. Then I think you sort of think through time is to sustain Jubilee production at the elevated levels that we've talked about, you need to be drilling 3 to 4 wells per year. And we've been clear about that. And we have a deep hopper of opportunities that will only get high graded as we start to leverage the full, final product of the NAS. But most importantly, OBN, which ultimately gets you a much better velocity model. And that velocity model, therefore, high grades the quality of that 4D picture, and we think will lead to greater clarity on that high grading of the hopper. All I'd say it's early days, but we've got a really good view now today of new targets that we haven't been able to see before. It's all about identifying un-swept oil, undrilled lobes, correlation of that from the 4D with a much higher uplift in the seismic and ground truthing it with the history match reservoir model gives you a much, much better view of the future. So what I'd say is our view of the long-term potential of the field remains absolutely unchanged. I'd say that sort of 3 months on, having a chance to play with the NAS, we've probably got a stronger view. There is more opportunity rather than less. And then ultimately, it's about now high-grading the next set of wells for a drilling program that we would target starting in '27. So I think that's sort of where we are with the program, Mark. We'll see the results of this '25, '26 program. The first well has gone well, the next well on by the end of the year, you then got 4 more producers and a water injector that will take us through the back end of '26. And then it's about optimizing the next set of wells. The only bit I'd add is that the 40 does help you optimize the water injection patterns as well. So I think that we've talked about voidage replacement. I think we need to be above 100%, we need to be targeting water injection levels above that. We're now at a level today where we're injecting water where we can do that. But then it's about where you put it. And I think the AI-driven reservoir model we've got now is bringing up some new ideas about how you optimize the water injection patterns. So I think all of that is to say a big step-change in technology. The opportunity set is probably larger. And now it's about delivery. And as you rightly sort of pushed at times, you've now got to deliver those 5 producers going forward, and that's our objective.

Our next questions come from the line of Kay Hope with Bank of America.

I just have a quick one. I can see on Slide 11, you say you expect production in the fourth quarter of 66,000 barrels a day to 72,000 barrels a day. But you mentioned in the comments that you're at about 72,000 barrels a day now. I mean is there a reason we should expect that average to be as low as 66,000?

Kay, this is Neal. So we have started off production pretty good in October so far. Again, I'd say there is normally some downtime, both planned and unplanned. We talked a bit about there's one more train in GTA that will be down for a few days within the quarter that stops you from producing at sort of, call it, sort of full rates. And then we have some sort of recurring downtime to the field. So again, I think on a regular basis, we should be doing better than that. But again, we allocate some for sort of unplanned downtime and things to go wrong. But that's just generally how we sort of get into the forecasting process.

Then I know that you flagged the working capital issue on the second quarter call on, I think it was August 5, I'm not sure, but on that call. Should we expect any of that to come back, or alternatively, do you expect to be free cash flow positive for the fourth quarter alone? And for the full year, it may be a bit tough. But what about the fourth quarter on its own?

You are right. We saw some big working capital flags as GTA sort of finished the commissioning phase and went into the operational phase at the end of the second quarter and into the early part of the third quarter. So we flagged that into the third quarter call. We haven't seen any of those into 4Q. Again, working capital is really hard to predict in terms of where we are. And again, I think, Andy mentioned sort of there is a cargo timing piece that sort of moves on one side or the other, which has an impact as well. But again, I think we don't flag. If we see any big working capital, we usually flag it. We don't see any at the moment. And there is no reason to expect that to sort of occur going forward given we were in the project delivery phase before and now we're into more normalized operations. But cargo counts still make a sort of quarterly difference in terms of variation and then some of the cash flows, it will be sort of different. But again, I think with our view today, it's hard. We don't see anything immediately, but it's something we'll have to continue to manage.

You are not telling me that you're going to be free cash flow positive in the fourth quarter?

If you tell me what oil prices are going to be.

Well, we're up to November. We'll cross our fingers.

Yes. What I'd say Kay is look, we've had a strong start to the first month. So obviously, we sit here today, we know what October was like. And we're well within the guidance that you talked about for 4Q. So I think this is about -- you talked about the downside of what would cause you to hit $66. The alternative question would be is what would you have to do to be at the upper end of that range. And that's clearly what we're targeting. So we're targeting to deliver well within the range in 4Q. And all I'd say is we're off to a strong start so far in the quarter.