Kosmos Energy Ltd. Stock

Good day, everyone. Welcome to Kosmos Energy's second quarter 2026 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 second quarter 2026 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 that we note in this presentation in our UK 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 second quarter 2026 results call. I'll begin today's call by reviewing the progress we've made against the 4 2026 goals that we laid out at the start of the year before giving an update on each of our business units. I'll then hand it over to Neal to talk about the financials before I wrap up the closing remarks. We'll then open up the call for Q&A. Starting on slide 3, when we released our full year 2025 results in March, we laid out 4 key objectives for Kosmos in 2026, which is shown on the slide. I'm pleased to say in the first half of the year, we've made excellent progress across all 4.

We've grown production from our core assets, namely Jubilee and GTA, delivered significant absolute and per BOE cost reductions year on year with a specific focus on operating costs. We've delivered a meaningful reduction in net debt already this year and are making good progress towards hitting a 20% reduction in net debt, a target we increased with our first quarter results in May. And we continue to advance our high-quality growth portfolio, particularly in the Gulf of Mexico with minimal capital input. Through these actions, we're delivering a stronger and more valuable Kosmos. A company with high production, lower costs, and lower debt is more resilient to future price volatility with significant upside from our deep hopper of future growth opportunities. I'll now go into more detail as we move through the slides.

Starting with Ghana on slide 4. We've seen a lot of positive progress in Ghana this year with an active drilling campaign that is delivering towards the upper end of our expectations, demonstrating Jubilee's potential. We used a chart on this slide for the last few quarters to highlight the ramp-up in Jubilee production since the start of the current drilling campaign in the second half of 2025. Since we reported first quarter results in May, 2 new producers have come online, J76 and J77. The final producer of the campaign, J50, is the completion of a previously drilled well, is expected to start up in the coming days. With J50 online, we expect Jubilee gross production 90,000 barrels of oil per day.

J76 in particular came in at the top end of our expectations and based on performance so far is the best well we've seen at Jubilee in over a decade. The well is an example of the upside potential of the asset, ensures there is a lot of future value left to play for, particularly as we start to integrate the results of the 2025 OBN seismic into our future well planning. With 7 months of production, we have a robust track record that underpins our full-year guidance for Jubilee, which remains unchanged at 70,000 to 80,000 barrels of oil per day. Performance of the latest wells continues to support the upper end of this range. The important takeaway from the chart at the top of the slide is the correlation between activity and performance. During periods of drilling, high FPSO uptime, and sustained water injection, the field has performed well.

We're therefore working closely with the operator to secure a rig for the '27-'28 drilling campaign for up to 10 wells with the objective of starting in mid-2027. We'll benefit from both the fully processed 4D and fast-track OBN seismic, which will help refine and high-grade future well locations and give the partnership the best opportunity to maximize future reserve recovery. So, in summary, it's an exciting time in Ghana. Jubilee, our highest margin production, is performing strongly at a time of higher oil prices, helping us to deliver our debt reduction targets for the year. And looking forward with the benefit of new technologies, we're working closely with the operator to plan and implement a new technology for the year and progress next year's drilling campaign.

Turning to slide 5. GTA has continued to perform well this year. In the second quarter, gross LNG production was around 2.65 million tons per annum equivalent, in line with our expectations. 9 gross LNG cargoes were lifted during the quarter at the upper end of guidance. For the full year, our guidance of 32 to 36 gross LNG cargoes remains unchanged with 18.5 lifted in the first half of the year. During the second quarter, 1 condensate cargo was jointly lifted by Kosmos and the NOCs, with around 300,000 barrels net to Kosmos. An additional condensate cargo is expected late in the third quarter, which is also expected to be assigned to Kosmos and the NOCs, with around 400,000 barrels net to Kosmos.

Due to the seasonality that we've flagged in the past, daily LNG production is expected to remain slightly lower during the summer months because of the warmer sea and air temperatures. Volumes should then pick up again late in the year as cooler temperatures return. On costs, we remain on track to hit our 50% reduction target for OpEx per MMBtu this year and see scope for further reduction in 2027. On the phase 1 expansion for domestic gas to power, which should materially enhance project returns, there's been good progress on the ground in both Senegal and Mauritania so far this year. In Senegal, the land has now been cleared for the onshore section, the northern segment of the gas pipeline, which will connect GTA to the 250-megawatt Gandon power station being built near St. Louis.

Photographs on the top of the slide show the gathering in China in May to celebrate the completion of the fabrication of the onshore pipeline before it was shipped to Senegal. The pipeline is due to arrive in country in the coming days after taking a longer route than initially planned to avoid the Middle East. In Mauritania, the country just signed a 25-year agreement with a Saudi power company for the development, finance, construction, and operation of a new 230-megawatt gas-fired power plant in Ndiago, which is expected to use gas from the GTA field. These developments in Senegal and Mauritania are important steps for both countries to enhance domestic electricity generation, reduce reliance on imported fuels, and support the country's long-term energy security and industrial development.

Turning to slide 6. Production in the Gulf of Mexico for the second quarter was in line with expectations, with continued solid performance for our operated Odd Job and Kodiak fields. On Winterfell, the #5 well was temporarily abandoned by the operator due to casing issues encountered during drilling. Turning to the growth side of the business, following final investment decision in March, the Tiberius project is making good progress. Last week, we successfully completed a highly competitive farm-down on Tiberius, bringing Navitas into the project as a 33.33% partner. Following the farm-in, Kosmos will remain as operator with a 33.34% interest. Occidental, the owner and operator of the nearby Lucius facility, will have a 33.33% interest.

The farm-in proceeds are a mix of upfront cash, carry for future development CapEx, and future milestone payments. We expect the carry element to cover all of our Tiberius CapEx in 2026 and fund our share of the development through the first half of 2027. Tiberius is a low-cost, high-margin development. We now have an aligned partnership to move it forward, with first oil expected in the second half of 2028. Elsewhere in the Gulf, as previously discussed, we entered into a strategic exploration alliance with Shell earlier in the year. As part of the alliance, we exchanged interests across multiple blocks across the Norphlet play, which houses several material exploration prospects. Shell plans to start drilling the first of these, Trailblazer, in the first quarter of 2027. Trailblazer is targeting around 200 million barrels of oil equivalent gross resource, and Kosmos is designated as a development operator in the event of success. I'll now turn it over to Neal to take you through the financials.

Thanks, Andy. Turning now to slide 7, which looks at the financials for the second quarter in detail. As Andy mentioned, it's been a strong quarter for the company, with production around 12% higher year on year, driven by the new wells coming online at Jubilee and the ramp-up at GTA. Realized prices were higher year on year, reflecting the elevated pricing seen in the second quarter following the war in the Middle East. As flagged last quarter, some of the pricing of our production has a lag impact. So we should also see some benefit of the higher 2Q pricing in the third quarter. On operating costs, we've seen a material reduction in both absolute and unit costs year on year. Absolute operating costs in the second quarter are around 25% lower year on year, consistent with our ongoing efforts to drive down costs across the business.

With the EG disposal, we've now sold our highest cost barrels, so we'd expect absolute operating costs and costs per unit to continue to fall through the second half of the year. The rest of the cost lines for the quarter were in line with guidance, but it's worth highlighting the interest expense reduction, which we expect to continue as we deliver on our debt reduction targets for the year. In terms of guidance for the third quarter and the full year 2026, we have updated the table in the appendix to reflect the Equatorial Guinea sale, which was completed in June. The 2 main line items that have been updated are production and operating costs. On production, the midpoint of the range has been moved down around 2,500 barrels of oil equivalent per day net, taking out the EG barrels for the second half of the year.

The remaining portfolio is on track following the strong performance year to date. With slightly lower production post the EG sale and significantly lower costs, we remain on track to reduce OpEx per barrel by around 35% in 2026. Turning to slide 8, we've had an active first half of the year, carrying out several important initiatives to drive a meaningful reduction in both debt and leverage, clear near-term maturities, and increase liquidity. The successful GTA bond largely addressed our 2027 bond maturity, and we intend to pay the remaining stub with free cash flow. We paid down approximately $420 million of debt through free cash flow, the equity raise, and proceeds from the EG sale, and we ended the quarter with over $500 million of available liquidity.

This progress is recognized by the rating agencies, with both S&P and Fitch upgrading the company to B-, reflecting the work we've done to enhance the balance sheet in the first half of the year. Looking at the second half of the year and the things that remain on our to-do list, we've commenced discussions with the lending banks around amending and extending the RBL, and we expect that process to close during the fourth quarter, targeting a facility size of around $1.2 billion. As we make further progress on the capital structure, we will also look potentially to repay the 2028 notes later in the year. And lastly, we'll continue to take advantage of higher prices to layer in more hedges for 2027. With continued execution, we expect leverage to fall further towards 2x by year-end, a pretty significant turnaround in only 12 months.

So in summary, we've worked hard in the first half of the year to reduce absolute debt and leverage while improving liquidity. There's more to do in the second half, and we are being proactive and methodical to get it all done. With that, I'll hand it back to Andy.

Thanks, Neal. Turning now to slide 9 to conclude today's presentation. As stated in my opening remarks, we have 4 key objectives for 2026: grow production, lower costs, reduce debt, and advance our quality growth portfolio with minimal CapEx in 2026. This slide shows the progress we've achieved year to date against those goals. Production for the first half of 2026 is up 18% versus the same period last year. Absolute operating costs are down 24% in the first half of 2026 versus 2025. We're on track to deliver a reduction in net debt around 50% versus year-end 2025. And we are advancing our growth portfolio with the Tiberius FID and farm-down, continuing progress on GTA expansion, and the exploration alliance with Shell in the Gulf of Mexico.

We're working hard to deliver a stronger, more valuable Kosmos and look forward to delivering on our full-year targets 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.

Thank you. We will now begin the question and answer session. [Operator Instructions] Our first question comes from Charles Meade with Johnson Rice. Your line is open.

Yes, good day to you, Andy, and to the rest of your team there. I'd like to ask about the J76 well, and if you could characterize for us the setting of that well, and I'm thinking along the lines of, you know, is it up-dip above 1 of your previous strong producers in the known fault block, or is it, you know, maybe on the other end of the spectrum, maybe it's up in some fault block that you hadn't been connected to. And I'm really trying to understand what the nature of the remaining opportunity for you is. Maybe not just the nature of the opportunity in the next couple of years in Jubilee for you guys.

Yes, yes, thanks, Charles. Look, you know, clearly J76 has been a very strong well. I think actually 1 of the best wells we've drilled in over a decade. You know, I think ultimately we're in the core part of the field. So when we've used the latest 4D to be able to identify some opportunities that are in that core part of the field that are up-dip and being unswept. So the other interesting thing about 76 is we have actually picked up some deeper horizons as well. So there's a combination of sort of what I would say the core areas of the field we've looked at in the past, plus some deeper opportunity. So I think in total, it sort of demonstrates 2 things. There are significant opportunities in the field where we have oil that has been bypassed by the current drilling program and injection patterns and therefore can provide wells that have both significant resource and the ability to drill a well where you can have a secondary target deeper that introduces additional resource.

And I think it's those 2 elements that are important as we go forward. I think there's significant bypassed oil opportunities, and I think there'll be continuing opportunities to find potentially deeper horizons that we haven't accessed in the past.

Got it. And that's exactly the kind of detail I was looking for. And then a follow-up question on Tiberius. I read or I went through the Navitas press release, and I had a hard time following it, even though it wasn't the Hebrew version. And so I'm wondering if you could, I recognize some of this may be sensitive, I wonder if you could frame up for us how we should think about the value that you achieved for your sell-down of 70% there.

Sure. Thanks for looking at this this morning. I'll pass it over to Neal, who can give you the full translation.

Yes, Charles. Hi. Yes, so if you just take the math simply in terms of what we got for what we've sold, it implies a gross valuation for Tiberius of around $250 million as of January 1st, 2026. And you know, again, we've got sort of a total of a bit under $45 million of consideration in between sort of upfront cash, carry, and milestone payments. And so again, I think a very good result from the team in executing a really good competitive farm-down process, and we're excited that we have the right partnership for the future.

That's exactly the kind of detail I was looking for, Neal. To be clear, that $250 million gross valuation, does that include the future contingent payments?

No, that's, it is a gross value of the asset, so our net, you'd add our net plus the value of the carry, okay?

Okay, thanks.

Great, thanks, Charles. Your next question comes from Bob Brackett with Bernstein Research. Your line is open.

Good morning. Question, a bit of a follow-up, I suppose. Can you talk about the Logan discovery that you all picked up and is now part of this Navitas JV? Maybe what are the volumes in place, and what is the future plan to sort of bring that part of Tiberius into production?

Yes. Thanks, Bob. I'll pass it over to Neal, he's been handling that.

Yes, good morning, Bob. We're still sort of up, we've just got updated seismic over Tiberius. There's a good discovery well that's already on Tiberius that was drilled, I think, 10-plus years ago. And so whether it's in the 10s of millions of barrels of resource, but we do look at it as a potential add-on into the sort of greater Tiberius area. So we're looking at a handful of wells in Tiberius in terms of different fault blocks and ultimately connecting Logan into the system. But yes, so it's a potential well or 2 into that area to add some additional recovery.

Very clear. And a follow-up. I imagine you're frustrated with Winterfell, either by the operator, by the reservoir, by something. Is there recourse there, or do you think you finally tackled some of the challenges there?

Yes, and so just on, again, I think just from a Winterfell basis, yes, I mean, I do think, ultimately, there's a big prize in terms of reserves there. You know, we've drilled a number of wells. There's good pay. But we have been disappointed by the drilling performance on, you know, again, what are relatively routine operations and the additional costs that have been incurred as a result. And so, you know, hence the pause on activity to fully understand sort of what's causing the issues. And, yes, again, there hasn't been a material daily impact to sort of production, but we do want to make sure sort of those drilling issues are resolved before any more capital gets spent on the project. So, yes, it has been frustrating, but it's something the team's working hard on with the operator to make sure gets comprehensively resolved.

Very clear. Thank you.

Thanks, Bob. Your next question comes from the line of Neil Mehta with Goldman Sachs. Your line is open.

Yes, good morning, team, Andy, Neal. I just want to first congratulate you guys on the progress on your net debt reduction, 15% since year-end 2025. And so, Neal, maybe the first question is for you on slide 8. Do you want to walk what your plan is through the balance of the year to hit 20% or above?

Yes, Neil. Hey, good morning, and thank you. Yes, so it has been a lot of good work by the entire team to deliver a good first half in terms of almost $500 million of debt reduction in the first half of the year. It's a bit under $600 million. We're at 2.5 and change. And then the goal would be to get closer to 2.4 by the end of the year. And, again, I think from where we are from a production and cost perspective, we feel pretty good about the ability to get there even in a sort of lower commodity price environment. And, you know, that'll be the big variable that sort of exists between now and the end of the year. But yes, the balance of that difference, which is about, call it $150 million, is expected to be generated from free cash flow, right? And so, again, I think we've delivered free cash flow the last 2 quarters. The expectation is to do that as well, and that'll get us to sort of that net debt number of around 20% reduction year on year.

And then in addition to that, again, I think we remain proactive in terms of just managing the maturity schedule. So we've tackled the '26s first earlier this year, we tackled the '27s thereafter, we're working on the RBL at the moment, and then we'll tackle the '28s. And once we're sort of done with that, we have plus, call it 3 years plus of runway to without sort of worrying about sort of the debt in front of us. And we'll continue to focus on free cash flow and managing that level down beyond the 20% reduction in '26. And so again, I think, you know, strong financial performance is driven by sort of good operational backbone at the beginning. And so, again, the focus on doing both things simultaneously to get to the right result.

Yes, thanks, Neal. And then just a follow-up is on the unit cost at phase 1. Again, year over year, there should be significant reductions in OpEx as we work through startup costs and you get towards the end of the year, Mauritania and Senegal scale, but just talk about where you stand in terms of the reduction in cost and then how does phase 1 plus fit into the equation? Like what could the cost trend down to on a multi-year basis as we try to dial in that number?

Yes, I'll pick that up, Neil. Yes, you're correct. Clearly, we're getting the effect of 2 dynamics this year. We clearly pushed volume up on GTA and the performance the first half of the year has been very strong. You know, we were targeting, you know, 32 to 36 cargoes with the weighting heavily in the front end of the year. So, you know, the overall production level, you know, clearly strong. That's obviously helped in terms of managing the unit costs, and we've also had the benefit of some of the final commissioning costs coming out.

And then I think there's still improvement to make in the cost base in '27 with different operating models that we're discussing with BP. And then you have the additional impact of increasing production. As we said in the past, you can add at least another 50% to the FPSO, the current throughput that's being supplied to the FLNG vessel for domestic gas. So that additional volume is going to have a significant impact on the unit cost because it comes with no additional cost. So I think, as we said in the remarks, the big agenda now, and it's an agenda that's deeply aligned with both countries in Mauritania and Senegal, is to push on with the supply of the domestic gas. We saw the progress, I think some pictures in the deck that showed the progress in Senegal in terms of getting pipe in the ground, connection to the first offtake, which would be the Gandon power station, and then in Mauritania the work that they've done with a Saudi developer for their power station.

So, you know, that volumetric effect just simply then, you know, impacts the per unit costs. So I think we've got continuing growth in margin in GTA through that phase 1 export, and I think we're aligned with the governments in both countries in terms of how we deliver that.

Great, thanks, Neil. Your next question comes from the line of David Round with Stifel. The line is open.

Great, thanks, guys. Jubilee, I mean the production side there has been really good. I guess I wouldn't mind if you could just touch on, please, the voidage replacement and whether previous decline assumptions may change if that's been going well.

Yes, no, thanks, David. I think it's a really good question. Clearly, our focus through the first half of the year has been on the drilling program. And I think we've seen the impact of new data, the ability to influence then the sort of selection of good wells. And I think that selection then with good operator drilling performance has led to the current levels that we're experiencing. So I think big check in the box there. I think when it comes to water injection, I'd say this is an area where there is an opportunity to do better. We did well in the first quarter, you know, a voidage replacement, you know, around 130%, which is sort of what you need.

That's what sort of world-class performance looks like. It hasn't been as strong in 2Q. It's been around about half that level, actually around 65%. Some of it was scheduled maintenance. Some of it was availability of the water injection pumps. So we're working really hard with the operator now to focus on that issue. And it's just an operational issue. It's not a reservoir issue. It's just simply about keeping the water injection pumps up and with high availability. So we've had high availability on the oil side. We need to sort of match that on the water side. So that's the focus in 3Q and 4Q and then in the beginning of next year as we take a time out on the drilling program and then restart, planned restart is around the middle of the year. We're making good progress on the rig contract. So I think we're clear about what we need to do and the back end of the year will be a strong focus on the water injection.

Okay, thanks, Andy. In terms of the forward program and the program you're looking at next year, I mean is it too early to think about how many of those might be injectors versus producers?

Yes, yes, it's a little early, David. You know, without being overly simplistic, I think we've, so let's say in the core of the field, we've got pretty good injection support. I'm talking more broadly now. And the issue is not so much about needing new injection, probably more around getting the water in the ground, actually. As we move out of some of the areas where the well density isn't as high, let's say, you know, as you move back into the eastern side of the field, JSE, for instance, it will be more about pairing injectors and producers. So, you know, if you sort of haze through, you know, sort of look through all of that, you know, there'll be a bias. I think the bias is still going to be more towards injection.

So more towards producers over injectors. But actually, the injection well, we're drilling at the tail end of this program, that's actually an injector that will provide some support for this year, but actually it's to support a future producer. So you're sort of getting the right balance there between injection and production, but I think the bias will still be that it will be more heavily weighted to producers.

Okay, that's really helpful. Thanks, Andy.

Great, thanks, Dave. Your next question comes from the line of Mark Wilson with Jefferies. The line is open.

All right. Thank you. I'd like to ask a question about the U.S. Gulf if I may start there. Great to see Tiberius farm-in completed. 1-well tie-back initially, you speak to 100 million barrels there, reminds me of Winterfell. I imagine that 100 million is a kind of an area. So I'm just wondering what you're targeting with that 1-well tie-back in terms of recoverable reserves at Tiberius. And then same sort of question for Trailblazer, great exploration opportunity, just wondering what Kosmos' net share would be of that 200 million target. That's my first question. Thank you.

Yes, hey, Mark, good morning. Yes, so with Tiberius, yes, I mean, the 100 million barrels is sort of within Tiberius, and then Logan would be sort of additional beyond that. But there are sort of, call it 3 fault blocks in Tiberius, which we've penetrated 1. But the first well is targeting around, call it 40 million barrels recovered. And again, we've talked about sort of $10 F&D, which is sort of a $400-ish million slightly gross development cost all in. So that sort of squares. But once the infrastructure is in place, that includes sort of the tie-in infrastructure. So once that's in place, then we can add the additional wells and get much production impact, much more. And so we'll sort of phase that on post-first oil.

If I sort of take that to Trailblazer, it's about 200 million barrels gross in terms of prospectivity. And we own about a third, a little under a third, 30% of the projects that are next to us, a little under around 60 million barrels gross. And so again, pretty material prospect for us. And again, I think you'd expect it to be a multi-well development all in, if successful. But in a similar sort of Kosmos fashion, the idea would be keep the first well on as a development well, bring that online to put it in infrastructure, and then bring in additional producers once it's tied back.

That's really appreciated, Neal. Thank you for that. If I could move on to GTA, because excellent to see the progress pipe on its way, goodness me, for the domestic power. I'm just wondering what flexibility you have on the pricing for that, or if that's part of the actual license agreements, that'd be the first point. And then secondly, a lot going on at BP. So just wondering if there's any discussions over further phases at GTA. Thank you.

Yes, so the agreements we have in place, we get the equivalent netback of the FOB less the LNG processing fee. Because clearly you're not converting it into LNG, you're just delivering it as domestic gas. So it's the FOB equivalent for domestic supply. And that's been agreed through for phase 1 in terms of the gas price. So, you know, the point about that is the additional volume comes with the same economics as the LNG export. And then, yes, look, there's a lot going on in BP as you say. So, you know, obviously I don't have any insight into that or can't comment on what their sort of corporate objectives are, whether GTA is core or non-core. I think for us the most important thing at the moment is to sort of focus on the development of the asset and we continue to work hard with BP on that and aligned with states around the delivery of the domestic gas. As you say, there's real progress being made.

Okay, and obviously the main one is the net debt coming down, which is, yes, great to see, as has been commented by others, and RBL refinance in the second quarter. And Neal, you also mentioned looking to, I think you said, repay the 2028 bonds, that's the $400 million. That's what I understood correct, or is that a refinance of those targeted this year?

Yes, no, good question, Mark. Yes, so, you know, again, I think, you know, like I was trying to refer to earlier, but this year we've tried to be really sort of methodical around how we sort of address the financing issues in the maturity schedule. And like I said, we've gone through the '26s and '27s earlier this year, we paid the '27s with the Nordic bond, are working on the RBL at the moment, which is, you know, matures in '29 but starts amortizing in '27. And then once that's out of the way, the next maturity for us to address is the '28s. And I think it's been good to see the yields on the bond return closer to normal. Maybe we'd expect as we continue to address the financial risk, get the debt down, we'll see a continued improvement in yields. And so it's something we're continuing to evaluate in terms of whether it's a repayment or a, from sort of from an opportunistic repurchase or just potentially refinancing those later in the year. So again, it's something on the agenda. And as the market and the yields evolve, we'll continue to keep an eye on that.

Okay, understood. I'll hand it over. Thanks for the questions.

Great. Thanks, Mark. Appreciate it. Your next question comes from the line of [ Christopher Bakhos ] with Clarkson Securities. Your line is open.

[ Christopher Bakhos ] from Clarkson Securities. So firstly, congratulations on another very strong quarter. I mean, operational execution continues to impress. So that's great to see. My first question is related to Jubilee, and especially with the Jubilee production now tracking at or above the 90,000 barrels per day. How should we think about the sustainable production potential of Jubilee over the next quarters and could this potentially influence the scope or pace of the 2027-2028 drilling campaign? So that's my first question.

Yes, no, Christopher, that's a good question. When you look at Jubilee, I think we know, if you look at the '25-'26 program, it's been a very successful program. It's certainly been supported by the new 4D, and I think that's enabled us to see a lot more opportunity in the field. I think it is actually worth commenting on if you look at that overall program, with payback of less than 6 months. So you want to get back to drilling as soon as possible. There are some logistical issues on that in terms of ordering, you know, long-lead equipment, wellheads, etc.

But we're working with the operator to make sure we get back to drilling as soon as practicable. And, you know, that date is around the middle of next year and we're pushing maybe to get there a little earlier, but I think that's sort of the current target. And then it's a fulsome program. Our objective is to drill up to 10 wells. Not only will we have the fully processed 4D at that point, but we'll also have early product from the OBN, which I think is going to be another step change in our ability to properly describe the opportunity set. You know, potentially some of the things that have been harder to image that are deeper. So I think that, you know, for us, we see ongoing opportunity and as we've said, I think consistently over probably the last to do sort of 3 things to deliver that potential. You've got to get back to regular drilling, which I've talked about, you have to deliver high FPSO uptime, which the operator has done so far this year, and you have to get the water injection operating so you get water in the ground. So as we look forward, we will see some decline, clearly. There'll be a little bit of mitigation from the last water injection well. That's primarily to support a future well in '27. So we will see natural decline from the end of the program, which finishes at the end of this quarter through the fourth quarter, first quarter, second quarter, and then back to drilling.

Thank you very much. And also staying on Jubilee and the full year guidance, you have highlighted that production is trending toward the upper end of guidance and you also had another well coming online. So assuming current operational performance continues, should we think about ending the year toward the upper end of the production range? Would that potentially allow you to exceed your target of 20% net debt reduction for...

Again, you know, really, you know, good question. And that's obviously our objective, yes. We're working again, it's about eyes-down focus on the operational delivery, it's about picking the right wells, it's about then drilling them, it's about the delivery then of the uptime, and I think the end area that's really important now is water injection availability. But I think when you look at the overall suite of options within Kosmos, it's obviously, you know, GTA has been trending to the upper end of its guidance in terms of the number of cargoes, you know, despite, you know, Winterfell #5, we've had strong performance in the Gulf of Mexico, particularly from Kodiak and Odd Job.

So you put all that together, Christopher, and yes, you know, are we confident we're going to hit our numbers? So it's about a managed outlook across all of those production opportunities. And then finally, you know, it's about managing the cost base. We haven't talked about that much on the call. But, you know, this is a significant reduction in costs we've achieved in the first half of the year, delivering the portfolio optimizations with the EG sale, the TEN FPSO repurchase, those are structural changes that are enduring. So that together with rigorous capital management, and again, I think we've talked about the Tiberius farm-down. But then that, again, allows us to manage the CapEx through the back end of '26 and into '27. So in combination, you know, the 3 things, you know, production performance, cost reduction and capital management then underpin that debt reduction target.

Thank you very much. Yes, you have briefly mentioned it already, but you are in ongoing discussions with the lending banks and have now also commenced discussions and you expect the amended RBL to be completed during the fourth quarter. Could you elaborate a bit on how those discussions are progressing? And once the RBL is completed, should investors expect you to kind of turn your attention towards addressing the 2028s? Or are those kind of two processes going in parallel?

Yes, I think that's the right way to think about it, Christopher, in terms of just the series of events. Yes, so we've kicked off the RBL process. And just for those of you who haven't been, this is the fifth time we get through an extension process on the RBL with a lot of the same banks who've been in there since I joined the company in 2011. So, yes, it's a well sort of established program, or process. We've started exchanging term sheets in terms of what that looks like, so we need to sort of finalize that. And, you know, clearly on the back of improved Jubilee performance, in a constructive commodity price environment, we're well-placed to sort of execute that here relatively quickly. But yes, I mean, I think as we get that complete, then, like I said, the next maturity on the list is the '28s. And that gives us a bit over 3 years of runway without any maturities to manage.

Thanks, Neal, for taking my questions.

Great, thanks, Christopher. [Operator Instructions] Your next question comes from Stella Cridge with Barclays. Your line is open.

Hi there, everyone, and many thanks for all the updates. Sorry to add a couple more questions on the refinancing side. Just wondered if you're still targeting 2032 and '33 as potential maturity dates of the new RBL. And I was just wondering regarding the liquidity test that you would usually be tested on the bonds. How does that fit into the next few months in the RBL negotiation? Do you get a waiver or is that just kind of rolled into the whole process? That would be great, thanks.

Yes, so, yes, I mean, the chart on, I forgot what slide it is. Slide 8. Slide 8 is clearly illustrative, but in line with what we're working live. And so the idea is to get sort of the final maturity beyond the existing bonds and again we normally do it in a sort of 6, 7-year timeframe, so that's kind of when the final maturity base would be, but it generally starts amortizing after 3 years. So the shape of the RBL won't be dissimilar to the shape that it's always in. And that essentially puts a sort of refinancing plan in sort of 3 years down the line to force another extension. So that's sort of, you know, again, business as usual from that perspective.

And then, you know, same thing with the, you know, your question around sort of the liquidity test along with sort of redetermination. And so essentially we'll sort of all boil that in up into the refinancing. And so, yes, we probably won't have a, yes, a sort of formal full redetermination because generally, you know, again, I'm going a little detail, but you know, the RBL is always limited by the loan life and so as you kick the loan life you have full access to the facility which keeps liquidity and, you know, keeps all liquidity available to the company. So we'll do those sort of contemporaneously with the refi.

That's great. Many thanks for that. And if you don't mind me asking on Tiberius, could you just remind us how much gross production would come from that first well? And I noticed you also mentioned a potential second well. It would be great to hear about that as well.

Yes, and yes, again, every well will be different, but the expectation is, yes, again, I think a good modeling assumption is around 10,000 barrels a day gross per well. And again, we have up to 30,000 barrels a day of capacity at Lucius, the facility. And so again, the ability to accommodate multiple wells over time.

Many thanks for that.

Great, thanks, Stella. Since there are no further questions at this time, I would like to bring the call to a close. Thanks to everyone joining today. You may now disconnect your lines at this time.

Good day, everyone. Welcome to Kosmos Energy First Quarter 2026 Conference Call. As a reminder, today's call is being recorded at this time. I would like to turn the call over to Jamie Buckland, Vice President of Investor Relations.

Thank you, operator, and thanks to everyone for joining us today. This morning, we issued our first quarter 2026 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 Andrew 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.

And at this time, I will turn the call over to Andrew.

Thanks, Jamie, and good morning and afternoon to everyone. Thank you for joining us today for our first quarter 2026 results call. I'll start today's call by reviewing progress against the four goals for 2026 that we laid out with our full year results in March.

I'd then like to spend some time talking about the current market dynamics and how Kosmos is uniquely positioned to benefit by being priced of premium benchmarks before focusing on each business unit and the operational progress we've made year-to-date.

I'll then hand over to Neal to talk about the financials before I wrap up with closing remarks. We'll then open up the call for Q&A.

Starting on Slide 3. Two months ago, we released our full year 2025 results, and I focused on four key objectives for Kosmos in 2026, which is shown on the slide. This year, we are targeting production growth from our core assets, continued progress in cost reduction with a particular focus this year on operating costs having made significant reductions in CapEx and overhead last year, meaningful net debt reduction, and advancement of our high-quality growth portfolio with minimal CapEx this year.

I'm pleased to say we're making excellent progress against all these goals. Compared to the same quarter last year, production is up around 25% and absolute operating costs are down around 22%. In addition, we've reduced net debt by around 7% from year-end 2025. I'll go into more detail on each as we move through the slides.

Starting with production on Slide 4. With the ramp-up of GTA and Jubilee production, we posted record quarterly production in the first quarter, as can be seen on the top chart on the slide. This record production has come at a time when we've seen record high pricing and also record high differentials.

The dark blue line on the left axis of the bottom chart shows Dated Brent pricing year-to-date. Dated Brent is the benchmark used for pricing our Ghana cargoes. In times of market tightness, Dated Brent can trade at a premium to Brent futures, reflecting the strong near-term demand for the barrels in the physical market. Dated Brent hit an all-time record high in early April and has continued to trade at a premium to Brent futures.

Also worth noting are the differentials we see on those barrels. The barrels we sell typically include a differential, which is either a discount or premium to the benchmark such as Dated Brent. That discount or premium depends on factors such as crude quality, location and regional market conditions. The red line on the chart shows an illustrative differential for West African crude year-to-date.

Through January and February, those differentials were slightly negative but started to grow through March into April as the Middle East conflict continued. While the data on the chart is illustrative, we've seen those differentials rise to a meaningful premium through this period of market tightness.

Turning to Slide 5. This slide looks at how our barrels are priced in different geographies and the time lag we see between production and revenue. Our three core production hubs, Ghana, GTA and the Gulf of America, are all priced of premium benchmarks. In fact, across the U.S. E&P sector, Kosmos is one of the most exposed companies to international prices as a percentage of sales.

Around 50% of our production, primarily Ghana is priced off Dated Brent, the dark blue line on the chart. Since the Middle East conflict broke out, the Dated Brent premium over WTI has more than tripled. Ghana cargos are typically priced off an average 5- or 10-day period before or after the cargo loading.

Our March Jubilee cargo had already been hedged, so we didn't benefit from the rise in prices seen in the month, but we do have a growing amount of unhedged production as we move through the year that should capture additional upside.

In the Gulf of America, we sell most of our barrels against Heavy Louisiana Sweet or HLS, which generally trades at a small premium to WTI, the red line on the chart. Production in the Gulf is typically sold on a 1-month trailing average, so we'll start to see the benefits of higher prices as we move into the second quarter.

On GTA, the gas production is priced off ICE Brent, the green line on the chart, which also generally trades at a premium to U.S. prices. Production is priced at a 3-month historical average price, so we'll start to see the full benefit of higher prices in 2Q. However, the lag effect also means we'll continue to see firmer GTA pricing beyond any future price declines.

So, in summary, we've seen record production, record prices and record differentials. But given the pricing structure we have in our various sales contracts, we won't see the benefit of higher prices that started in late 1Q until the second and third quarters.

I'd now like to talk about each of our business units in more detail.

Turning to Slide 6, which looks at the progress we're making in Ghana. This is a slide we've used for the last two quarters and has been updated for recent activity. As the operator discussed in our full year results last week, the 2025-'26 drilling campaign continues to perform strongly.

The J74 well came online in early 2026, followed by the J75 well at the end of the quarter. Both wells are performing in line with expectations and gross Jubilee production for the first quarter was around 70,000 barrels of oil per day.

The plots on the chart have been updated slightly since last quarter and reflect the partnership's decision to enhance efficiency by drilling a series of wells before completing them simultaneously. This means there will be a gap in new production additions during the second quarter with 2Q production expected in the mid-70s.

Three new producer wells are due online in relatively quick succession in June and July as previously communicated by the operator. Each of these wells has been drilled and completion operations start shortly. Based on the logging results, these 3 wells should drive a material uplift in production of around 20,000 barrels of oil per day gross in aggregate before some natural decline is expected in the fourth quarter as the drilling campaign concludes.

Year-to-date performance and the upcoming activity set continues to support the upper end of our 70,000 to 80,000 barrels a day gross oil production guidance for Jubilee this year.

Looking at the bottom right of the slide, we're pleased to see the operator announce their refinancing earlier in the year, which was accompanied by a commitment to drill in '27 and '28. The partnership is aligned on securing a rig for a program of up to 10 wells, with drilling targeted to restart around mid-2027.

As we previously discussed, this regular drilling program is key to sustaining the improved performance we've seen from Jubilee this year. Also worth noting is the value creation from the current drilling program, with well paybacks in a mid-cycle price environment of around six months, and a lot shorter in the current environment.

Turning to Slide 7. GTA has continued to perform strongly this year, with around 2.85 million tons per annum, equivalent gross produced in the first quarter, in excess of the floating LNG nameplate capacity of 2.7 million tons per annum.

9.5 gross LNG cargos were lifted during the quarter, in line with guidance. For the year ahead, our gross cargo guidance of 32 to 36 LNG cargos is unchanged. One gross condensate cargo was lifted in the quarter, which went to BP. The second and third condensate cargos later in the year, including one this quarter, are expected to be assigned to Kosmos and the NOCs.

Due to some seasonality that we flagged in the past, daily LNG production is expected to fall from higher winter levels as the sea and air temperatures warm up through the summer months. Volumes should then pick up again later in the year as cooler temperatures return.

On costs, we remain on track to deliver our 50% reduction target for OpEx per mmbtu this year and see scope for further cost reductions in 2027.

On the Phase 1 expansion, which should materially enhance project returns, there's been good progress on the ground in Senegal year-to-date. Approximately 50% of the land has been cleared for the onshore section of the northern segment of the pipeline, with the remaining 50% expected to be done this quarter.

This northern segment will connect to the 250-megawatt Gandon power station being built near Saint-Louis.

The onshore pipelines are expected to be exported from China in May, with arrival in Senegal scheduled around middle of the year. The West African Development Bank has been appointed as the mandated lead arranger to raise approximately $270 million to finance the infrastructure. The Board of Directors of the bank approved at the end of March, the first tranche of around $90 million.

Turning to Slide 8. Production in our Gulf of America business unit for the first quarter was in line with expectations, with continued solid performance from our Odd Job and Kodiak fields.

In April, the Winterfell-2 well was shut in pending a future intervention, and full-year Gulf of America production is now expected toward the lower end of our guidance. On the growth side of the business, we were pleased to take the final investment decision on the Kosmos-operated Tiberius project alongside our 50-50 partner, Oxy.

With an expected development cost of around $10 per barrel and operating and transport costs of around $20 per barrel for the first phase, this is a low-cost, high-margin development. The first phase will be a single well tie-back that will produce into Oxy's nearby Lucius platform.

CapEx is planned largely to be spent in 2027 and 2028, with first oil expected in the second half of 2028. We have commenced a farm-out process to reduce our working interest to around a third.

As mentioned with our full-year results in March, we recently entered into a strategic exploration alliance with Shell in the Gulf of America and exchanged interests across multiple blocks across the North Pole play, which houses several material exploration prospects.

We expect to drill the first of these, Tiberius, in the first half of 2027. Tiberius is targeting around 200 million barrels of oil equivalent gross resource.

I'll now turn to Neal to take you through the financials.

Thanks, Andy. Turning now to Slide 9, which looks at the financials for the first quarter in detail.

Production year-on-year was around 25% higher, driven by both GTA ramp-up and new wells coming online at Jubilee, resulting in record production of 75,000 BOE per day for the quarter. Realized price was slightly lower year-on-year, reflecting the changing production mix, with more gas volumes from GTA.

As Andy mentioned earlier, due to the lag in pricing, we don't expect to see the full benefit of higher prices until the second and third quarters this year. OpEx of just under $20 per BOE was in line with our guidance and marks a decrease year-on-year of 47%, reflecting the continued progress we're making this year in reducing costs, having focused on CapEx ad overheads last year. Most of the other line items came in within our previous guidance ranges, except tax, which was impacted by the large mark-to-market change in derivatives.

Looking ahead to Q2, we have included the usual guidance in the appendix to the slides. Q2 production is expected to be slightly lower than 1Q, largely due to seasonality on GTA we talked about, and lower Gulf of America production on the back of Winterfell-2.

In Ghana, we're guiding to three to four cargos in Q2, which also includes a TEN cargo in the quarter. This also drives higher Q2 OpEx as a result of the accrued TEN FPSO lease payments prior to the agreement to purchase the vessel. OpEx is expected to normalize in the third and fourth quarters. One jubilee cargo is expected at the very end of the quarter, which is the reason for the three or four cargo range for Q2. For the full year, guidance remains unchanged.

One area that we continue to monitor is tax as we incorporate higher oil prices into our actuals, and we will provide further updates through the year. Just a reminder that we only pay cash tax in Ghana at the moment, given net operating losses in the US and cost recovery at GTA.

Turning to Slide 10.

We've had a busy start to the year on the financing side, completing several important objectives that set us up well for the year ahead. In January, we completed a $350 million Nordic bond and repurchased $250 million of 2027 notes with the proceeds.

We also paid down $100 million of the bank facility with the remainder of the proceeds. In March, we took advantage of the strong share price rally this year to raise around $200 million of equity, which was also used to accelerate our debt paydown. The company exited the quarter, with around $500 million of liquidity, post these transactions, with additional liquidity to be created from the EG sale and from free cash flow going forward.

On the reserve-based lending bank facility, the banks approved a covenant waiver through the mid-year, and we are already seeing leverage drop sharply on the back of the equity raise and strong operational progress. We expect this to continue as we start to see the full benefits of higher production and higher pricing coming in over the coming months.

The lending banks have also approved the sale of our producing assets in Equatorial Guinea, which we expect to close around the middle of the year, with the proceeds used to further pay down the facility.

On hedging, we continue to be active, targeting more hedges in 2027 at higher floors and higher ceilings than our existing 2027 hedges. Last week, we were pleased to see Fitch upgrade our corporate rating to B-, a positive move to reflect the progress we have been making so far in 2026, but discussion ongoing with S&P as well.

Despite the higher pricing we have seen so far in 2026, our capital allocation for the year remains unchanged. We remain focused on increasing our financial resilience and utilizing our free cash flow to accelerate debt paydown with deleveraging.

With that, I will hand it over to Andy

Thanks, Neal. Turning now to Slide 11 to conclude today's presentation. As I said in my opening remarks, we have four key objectives for 2026: grow production, lower costs, reduce debt, and advance our quality growth portfolio with minimal CapEx in 2026. This slide highlights the targets we've set against those objectives.

On production, we now expect to complete the sale of EG around the middle of the year, making that adjustment for the second half, we still feel we can achieve production growth close to that 15% target.

On costs, based on year-to-date performance so far, we feel confident that we can meet and potentially exceed our 20% operating cost reduction target. So, in aggregate, we're on track to deliver a reduction of around 35% in operating cost for BOE year-on-year.

On debt with the EG sale, equity raise and higher pricing, we're doubling our debt reduction target from 10% to around 20% by year-end and have made significant progress already.

And we are advancing our growth portfolio with Tiberius FID, progress on GTA expansion and the exploration alliance with Shell in the Gulf of America. We look forward to delivering on these 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?

[Operator Instructions] Our first question comes from the line of Charles Meade with Johnson Rice.

I want to ask the first question on Jubilee. The OBN seismic shoot that you guys did at the end of the year last year, is that, are the results or insights from that, are those already informing this '26 drilling program? Or is that something where we're really going to see more of the benefit in the '27, '28 program?

Charles, no, the OBN is really going to have an impact on the '27, '28 program, yes. So, the '26 program, though, is leveraging the 4D NAS that we shot ahead of the OBN. And so, we've got the product from that, and that did influence the selection of the '26 drilling program, which is going well. So, I think the objective then is to build the results from the early products of the OBN and then the later products of the OBN into the '27 program, match that with the NAS.

And so, you're getting a continuous upgrade in the quality of the seismic and therefore, the opportunity to derisk the future drilling programs. And as I said in my remarks, the, we're seeing the impact of a continuous drilling program on Jubilee in '26. Carrying that through into '27, '28 is clearly important. And these are economically good wells. In my remarks, I talked about a 6-month payback in a mid-cycle price environment. Clearly, we're doing better than that.

So, a lot of, as you know, there's a lot of opportunity in Jubilee and the seismic upgrade through the 4D NAS and then the follow-on of the OBN is continuing to make a difference.

Right. That's what I was aiming to get at. And then the follow-up on Tiberius in the Gulf of Mexico. I think you have a point in your slide that you expect a farm-out proceeds to cover any '26 CapEx? That maybe in broad strokes, it seems to me that the farm-out proceeds to you will be on the same order of magnitude as what the dry hole cost, proportion of dry hole cost would have been. And so, it doesn't look like there's a big premium that you're looking for on this farm-out, but maybe you can tell me if that's the right read.

Yes. Obviously, I don't want to disadvantage ourselves in the process that's ongoing at the moment. Look, I think it's a great time to be in the farm-out. We clearly have a project that's underway. FID has been taken, strong alignment between ourselves and Oxy. And therefore, there's been significant interest in the opportunity. So, we're obviously looking to maximize the farm-out proceeds, and we may do a little better than we'd anticipated.

And your next question comes from the line of Lydia Gould with Goldman Sachs.

You target a 20% reduction in operating costs this year. Could you expand on some of the key strategic initiatives that are in place across the portfolio to meet this target, particularly at GTA?

Yes. Lydia, yes, look, it's a combination. And I think I want to emphasize the fact that we've used the opportunity to high-grade the portfolio and address some of our highest cost assets. And those highest cost assets were in Equatorial Guinea, where clearly, we are selling the asset. And also, it was on TEN because of the lease cost on the FPSO.

So those, both of those are making a significant difference. Then on top of that, there is an ongoing reduction in GTA. There's an absolute reduction in operating costs as you take out some of the additional costs that were in last year because of the start-up process. But clearly, you're seeing a big impact on the per BOE number or MMBTU number because of the ramp-up in production.

But the combination of those sort of ongoing processes and the asset high-grading delivers that 20% reduction in absolute operating costs that we're seeing in '26 versus '25. And I think there's ongoing opportunity. We haven't stopped there. I think there's ongoing opportunity in Ghana in '27 as you look at the ability then to sort of, you'll have the operator than having the operations of both FPSO.

I think there's opportunity to create synergies there. And then there are different operating models in Mauritania and Senegal for GTA, which are being explored by BP. So, I think this is just the start of a journey of continuing to drive cost down and the big step in '26 comes from that underlying activity, but also the high grading of the portfolio.

And your next question comes from the line of David Round with Stifel.

A key theme in recent years has been around this cost reduction and capping CapEx actually specifically. I'm just interested in whether this commodity backdrop makes that harder to achieve and how you're thinking more generally about CapEx in '27 and beyond, please?

Yes. David, yes, good questions. We go through price cycles, yes. And I think you do see some tightening. I think it's very hard to predict today what the long-term effect is on the inflationary environment. I think it's too early to say that. But I think the things that we're doing now are just not about smarter procurement, if you like. It's about underlying changes in how you do activity.

And I think that means that the cost reductions that we're targeting and the ongoing cost reductions we would target in Ghana and GTA are about changing the way you do business. Therefore, the activity changes, therefore, the cost comes down.

So I think those are enduring. I don't think they sort of are simply about the procurement cycle you're in. And clearly, the high grading of the portfolio is independent of that. So I think that opportunity remains, and I don't think the magnitude may vary a little, but the opportunity remains.

And then I think on CapEx, we've clearly targeted CapEx hard in both '25, '26. I think that we're focused again on ensuring that we're being very, very rigorous about the allocation of capital. I think we've been clear around the growth opportunities that we're pursuing. It is Tiberius.

It is the GTA expansion, trailblazer exploration. In a timing sense of the spend flowing through, I think Tiberius is relatively low spend in '27. The biggest spend is really in '28, probably if it's $100 million on Tiberius net, it's probably 1/3, 2/3 in that sense.

The GTA, it's probably overall for Phase 1 plus there really isn't any expenditure on the facilities. You can move from 430 to 630 production through the FPSO with no spend. Therefore, it's about the additional wells that will sustain the portfolio beyond the end of the decade. And therefore, the spend for that will really be in '28, '29.

So we take all of that, I don't think you'll see a significant, it's early days yet, but the capital for '27 is going to be pretty tight, maybe a little higher than today for '26, maybe around $400 million. But underneath that, you've got the sustaining CapEx that we're spending today in drilling in Ghana and the Gulf. That will sort of be pretty similar in '27. And then you've got a little more growth CapEx. But that allows you then though to continue to move forward these high-quality prospects.

Okay. That's very clear. A very quick follow-up then, actually, if I might. Can you just remind us if there is a specific leverage target, please?

I'll pass it over to Neal.

Yes. And so David, we've always talked about getting to sort of 1.5x in a normalized oil price environment. And again, I think what you'll see this year is we said we'll take off around 20% of the debt. We started this year at $3 billion, which we get into sort of the mid-2s. And then with higher oil prices, you can continue to flex that down.

And then the EBITDAX of the business jumps quite largely. So last year, we did something in the $500 million to $600 million range, which should be north of $1 billion this year in terms of where we get to. And so that leverage ratio compresses quite quickly. But I think, again, from, Andy said, the capital has continued to stay a bit tight in '27, but that allows us to advance the projects and at the same time, generate free cash flow to pay down the debt.

So the goal is to do both at the same time and get leverage, what we'd like to see is sort of the net debt fall below $2 billion first in terms of a milestone. So we'll make a good dent in that progress this year. And again, we're seeking to sort of maximize every dollar in terms of debt paydown.

[Operator Instructions] And our next question comes from the line of Bob Brackett with Bernstein Research.

I'd like to talk a bit about Senegal and GTA. You mentioned the Phase 1 plus, which I expect is a 300 million cubic feet a day gas pipeline that brings ultimately molecules up to that Gandon Power Station. Can you talk about how to think about the unit economics? You mentioned it's reducing OpEx. How do we think about the volume? Is it your 27%? And how do we think about price?

Yes, Bob, good questions. I think that the first thing is it's somewhere that the expansion of GTA, I sort of think about it being sort of $200 million rather than $300 million, yes. You can go from today, we're pushing about 430 million standard cubic feet through the FPSO. You can get to 630 million without actually spending any capital on it. If you want to go up higher than that, there is an increased demand. There are incremental spend on capital to get there, relatively modest.

But if you think about the first wave being sort of $200 million, the first piece of that domestically, piece of it will be used in Mauritania, a piece of it will be used in Senegal.

The first piece in Senegal will flow to the Gandon Power Station, as you said. Then the RGS, which is the pipeline company in Senegal, we'll continue to build that pipeline south from Saint-Louis to Dakar. There's actually four phases. You can look online and see what they're doing and ultimately allows you to build out that sort of power station infrastructure down towards Dakar. So it's going to be a phased process that will start to build through '27, '28, '29 and to the end of the decade.

So actually, in terms of unit economics, the capital spend for us is very low, sort of de minimis is the way to think about it for that 200 million standard cubic feet. There is capital spend to sustain the profile at the back end of the decade, which is associated with more wells to keep you at that sort of 630 million, 650 million standard cubic feet. But ultimately, it is a very low-cost expansion. And therefore, the margin that you're getting from it is high. You're almost, from an operating cost perspective, there is no FLNG lease. And therefore, your margin on those versus the export is higher.

And again, I think the easy way to think about it, Bob, is just, again, we've said sort of Phase I OpEx is around sort of $5 to $6 per MMBTU. That's fixed cost essentially. The costs don't change with the expansion on the operating cost. And therefore, you get a sort of multiplying effect in terms of reducing that to sort of the sub four type area. So again, I think every incremental molecule helps bring down that breakeven even faster.

And then for the domestic gas, you're not paying the FLNG cost, which is part of that sort of $4.

A follow-up, please. I'm seeing mixed messages in the press around Yakaar-Teranga. Can you give us an update on what's happening there?

Yes. I don't think it's sort of mixed messages, Bob. I think that the key message out of it is around the importance of domestic gas for Senegal's growth, relatively large population, growing population, reducing the cost of power, electricity is a key priority for the government. And therefore, their goal is to ensure that they can advance those projects and do that in a timely way.

But at Kosmos, it was about saying we want to invest in GTA. We want to enable that source of domestic gas to be our focus. And therefore, we did relinquish Yakaar-Teranga. The government has picked it up. Petrosen, I believe, will lead that development, and it will be another source of gas for the country. But given the scale of the economic growth, I think, that can be seen basically from population growth, then it needs all the gas that the country needs all the gas that it can take.

Mauritania is a slightly smaller population. So the pull for domestic gas will be lower and can be fed by GTA. So this is good for both countries.  And clearly world events today are all about how do you create security and affordability and the extension now of both GTA and Yakaar-Teranga will enable Senegal to achieve those goals and we are fully supportive of it.

Our next question comes from the line of Mark Wilson with Jefferies.

I got a question from an investor to start off with. It's probably more for Neal. Just wondering about the derivative cash losses in Q1 and what we should expect in 2026. And obviously, this speaks to this maximizing of deleverage.

So yes, the cash derivatives, Neal?

Yes. Yes, it's clearly a large mark-to-market change. And again, we came into the year with an asset of about $50 million, and then there's a $250 million market-to-market loss, just given we got payout in January and February on those hedges, and then clearly, the market moved. From a cash perspective, it cost us about $30 million and not a ton of cash, actually.

But clearly, the implied shift in the forward curve has an impact on the derivative side. Our hedges are largely sort of yes, focused on sort of the first half of this year. So we talked about we have 6 million barrels left for the rest of the year, about half of that matures in Q2, and the other half over the second half of the year. And so there's a larger exposure in Q2 and then sort of less, and then that sort of steps down again in Q3 and Q4.

And so again, it will ultimately depend on sort of what the actual realized Dated Brent price is. But we feel okay with our exposure on '26 and have really been working on adding some additional downside protection in '27. And so again, I think we're good in terms of where we are.

We'll have more physical exposure from a pricing perspective, as we talked about in the call in 2Q. And so there's a bigger, call it, unhedged volume that we'll be able to realize in the second quarter, with more physical volume being sold versus the hedges. So again, I think Q2 is sort of shaping up quite nicely, and then the hedging exposure comes down at least more access to the upside from the physical sale.

Okay. And Andy, a slightly bigger picture question. I'm just wondering what contact you've had with, if at all, with the new management setup at BP, given Tortue is performing so well. I'm just wondering if there's any commentary you could give there.

No. Look, things change, and they don't change. For us, clearly, and for BP, ensuring that GTA runs both efficiently from a cost perspective, but equally well from a production perspective. We deliver on the cargo forecast, et cetera. So that's all going well, Mark. And we sort of see no change. Clearly, Meg, the new CEO, has significant experience of Senegal from her experience at Woodside with Sangomar. So as we bring, it's great, somebody who has deep industry knowledge and very specific knowledge actually of the, of that Pacific geography.

So the real sort of answer is, as you'd expect is that we're focused on the operational side at the moment and ensuring that we deliver on the targets we've set. And actually, that's exactly what we're doing.

Okay. And then just one last point, just checking on the Jubilee guidance. Is there any scheduled downtime on the vessel in the rest of the year, maintenance or anything?

I think you've asked that question before. You do like that question. The honest answer is no, okay? So none in '26 and '27. I think that's what the operator told you last time. So, no, the answer is no scheduled maintenance. And look, if I go to the essence of your question, right, are we comfortable with our guidance?

The answer is sort of yes. And why? As we started the year, we were unclear about forecasting yet. But of course, now, sort of getting close to the middle of May, you have a lot of extra information. The field started the year at, we ended the year '25, at 57,000 barrels of oil per day. We've stabilized it. We've added two wells. It's delivered at 70,000 barrels of oil per day. year-to-date.

So very strong performance with two wells added. We have now drilled three wells. We have all of the logging information, pressure data, et cetera. So, we're confident we're adding wells that will add an additional 20,000. So, you built a base of 70,000, and you add another 20,000. And you can see on our plot, which we showed in the presentation, the resulting production profile.

So, I think to the point really, to add is, look, we're further down the process. We've clearly delivered strongly in the first 4 or 5 months of the year. We've got additional data from the wells that we've drilled, and we're now starting that completion process. So, I think as every month goes by, we're more confident that we can deliver on the guidance that we've given with no shutdowns in '26.

And your next question comes from the line of Stella Cridge with Barclays.

I just wondered if I could ask you for a bit more color or comments on how you're thinking about the debt profile going forward. You have taken many actions year-to-date to address many different parts of the capital structure. The RBL discussions, you said, are going to commence around a bit midyear. Could you give us any sense of what you think the lenders will be looking for there? Would it be sort of the visibility around Jubilee, for instance, in this supportive oil price environment?

No, I'm happy to do that. And then if you have another question, we can follow up. But yes, like I said, we've been quite busy on the financing front. And again, what we wanted to accomplish is pretty clear in terms of clearing out the near-term maturities and bolstering liquidity, sort of stabilizing the ratings and continuing to reduce the absolute amount of debt. So again, as I say, we're well on track to deliver all of that.

We've cleared the '26s and most of the '27s at this point. Liquidity is $500 million and growing. And we're on our way down on the debt paydown to get into the low 2s from a leverage standpoint by the end of the year. So again, I think all that's on track. And that leaves sort of, as you referenced, sort of the next financing objective for us to work on is the extension of the RBL. Just to recall, this would be the sixth RBL extension that we've gone through or that I've been through here at Kosmos.

And so again, normally, it's a 7-year facility, it doesn't amortize for 3 years, and then you end up extending the tenure every 3 years. And so, I met with the banks recently. Again, they continue to be really supportive. They are looking for Jubilee performance to continue to improve.

But again, I think that process is well underway, as Andy noted. And otherwise, again, I think they want to see the same thing that our creditors and equity holders want to see, which is for us to bring the leverage down. So as we execute the plan, again, I feel pretty good about going into that process in the middle of this year. And then that will basically kick, the ultimate maturity from sort of '29 to sort of the 32, 33 time frame.

And just want to ask, I thought it was very interesting in the report that they were talking about potentially you're trying to get down into the $800 million to refinance a smaller amount in the RBL. Is that something you could comment on as well?

Yes. And so we exited 1Q with about $1 billion drawn on the facility, with the EG proceeds coming in around $150-ish million free cash flow. Again, I think naturally, the RBL will reduce into that range from a drawn perspective. From a total facility size perspective, though, which is what will generally extend, I wouldn't expect much change. We were at a sort of $1.3 billion facility size. We probably don't need that much just because we're bringing down, the absolute amount of both bonds and bank within the capital structure. So maybe it's 1.25-ish in terms of facility size. I wouldn't expect the size to change dramatically, although again, I think the bigger focus on our side is just reducing, the actual drawn amount.

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.

Thank you for standing by. My name is Colby, and I'll be your conference operator today. At this time, I'd like to welcome everyone to the Q4 2025 Kosmos Energy Earnings Conference Call. [Operator Instructions] I now like to turn the conference over to Jamie Buckland. You may begin.

Thank you, operator, and thanks for everyone for joining us today. This morning, we issued our fourth 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. And at this time, I will turn the call over to Andy.

Thanks, Jamie, and good morning and afternoon to everyone. Thank you for joining us today for our fourth quarter and full year 2025 results call. I'd like to start today's call by reaffirming Kosmos' key priorities, which have remained consistent over the last year before reflecting on our progress in 2025. I'll then talk about the operational momentum we've already built this year and the planned activity set for the remainder of the year. Neal will then take over to review our financial progress and priorities for 2026 before I wrap up with closing remarks. We'll then open the call up for Q&A.

Starting on Slide 3. As we close out 2025 and enter 2026, our goals of building a sustainable, lower-cost business has not changed. We're growing production from our core assets. We're laser-focused on cost reduction, and we're targeting a meaningful reduction in debt this year. We're doing all of this while high-grading our portfolio to drive down the overall breakeven of the company.

Turning to Slide 4, which looks back on 2025. 2025 was a challenging transitional year for the company, creating the platform for a sustainable, lower-cost business. We delivered safe operations with no lost time or recordable injuries during the year. We delivered strong 1P reserves replacement of around 90% or 120% when excluding the assets we're selling in Equatorial Guinea.

The Ghana licenses were extended to 2040, bringing additional reserves and reinforcing a commitment to invest in Ghana over the long term. We saw production growth every quarter in 2025 as we recommenced Jubilee drilling and ramped up GTA production. GTA was fully ramped up in the fourth quarter with a floating LNG vessel producing at its 2.7 million ton per annum nameplate equivalent through the month of December.

And finally, on the finance side, we continue to enhance the resilience of the balance sheet, reducing near-term maturities and adding more hedges to manage our oil price exposure. We didn't deliver everything we set out to do in 2025. Production growth came more slowly than expected and net debt ended the year higher than planned. But we laid the groundwork to deliver in 2026, and we're already seeing strong progress and momentum this year.

Turning to Slide 5. As I said on the previous slides, our agenda remains consistent and our key priorities have not changed. We've had a strong start to 2026 with good progress across production, costs and the balance sheet. Starting with production. The Jubilee drilling program is continuing to deliver. The second producer well came online in January and is contributing around 13,000 barrels of oil per day gross. This includes any cannibalization from neighboring wells and takes Jubilee production to over 70,000 barrels of oil per day gross, in line with our expectations. Five more Jubilee wells are due online this year, which helps support further material production growth in the field.

At GTA, after strong 4Q performance, production has remained high, averaging 2.9 million tons per annum equivalent year-to-date with 6.5 gross LNG cargoes shipped year-to-date in 2026. And in the Gulf of America, production continues to perform well, in line with our expectations. On costs, we're targeting CapEx this year of around $350 million, which includes around $300 million of asset expenditure in line with 2025 and around $40 million associated with the TEN FPSO purchase.

On operating costs, we're targeting an absolute OpEx reduction of over $100 million year-on-year as we continue to look for ways to drive costs out of the business. This reduction is expected to increase to around $250 million post the sale of our production assets in Equatorial Guinea. On overhead, we expect to see the full benefit of the cost savings we identified and implemented through 2025, benefiting the company sustainably in 2026 and beyond as we focus the organization on our most important priorities.

Finally, on the balance sheet, it's been a busy first few months of the year. In January, we successfully completed a $350 million bond in the Nordic market. We'll use $250 million of the proceeds to pay down our 2027 notes and $100 million to pay down the RBL. On the RBL, we received a leverage covenant waiver from the bank group for year-end 2025 and midyear '26, which allows time for our leverage to normalize with GTA now fully online and Jubilee ramping back up. On hedging, we took advantage of recent price strength to commence our 2027 hedging program. And we recently announced the sale of our producing assets in Equatorial Guinea, which enhances liquidity and accelerates debt paydown.

Turning to Slide 6, which provides a summary of our reserves at year-end. On 1P reserves, we have reserve to production life of around 10 years, which underpins our near-term growth activities. We also had a strong reserve replacement ratio of around 90%, largely driven by Jubilee additions post the license extensions. Adjusting for the recently announced EG disposal, 1P reserve replacement would be around 120%, demonstrating the high grading of the portfolio.

On 2P reserves, we have reserve base of around 500 million barrels of oil equivalent, representing a differentiated reserve life of around 20 years. This deep reserve base allows sustained 2P to 1P migration over time as well as additional 2P recognition as projects are sanctioned to develop already discovered resources. The 2P reserve base is slightly down year-on-year, reflecting some downward revisions largely in EG. As with previous years, our reserve data has been independently prepared by leading reserves auditor, Ryder Scott. So in summary, we continue to have a robust and diverse 1P and 2P reserve base that underpins the sustainability of the business well into the future.

Turning to Slide 7. It's been a busy start to the year in Ghana with an active drilling campaign, new OBN seismic, license extensions and a commitment to purchase the TEN FPSO. Before I get into each of these developments, I want to share some insight from a meeting in February with President Mahama in Accra. We meet regularly as part of our discussions, we talk about the future of Ghana's oil and gas industry and about the critical role Jubilee and TEN play in the country's energy security, economic growth and long-term development.

Oil and gas remain a vital pillar of Ghana's economy. It's a major source of government revenue, supports skilled jobs and strengthens national energy security. Continued investment in the sector today is essential if it is to deliver fully for Ghana in the years ahead. At Kosmos, we continue to see strong alignment with the country's interest and with President Mahama's administration around a clear priority. Long-term sustainable investments support higher production and ensure the sector delivers tangible benefit for the people of Ghana for many years to come.

With sustained investment and a stable operating environment, the opportunity is compelling. Higher production can generate greater state revenues, while low-cost associated gas can support more reliable, affordable domestic energy for power generation and broader industrial use. Our focus is to work constructively with our partners and the government to realize that potential, driving growth, lowering costs and ensuring these world-class assets deliver long-term value for Ghana, the partners and all our stakeholders.

Looking in more detail at the activity year-to-date. The drilling campaign has started positively with the J74 producer well, which came online in January. The well continues to perform strongly and is contributing around 13,000 barrels of oil per day gross with Jubilee producing more than 70,000 barrels of oil per day gross. The next producer well, J75, is expected online around the end of the quarter with a meaningful increase in production expected from current levels.

After J75, we then have 4 additional wells to bring online later in the year with 3 producers expected to grow production and 1 water injector to support the higher production levels. At the end of last year, we concluded the ocean bottom node or OBN seismic acquisition over the field. The data is now being processed using the latest technology with the results expected to deliver significantly enhanced imaging to allow for better selection of future well locations, leading to improved recovery over the life of the fields.

In February, the Ghanaian government formally ratified the license extensions for Jubilee and TEN to 2040. We're pleased to have played a leading role in progressing those discussions with the government. As I said on recent earnings calls, the license extensions were an important step for the partnership to support increased investment in the field for the long-term benefit of all stakeholders.

And finally, in February, the partnership signed the sale and purchase agreement to acquire the TEN FPSO at the end of its lease term in early 2027. Signing the SPA will result in significant OpEx reduction from 2026 onwards as the lease payments will be classified as CapEx until early next year and then be eliminated.

Turning to Slide 8, which we showed last quarter, highlighting the strong correlation between drilling activity and production performance. On Jubilee, the partnership returned to drilling in the middle of 2025 with J72, the first producer well of the '25-'26 drilling program, which largely arrested and offset field decline in the second half of 2025.

As I mentioned, in early January, the J74 producer well then took production back above 70,000 barrels of oil per day gross and has stayed above that level since supported by high levels of water injection. The blue dots on the chart show the approximate timing of the next 5 wells coming online with each producer well expected to drive higher production.

As a reminder, these are high-return wells with quick paybacks. The last 12 wells drilled in Ghana have an average payback of around 9 months. The latest 2 wells in the current campaign are likely to be closer to 6 months given their strong performance. These compelling economics support a consistent drilling program informed by the new seismic data.

With this year-to-date performance and the active program over the next few months, our production forecast for Jubilee is in the range of 70,000 to 80,000 barrels of oil per day gross with current performance supporting the upper end of the range. This forecast uses actual data for the first 2 months of the year of around 70,000 barrels of oil per day gross plus the expected performance of the additional 5 wells.

We assume a decline rate for the field of approximately 20%. Year-to-date, we've done better than this as a result of well replacement ratio of 130%, a key performance metric. In our second quarter 2025 results, I talked extensively about the impact technology is having on our business. And in Ghana, we're already seeing the positive impact of the 4D seismic shot last year. The improved imaging gives us increased confidence in the performance potential of the asset and the year-to-date performance has been very consistent with our modeling.

We look forward to integrating the OBN data with the 4D NAS data to help select the best well locations for the '27-'28 drilling program as well as optimize water injection to manage future decline. With the license extensions, the partnership is now starting to plan the long-term investment in the fields. As we mentioned on previous earnings calls, Kosmos has been a strong advocate of regular drilling to maximize the value of a mid-life field like Jubilee, a position which was echoed by the operator in their recent trading update.

So in summary, there's been a lot of progress in Ghana year-to-date with an active program through the remainder of the year that should see higher production from new wells and a partnership aligned to invest in the future. Turning to Slide 9. At GTA, we've also seen a lot of progress. In the fourth quarter, the partnership listed 8 gross LNG cargoes with 18.5 for the full year. We also lifted the first gross condensate cargo in the fourth quarter at a small discount to Brent, another important revenue stream for the project.

Production ramped up steadily during the fourth quarter, averaging the FLNG nameplate volume of 2.7 million tons per annum equivalent throughout December and on several occasions, reaching record levels of around 3 million tons per annum equivalent. So far this year, this good performance has continued with production around 2.9 million tons per annum equivalent year-to-date, partly benefiting from the cooler seasonal weather.

We are targeting 32 to 36 gross LNG cargoes and an additional 3 gross condensate cargoes in 2026. On costs, we expect operating costs to be lower year-on-year, targeting a reduction in OpEx per MMBtu of over 50%. This reflects lower costs, including the FPSO refinancing that was completed in January alongside the higher production volumes. As Golar said in their results last week, they are working with the partnership to develop value-enhancing initiatives for the project, including FLNG operational efficiencies and debottlenecking of the LNG production capacity.

Production should continue to rise and unit cost should fall as we move forward with Phase 1+. We expect to agree heads of terms for domestic gas sales in 2026, and Senegal is expected to commence construction of the domestic gas pipeline network next quarter. The chart on the right shows the significant drop expected in OpEx per MMBtu as the higher volumes and cost reductions come through in 2026 as well as the impact of Phase 1+.

We've shown volumes of 613 million standard cubic feet per day for LNG export and domestic gas as that is what the FPSO is capable of doing today without any cost required to debottleneck the infrastructure. As the Senegalese government builds the multiple phases of the onshore pipelines, domestic gas needs will continue to increase, driven by demand for power and industrial use such as fertilizer plants in various centers from Saint-Louis in the north to the capital Dakar.

Turning to Slide 10. the Gulf of America, performance for the fourth quarter and the year was in line with expectations with good performance from Odd Job and Kodiak and minimal storm downtime offset by lower Winterfell performance.

As a result of challenges in drilling and completions at Winterfell last year, we took an impairment on the assets in today's results following the fair value assessment with the auditors. While there's still a lot of resource potential at Winterfell, we're working with the operator to refine the drilling program to reduce risk going forward to ensure we produce the resource in the best and most cost-effective way.

Looking ahead, we have an attractive hopper of future opportunities in the Gulf of America, which we are advancing with some of the most established players in the basin. In the Outboard Wilcox, we have advanced the low-cost development plan on Tiberius with our 50-50 partner, Oxy. Kosmos is the project operator and Oxy owns and operates the Lucius host facility, so we are well aligned. We expect to take FID in the first half of 2026 with the bulk of the CapEx in '27 and '28. Post FID, we plan to farm down our interest to around 1/3.

Elsewhere in the Gulf, we formally entered into a strategic alliance with Shell earlier this year to jointly explore the prolific Norphlet. As part of the partnership, Shell and Kosmos have exchanged interest in multiple blocks with several high-quality prospects targeting over 400 million barrels oil equivalent gross, all within tieback distance to Shell's Appomattox facility.

The first prospect Trailblazer is targeting over 200 million barrels of oil equivalent gross with drilling planned for 2027. To fit within our lean capital budget this year and next, Kosmos has the ability to adjust its working interest to manage our capital exposure. Neal will now take you through the financials and the progress we're making on our cost reduction targets.

Thanks, Andy. Turning now to Slide 11, which looks at the financials for the fourth quarter in detail. Production was again higher sequentially due to the continued ramp-up of GTA through the quarter, achieving well in excess of the nameplate capacity in late 2025, as Andy mentioned. We ended up only lifting 2 cargoes from Jubilee in Q4 as the third cargo slipped into early 2026.

While this has minimal impact to value, it does materially change Q4 EBITDAX and leverage. Realized price was lower sequentially, reflecting lower commodity prices, although we'd expect this to bounce back in 1Q '26 with the higher prices we've seen quarter-to-date. OpEx was higher than our expectations during the fourth quarter, largely due to higher costs in Equatorial Guinea. DD&A was lower quarter-on-quarter, but above our guided range due to lower sales volumes than forecast. Most other line items were in line with our forecast, with CapEx materially lower, reflecting the lower-than-expected accrued CapEx in Ghana.

Turning to Slide 12. As Andy said in his opening remarks, one of the key priorities for the company as our phase of significant investment in growth comes to an end is to reduce costs to ensure we continue to grow our margin. In 2025, we made a lot of progress with CapEx of $290 million, a year-on-year reduction of almost 70% and the lowest since 2017. This can be seen on the chart in the top right of the slide. We expect 2026 CapEx to remain around these multiyear lows and in line with 2025 when excluding the TEN FPSO purchase in Ghana.

Our focus in 2026 now turns to reducing operating costs. We are targeting a reduction of greater than $100 million net to Kosmos this year, which can be seen on the chart on the bottom right of the slide. The amount of targeted OpEx savings rises to around $250 million once EG is removed from the overall cost base. Our TEN and EG assets represent our highest operating cost barrels. And with the purchase of the TEN FPSO and sale of EG, we will see a significant improvement in our operating margin per barrel. This is important as we navigate a volatile price environment. On overhead, we made a lot of progress in 2025, exceeding our cost reduction target of $25 million by year-end, and we expect to benefit from the full year impact in 2026 with further savings identified.

Turning to Slide 13, capital allocation. As I said on the previous slide, we expect full year CapEx of around $350 million, including the $40 million associated with the TEN FPSO. Around 70% of the annual CapEx is allocated to Ghana with 5 Jubilee wells delivering expected paybacks of less than a year. In the Gulf of America, around 15% of the company CapEx budget has been allocated to the Winterfell-5 well and the long lead items for Tiberius.

In Mauritania and Senegal, we expect minor CapEx during the year as we plan for GTA Phase 1+ expansion and advance the associated wells required towards the end of this decade. In summary, we are tightly focusing our capital on near-term high-return oil projects that deliver production growth and have the flexibility to defer more capital-intensive projects until we get our debt into the right place.

Turning now to Slide 14. As Andy said in his earlier remarks, we have been actively working to enhance the balance sheet, paying down near-term maturities, adding liquidity, increasing our hedging and reducing costs. We are pleased to have completed the $350 million Nordic bond in January, which is well supported by both existing and new investors and helps diversify our sources of finance. I'd like to thank everyone who participated and made this new issuance a success. $250 million of the proceeds are being used to repay the 2027 notes with $100 million used to pay down the RBL facility.

The charts on the right of the slide show the work we have done to address the nearest-term maturities. So our focus can now turn to operational delivery and debt paydown. This year, we are targeting a debt reduction of at least 10% and have made a good start with the announcement to sell our producing assets in EG last week. Further reductions are expected through free cash flow delivery and other noncore asset sales. On the RBL, we received a leverage covenant waiver from our bank group, which covers year-end 2025 and the midyear 2026 tests. This gives us runway to improve our metrics through increasing production, reducing costs and paying down debt. I'd like to thank our banks for their continued support in this process.

Having made good progress on the maturity schedule, our next objective is to commence RBL extension discussions with our bank group this summer, which would push out the dark blue amortization blocks on the bottom right chart as we incorporate more Ghana reserves into our borrowing base. All in all, a pretty active year on financing, which demonstrates our ability to access different sources of capital.

We've also been active on our rolling hedging program, taking advantage of recent price strength to hedge barrels for 2027. We now have 8.5 million barrels of oil hedged for 2026 and a further 2 million barrels hedged for 2027. Post the sale of BG, we will retain our hedges, increasing our hedge exposure in 2026 to over 50%. As hedges roll off, we'll continue to add more to protect against future downside, in particular, in 2027.

So in summary, we're proactively tackling our level of debt and leverage with a lot of progress in 2026 so far with more to go. We're doing a lot to reduce costs further in 2026, and our capital allocation priorities are clear. With that, I'll hand it back to Andy.

Thanks, Neal. Turning now to Slide 15 to conclude today's presentation. As I said in my opening remarks, we have 3 clear priorities in 2026: grow production, reduce costs and reduce debt. This slide puts some targets against those priorities. On production, we want to deliver 15% production growth year-on-year coming predominantly from our core, Jubilee and GTA assets. Alongside that, we plan to deliver a 20% reduction in total operating costs. We expect the combination of higher production and lower costs to reduce OpEx per barrel by around 35%. That increasing margin, combined with our portfolio high grading should allow us to reduce net debt by at least 10% with scope to do better.

And at the same time, we're advancing our quality growth portfolio with minimal CapEx in 2026, and we retain a deep offer of opportunities for the future. As Neal and I have highlighted in today's presentation, the team is focused on delivery, and I'm pleased with the strong start to the year. Thank you. And I'd now like to turn the call over to the operator to open the session for questions.

[Operator Instructions] Your first question comes from the line of Charles Meade with Johnson Rice.

Andy, I appreciate all the detail that you've already given us on Jubilee. And in particular, I appreciate your comments as you went through that Slide 8. But in your prepared remarks, you talked a bit -- I think you used the word cannibalization of bringing new wells online. And I think your operator had talked about backing out volumes. So can you give us a sense for what your net adds will be as you bring new wells online? In other words, if you bring on a 10,000 barrel a day well, are you going to be -- is it going to be an additional net 5 perhaps after you back out lower pressure wells?

Yes. Look, yes, thanks, Charles. Look, it's not the same for every well. That's the most important thing to remember. For instance, when we brought the last well on J74, we were actually able to bring it into a new riser. So that actually relieved pressure on other wells. And actually, I think the net back out was kind of close to 0, yes. So it's not always the same. It depends on also the GOR of the well. So I think we have to be careful not to just do it by rule of thumb. But if you were to get into that conversation, right? And you understand what I'm saying, yes. It's not always the same.

Yes, just go ahead. Yes.

Yes, alright. So -- but a rule of thumb, if you're sort of looking at a well that is coming on at 10,000 barrels a day, sort of on average, you might get sort of 2,500 barrels a day back out, yes. So I think that's the way to think about it. Yes. For some, it could be slightly more. Clearly, for a well like J74, essentially 0, yes. And the final point to make is that all of that is included in our forecasting. So you can model exactly what the well is doing, the GOR is going to come on, what impact it has on the infrastructure, which riser it's coming into, et cetera, yes. So it's obviously part of the forecasting process.

Yes. I'll let your engineers do all that modeling. Second question I have for -- is on GTA and specifically the cargo guidance for the year. If we look at your 1Q guide, you have 90-10, and I think you said you're already at 6.5%. So you're maybe kind of tracking towards the high end there. But if we look at your annual guide of 32% to 36%, the lower end of that annual guide -- excuse me, the low end of your quarterly guide tracks to the high end of your annual guide. So I'm curious, is there a turnaround baked in somewhere in the annual guide? Or is this just some of the seasonal effects that are...

No, it's seasonal, it's seasonal, Charles, yes. So if you -- what you need to think about it is your strongest quarters are going to be quarter 1 and quarter 4, yes. So if you sort of put those 2 bookends together, maybe you could sort of look at 20% from those 2 quarters. And then the residual as it were, is warmer weather in the summer in quarter 2 and quarter 3, where you're going to get lower cargoes. So I think no planned turnaround. It's really the seasonal effect.

And you can't sort of take the first quarter and multiply it by full, but thing to add is that a strong start to the year, yes. And I think that's the most important part. The -- through year-to-date, we're at 2.9 million tons per annum from the facility, which is above its nameplate of 2.7 million ton per annum. So I think the thing to take from it is the strong start to the year should give confidence in the overall outlook for the rest of the year.

Your next question comes from the line of Alexa Petrick with Goldman Sachs.

Could you talk more about the amended debt cover ratio that you announced this morning? How should we think about the next 2 periods coming up, where you stand and how conversations have been going there?

Yes, Alexa, this is Neal. I'll take that. Just yes, so we've had a constructive conversation with the banks so far in the year. And what we -- the 2 next periods is sort of March and September this year, which covers sort of year-end '25 and midyear '26. And so basically, the March covenant cover -- the amendment essentially covers where we ended up at year-end '25. So that's sort of covered off. And basically, in midyear '26, basically, the leverage covenant was raised from 3.5 to 4.25. And that basically accommodates sort of the historical underperformance in sort of the second half of '25 as well as lower oil prices. So it works down to sort of, call it, 60-ish Brent.

So again, we've created some cushion in there. And what we wanted to do with both us and the banks to make sure that sort of we don't have to revisit it. And so it returns to normal by the end of the year. And again, based on our guidance and forecast, we should be back under sort of leverage targets by the end of the year when you take that GTA effect ramp-up effect out of the LTM calculation. So again, I think it's something that was on sort of people's minds. So we wanted to get it addressed early, get the issue cleared out for the year. And now we've got the runway to just deliver operationally and then the results will naturally lead to the deleveraging that we talked about.

And then as a follow-up, I think you've talked about cost per BOE at Tortue declining by more than 50%. Can you help just kind of walk about -- walk us through the bridge there? How much of that is just on top line production growth versus nominal costs coming down? And how should we think about it?

Yes, Alex, I'll take that. It's Andy. Yes, it's both effects, as you say. Clearly, we produced 18.5 cargoes in Tortue last year. We're targeting a range of 32 to 36 cargoes, the question from Charles. So the volumetric effect is obviously significant, yes. That combined with around a 10% overall reduction in operating costs year-on-year. Some of that's coming from operations, some of it's coming from the FPSO refinancing. The 2 combined give you a greater than 50% reduction on an MMBtu basis.

Your next question comes from the line of David Round with Stifel.

Can I start with Ghana, please? Because you've always talked about that being your best return on capital, but specifically, it's always been around Jubilee. So I just wonder whether the TEN FPSO purchase changes that thinking. And if it does, when we could see a well or whether you're in a position to even think about that at the moment? Second one, just on Jubilee. Andy, I think you mentioned the 10,000 barrels a day for a typical well. And to be fair, you guys have always been pretty consistent around that. And I think that's precannibalization. The J74 is actually nicely above that level. So I'm just wondering if there is anything exceptional about that well and any reason why we shouldn't hope for, let's say, that the next wells could also deliver at that kind of rate?

Yes. Okay. Thanks, David. If I take the TEN question first. Yes, clearly, lowering the breakeven of the asset through the FPSO purchase does create a longer economic life for the field, which is important. But the other thing that we're doing is we have shot of 4D and OBN over TEN. So we're -- it's actually been focused on Jubilee first to build a drilling program for Jubilee. But as you look to '27 and '28, yes, I think there's a potential for a well in TEN on the basis of being able to bring in the enhanced seismic imaging from the NAS and the OBN.

And that in combination with the lower operating cost of the asset, will the economics there will be competitive against Jubilee. And that's ultimately what we're trying to do. And I think I want to reinforce the comments that we made in the script around the quality of the economics of the Jubilee wells. They're paying back -- last 12 wells paid back the average. That's with all the ups and downs in around 9 months in the last 2 wells, I think closer to 6.

So it's a very strong opportunity set that we see in Jubilee. And therefore, I believe that there is a competitive well in TEN, but the work on the seismic will enable us to uncover it. Yes. In terms of the higher rates, I think the point to note, David, is that we've gone back to the core of the field, yes. So the J72, J74 and then J75, which is the next well that we're currently completing now that will be on before the end of the quarter, they're in the main part of the field where we know we've got good pressure support. We know we've had productive horizons. And these are fundamentally bypassed oil pockets. And they are being illuminated by the seismic.

So again, we want to be appropriately measured about the forecast. But I think J75, we had 40 meters of pay. It will be a 3-zone completion, similar to J72. So I think we're going to see somewhat similar to J74. So we're going to -- we should see strong performance from that well. So are there more 10,000 barrel a day wells in the field? Absolutely, yes. And I think that's the point to take away. And they come with good reserves and therefore, very strong economics.

Very quick one on GTA, while I've got you. Can you just remind us how anything over 2.5 million tons is priced, please? Is it along the same...

Yes. Great, David. Yes, sorry I didn't mean to cut you off. Yes. No, exactly. It's 2.45 million tons per annum, that's what I was going to say. It's 2.45 million tons per annum, the contract with BP. So everything that's above that is sold under that contract. Yes, it's exactly the same pricing, yes.

Your next question comes from the line of Christoffer Bachke with Clarksons Securities.

This is Christoffer from Clarksons. First of all, congrats on an eventful quarter and some strong recent months. I have a couple of questions, so I'll just take one at a time. First question is related to the RBL, which is currently secured against Ghana and the recently divested EG stake. Could you give some color on how the license extension in Ghana are affecting the borrowing base? And will that extension alone replace EG, so to say?

Yes. So we're -- we've just started the RBL process. Again, I think the RBL, like you said, is underpinned by the Ghana reserves in EG. We'd expect for March for both pieces still to be in there. And then as the transaction closes in Q2, then the EG portion will be -- will come out. And so again, there will be some impact in terms of the borrowing base from EG. We had roughly plus or minus $100-ish million of impact, but we were well overcollateralized from a Ghana perspective. And again so I think net-net, you won't see much impact from EG in 1Q. But clearly, by the time we pull it -- we close the asset sale in midyear, there'll be an impact to the RBL as a result of that transaction.

My second question comes following the EG divestment as well. How do you think about further divestments versus holding assets like Tiberius into FID? And is the portfolio now largely set for a harvest phase in your view?

Yes, maybe I'll take that, Christoffer. Look, I think a key theme coming out of the -- hopefully, out of the prepared remarks and the slides is we're on a journey to create a lower-cost business. And we've talked about the -- as it were the organic portfolio as it sits today, more than $100 million of cost coming out. And when you put EG onto that on a pro forma basis, it would be another probably gets you closer in aggregate to about $250 million.

So really, we are building that lower cost portfolio. And clearly, on a per BOE basis, it's a significant reduction. Sort of where next, it has to be things that are really sort of not core to the future where we don't see growth, we see potentially higher costs, and we'll continue to look at those assets. At the same time, we're redirecting the capital that we would have spent on the more mature higher cost assets. We're redirecting that to growth.

Clearly, the growth in this year is targeting the very strong economics in Jubilee. And then as we look out beyond into '27, '28, yes, you're right. Tiberius is an important growth project for us in the Gulf. So I think the messages are really around very, very strong focus on cost to build that lower-cost sustainable business, very strong reserve base, yes. And then associated with that is rigorous allocation of capital to the highest return projects and with a very lean capital base in '26 to enable us to do that. So yes, there will be, I think, on the margin, some continuing trimming of the portfolio, but we've got a very strong set of core assets, and those assets will continue to deliver growth.

My third and last question, if I may, is also related to GTA. You're guiding to more than 50% year-on-year unit cost reduction in '26. Can you please help me understand what kind of the steady-state cash OpEx per MMBtu looks like at, let's say, 2.7 mtpa to 2.9 mtpa? And how much of that reduction comes from the FPSO refi versus kind of operational efficiencies?

Yes. So if you look at it, the big driver initially is in the step-up in volume. And we have a chart in the pack that shows the absolute numbers. They're on the chart on slide.

Maybe if I answer the question in a different way, Christoffer, when you look at sort of just the absolute cost reduction in '26 versus '25, about half of that is the FPSO refinancing and half of that is that sort of the start-up cost piece coming out. And as Andy alluded, sort of there's more to go on the operating costs from a pure perspective to pull out of the system. And then while the changes are slightly larger than that, there is a slightly increased FLNG toll just because we're pushing more volume through the Golar vessel and they get paid on a per molecule basis. So net-net, for those 2 are a little larger than 10%. But when you include the FLNG higher toll, it sort of gets to around 10% on the total into '26, then you should see a further reduction into '27.

Yes. And the actual numbers are shown there on Slide 9. But again, I think what I'd add to that, Neal, is as you sort of there's no required investment really to deliver up to the $630 MMscf/d, which is the additional increment from the domestic gas. So as that starts to come through on Phase 1+, you see another step down in the net OpEx per dollar per MMBtu.

Your next question comes from the line of Stella Cridge with Barclays.

There was 2 things, if I could ask, please. And the first is on Tiberius. When you're talking about the farm down, is the idea that the new partner covers their kind of pro rata share of CapEx? Or just if you could just talk us through how that transaction might work? And then secondly, I was just wondering how you were thinking about the amortizations on the Shell loan? And what would be your base case for addressing those? That would be great.

Stella, I'll take those. In terms of Tiberius, yes, when we and Oxy will both look to sort of farm down, we're about -- we're both 50-50 partners today. And the goal is to get sort of a third partner in there. Is that 1/3, 1/3, 1/3. And so the idea is that they clearly pay their own capital cost, and there's some back cost and then potentially some additional consideration. So that's sort of the structure that we're looking at post sort of FID to bring in that partner.

In terms of the Gulf term loan perspective, again, I think we talked about today sort of getting net debt down by about by at least 10% in calendar year '26. About half of that is through sort of the EG sale and the other half is through generation of free cash flow across the business in sort of a, call it, mid-60s type oil price. And so again, sort of the Gulf term loan amortization is sort of a little over $50 million this year. We'd expect to pay that out of cash flow generated from the business.

And your last question comes from Mark Wilson with Jefferies.

I'd like to ask actually a follow-up for that Tiberius question. Certainly, the Gulf of America did seem the most material new information I felt from this. And so following on from that, the results talk to an FID and farm down in the first half. So we're pursuing those two situations in parallel. Those would be the -- that would be the first question. Should we consider an FID and a farm-down are things that come together, one and the same?

Yes. So Mark, I think that they're more sequential. And again, we've sort of -- we're close to -- again, as operator, we've moved down the development or FID path pretty far, and we're sort of close to getting that sanctioned. And then we'll kick -- yes, and we've talked -- clearly talked to a number of people around the farm-down we'll kick off a process here quite shortly. And again, there's not a -- it should be a fairly attractive clean project to bring in the third partner. And as you've seen, just generally in the Gulf of America, there's been a lot of interest around people participating in new developments in new cost competitive large resource projects. So again, we're not -- we think there'll be a lot of interest as we conduct a relatively short process.

And then the other new information in the Gulf is this strategic alliance with Shell. You talked about being aligned across 10 blocks now. Just -- would just like to know, is there anything within that call it strategic alliance beyond involvement in licenses, any kind of carry or information share, et cetera?

Yes. So Mark, I'll take that. So as you know, we've had a long, good working relationship with Shell. A few years ago, we sold them our exploration assets across the portfolio in terms of the frontier licenses. We signed the term loan with them in the Gulf. And for a couple of years now, we've been having sort of an ongoing conversation around how we can collaborate in the Gulf.

And clearly, they're the largest producer in the area, and they have access to a bunch of infrastructure, which as we push forward our strategy around ILX in the Gulf, having access to infrastructure is clearly helpful. And so we've been discussing for some time in terms of how can we put together our capabilities to create sort of a mutual benefit for both companies.

And so we agreed sort of alliance to start here around the Norphlet trend. We had some prospects. They had some prospects in and around Appomattox so that made sense to combine and then basically work to jointly develop that infrastructure and actually creates a good partnership where, again, I think we can use both companies' capabilities, their's around sort of drilling and production, ours on the sort of accelerated development path to create value for both companies. And so again, I think that there continues to be more that we can do together, and we're happy to sort of formalize sort of the first step and continue to move things forward.

And if I could add, Mark, it's not just about the license exchange. There is a commitment to drill Tiberius, which is the high rank prospect actually between us in early '27. And again, it's about a theme really about ILX. So this is Norphlet, but it's ILX around Appomattox where there is [indiscernible] available on the host platform there. So no, I like the coming together.

Actually, they've obviously got a huge knowledge of Norphlet development. So being able to leverage their knowledge onto our prospects has been great. And clearly, for them, it's about finding how they sort of high grade and create a larger inventory to drill. So yes, lots to do now. And again, we look forward to updating you on Tiberius when we get started -- Trailblazer when we get started.

Yes. No, Trailblazer -- understand that. And then just one point, a bit of a housekeeping here. On your group production guidance, the 70,000 boe to 78,000 boe, can we -- could you just let us know where EG sits in that, is there a number...

Yes, I'll let Neal give you the exact.

Yes, thank you.

Yes. So it is dug in the footnotes, But Mark, it's about 6,000 barrels a day in the guidance on average is contributed to EG. And so again, it's in the full year guidance. What we'll do is, again, given the uncertain closing time in terms of what -- does it close exactly in 2Q, 3Q. What we -- what we'll do is we'll reissue guidance. But we've broken out the components in the footnote there so that you can make an assumption around what that is and therefore, the impact to the full year depending on when it closes.

And equally true, all the costs from EG are in the year as well...

Correct, yes.

Mark. So when it's closed, we'll have -- yes, some production will come out, but also some costs will come out.

The costs...

Chunk of costs will come out of the business.

Thank you. And with no further questions in queue, that concludes our question-and-answer session. Thank you all for joining. You may now disconnect.

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.

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