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.

Thank you, Jamie. Good morning and afternoon, everyone. I appreciate you joining us for our third quarter results call. I will begin by discussing Kosmos' priorities and reiterating the key points I made last quarter, followed by an update on our portfolio's progress. Neal will then provide details on the financials and our recent efforts to strengthen the balance sheet, after which I will conclude with some final thoughts. We will then move into the Q&A session. As we deal with ongoing commodity price fluctuations, our main priorities have remained consistent. In our previous quarters, I emphasized the importance of increasing production and reducing costs to focus on free cash flow while also bolstering our balance sheet. We have made significant strides in all three areas this quarter. Regarding production, we brought the first producer well of the 2025/26 drilling campaign online at Jubilee in July, achieving gross production of approximately 10,000 barrels of oil per day. The drilling rig has returned to Ghana after scheduled maintenance and has just started the second producer well in this campaign, which we expect to come online by the end of the year. Thanks to increased drilling efficiencies, we have expanded the number of wells in the '26 drilling campaign from four to five without exceeding the original budget. At GTA, production growth continues, with our partnership having lifted 13.5 gross LNG cargos through the end of October, including the first condensate cargo, which represents a new revenue stream for the project. By year-end, we aim to reach the FLNG nameplate capacity of 2.7 million tonnes per annum. In the Gulf of America, production remains strong as we also advance future developments like Tiberius and Gettysburg. In Equatorial Guinea, we anticipate increased production as our partnership has begun installing repaired subsea pumps at Tiberius. We have completed the first pump installation, the second is on-site, and the third is expected to arrive in the first quarter of 2026. We are excited to see production nearing record highs for the company, with further growth expected each quarter through 2026 as we ramp up GTA towards nameplate capacity and bring on additional Jubilee wells. Now, regarding costs, we are strategically focused on three areas and making solid progress. First, our capital expenditures continue to decline, and we now expect them to fall below our $350 million forecast for the year, representing a year-on-year reduction of around $500 million. Second, for overhead costs, we remain on track to achieve the targeted savings of $25 million by year-end, with full benefits occurring in 2026 and beyond. Third, we are reducing operating costs across all sectors. As mentioned last quarter, the biggest potential for further operational expenditure reduction lies with GTA, where we are observing improved unit costs as production increases and costs decrease. We are aiming to refinance the GTA FPSO by year-end and are collaborating with the operator to implement a cost-effective operating model, which should further lower costs across the project. On the balance sheet front, we have made several important moves recently. To bolster our liquidity, we secured a $250 million term loan from Shell, which we will use to pay off our 2026 bond maturities. We also successfully completed the semi-annual re-determination of our RBL in September and passed the maturity test for the 2027 bonds simultaneously. Additionally, we added more hedges for 2026 during this period. Neal will provide more detailed information on these developments later. In summary, we are making progress toward our financial goals. The combination of increasing production, reducing costs, and a lack of near-term debt maturities positions us well to navigate periods of volatility. I remain optimistic about our unique, world-class portfolio of assets and our commitment to maximizing long-term shareholder value. Moving to operations for the quarter, total net production in Ghana was about 31,300 barrels of oil equivalent per day. Jubilee's gross oil production for the third quarter reached around 62,500 barrels of oil per day, a 13% increase from the previous quarter, aided by the first new well of the 2025/26 drilling campaign coming online in July. Gross gas production was approximately 15,000 barrels of oil equivalent per day in the third quarter, slightly lower due to extended scheduled maintenance of the onshore gas processing plant. At TEN, gross oil production for the quarter was around 16,000 barrels of oil per day. For GTA in Senegal and Mauritania, third quarter net production was around 11,400 barrels of oil equivalent per day, which marks an increase of just over 60% from the previous quarter. The partnership lifted 6.8 gross LNG cargos during the quarter as planned, and we also transported the first gross condensate cargo early in the fourth quarter. Some startup maintenance on three of the four LNG trains during the third quarter slightly limited production, but with all trains now online, we are achieving approximately 2.6 million tonnes per annum equivalent and are on track for nameplate production this quarter, with work on the last LNG train scheduled for this quarter, included in our guidance. In the Gulf of America, net production was around 16,600 barrels of oil equivalent per day, in line with guidance, due to robust performance from Odd Job and Kodiak, with no major storm incidents during the quarter. Some unplanned facility downtime and the abandonment of the Winterfell-4 well did impact production, which I'll elaborate on in a later slide. We have executed a production handling agreement with Oxy, our 50-50 partner and operator of the Lucius production facility, which will manage the volumes from the upcoming development. We plan to take FID and reduce our interest to about a third by 2026. In Equatorial Guinea, net production was around 6,200 barrels of oil per day, which is down from the previous quarter due to the subsea pump issues mentioned in May. We are making progress on repairing those pumps, and we expect normalized production in the first half of 2026. We discussed Jubilee in detail last quarter, highlighting the chance to unlock the field's full potential as we resume drilling. The initial well of the 2025/26 drilling campaign was drilled in the second quarter and became operational in July, continuing to perform as expected, producing approximately 10,000 barrels per day of gross oil. The drilling of the second producer well has started, and we anticipate it will also be a strong producer once it becomes operational near the year’s end. The next 12 months will be critical for this field, with a committed drilling program for five additional wells in 2026. While we initially planned to drill four producer wells next year, we've collaborated with our partners to create a more efficient plan, allowing for the inclusion of a fifth well, which will be a water injector, all while remaining within the current budget. The chart indicates that production may see an increase through 2026 as new wells come online. Although this upward trend won't follow a straight path, given that individual wells will contribute varying production volumes, we foresee Jubilee production significantly exceeding current levels by the end of the drilling program in late 2026. We plan to maintain sustained production at these elevated levels through improved water injection and regular follow-on infill drilling. Another significant point highlighted in the chart is the OBN seismic acquisition currently taking place this quarter. This cutting-edge imaging technology, which I mentioned last quarter, will enhance our understanding of the subsurface, yielding better data on historical fluid movement and aiding in locating additional undrilled lobes and unswept oil. This advancement in imaging technology is expected to facilitate optimal well selection for future drilling campaigns, ultimately boosting resource recovery throughout the field's remaining lifespan. With the license extension anticipated by year-end, our partnership can now focus on long-term investments in Jubilee, likely leading to a meaningful increase in 2P reserves. All documentation required for the extension has now been prepared for submission to the government for 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 refinancing 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. 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 acknowledge the resource upside at Winterfell, which contains around 100 million barrels of 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 Equatorial Guinea, 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 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.

Our first questions come from 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 upfront. 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. I think 2025 is a challenging year to establish a baseline. Looking at the quarterly operating expenses, we had $70 million in the second quarter, $60 million in the third quarter, and we expect around $50 million per quarter net to Kosmos in the fourth quarter at the midpoint of our guidance. Beyond that, we anticipate potential for either an increase or decrease in operating costs as we aim to operate at a slightly lower cost into 2026. Currently, we are around a breakeven point of approximately $6 per million from a production perspective, with the aim of reducing that figure further.

A follow-up on any lessons learned from Winterfell. Is there a common theme among some of the challenges, or is it too early to tell?

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 an 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 low-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 overall cost structure. So again, I think we're doing the right things in the business and 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.

Can you discuss the upfront investment needed for the GTA expansion? Also, how do you view the differences in leap rates for a 5 MTPA floating LNG facility compared to the Golar facility you had previously?

Thank you, Neil. That's a really important question. I just returned from a meeting last week in Paris, where we engaged extensively with the national oil companies and governments of Mauritania and Senegal to discuss future needs. It's evident that both countries, especially Senegal, require more domestic gas in the near term. We envision the next phase, known as Phase 1+ expansion, focusing on the domestic market. The pricing isn't a primary concern for us; we're looking at prices similar to the FOB of LNG minus the liquefaction costs. This setup benefits everyone involved: the government gains a competitively priced source of gas, while we can proceed with the Phase 1+ expansion without the need for complex redesigns of existing facilities. On the cost side, the FPSO and current well stock can provide about 200 million standard cubic feet of additional gas at no cost, which means the government could access domestic gas sooner. They are working on building the necessary infrastructure, including a pipeline system to connect power stations that will be either newly built or modified for gas use. They believe they could potentially increase their demand for gas before the previously mentioned 2029 timeline. During our discussions in Paris, we also considered starting early negotiations for a gas sales agreement. To break it down, there's an immediate potential for 200 million cubic feet at no cost, and an additional 100 million cubic feet could be secured through minor modifications to debottleneck the FPSO. The remarkable aspect of GTA is that it can be expanded at a minimal cost, with no additional expenses beyond debottlenecking the FPSO. Eventually, more wells will be required, but that will be in the future. Our focus is on collaborating to maximize infrastructure use with the least capital investment while ensuring that host countries reap significant benefits, ultimately creating a true win-win scenario. Therefore, I see the initial expansion, Phase 1+, as being geared more toward domestic gas, while later phases may lean more towards LNG. There are also opportunities to enhance the Gimi production beyond its current nameplate capacity, resulting in a small increase in LNG output. In summary, this plan involves very low capital expenditures overall.

Our next questions come from 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 to discuss, Chris. I'll address the first point regarding Jubilee and then pass it over to Neal. For Jubilee, it’s important to keep things simple. Currently, we're producing around 62,000 to 63,000 barrels of oil per day. We just started drilling a new well, specifically the 26 in section, and we're glad to be back on track with our timeline. We expect this well to be operational by the end of the year, bringing our exit rate for Jubilee to approximately 70,000 barrels per day. Looking ahead to 2026, we have four additional producers to drill, which we estimate will yield between 5,000 and 10,000 barrels per day each. If we take an average of around 7,500, that would put us at about 100,000 barrels a day, before factoring in the decline rate. Assuming a decline rate of 20%, which may be slightly high overall, this would reduce our production to the 80s. We anticipate reaching that rate as the year progresses. We have a clear plan moving forward, with well selection focused in key areas of the field where we expect good pressure support. In the past, we faced challenges in the Jubilee Southeast area due to fewer injectors, which impacted connectivity. Thus, while discussing decline rates, we need to consider both the location of the wells and the pressure support as well as the differences in production between new and existing wells. We have key aspects to monitor going forward. Yes, we've started drilling, and our goal is to get the new well producing by the end of the year, then gradually ramp up production as we complete more wells. By 2026, we aim to have 12 producers. We've also refined the program to fit in a water injector, which is vital for the next phase, all within the original 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?

I don’t want to repeat everything I mentioned in response to Neal's question. Referring back to your last inquiry about FID timing, I want to emphasize that we can secure an additional $200 million of gas today without any expenditure. No FID is needed for this; the key factor is signing a GSA, which was a significant action item from the discussions in Paris with the NOCs and the government, particularly in Senegal, who want to speed up the process due to strong domestic demand. The President and Prime Minister have underscored the significance of obtaining domestic gas, making this a beneficial situation for all parties involved. This additional gas comes without incurring extra costs. However, securing the last $100 million will require us to do some work on the FPSO, specifically the FEED work. We anticipate that FID may occur within the next 12 months. We need to complete tasks for the 2028 turnaround, which necessitates lead time. The additional $100 million would be accessible in 2029 when the FPSO undergoes a normal shutdown for the necessary work. Regarding Guinea, we're aiming to reach nameplate capacity, and I believe we are making month-to-month, quarter-to-quarter progress to achieve that goal by the end of this year. To exceed nameplate capacity, modifications to the Gimi will be necessary, focusing on enhanced cooling and added power, which are critical for LNG plants. This work is currently underway with Golar. I won’t provide a specific figure until we finalize that work, but the increase might range from roughly 10% to 20%, depending on the outcomes. Improvements to the Gimi depend on these two factors: power and cooling. Ideally, we would implement these enhancements during the turnaround period alongside the FPSO work. Thus, I won’t include any projections until around 2029.

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 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.

Yes, Kay, we have had a strong start to the first month. We have a clear understanding of what October was like and we're operating well within the guidance for the fourth quarter. Instead of focusing on the downside that could lead us to hit $66, I want to emphasize what we need to achieve to reach the upper end of that range, which is definitely our goal. We aim to deliver results firmly within the range for the fourth quarter, and so far, we are off to a strong start this 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.