Kosmos Energy (KOS) Q3 2025 Earnings Call Transcript

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DATE

Monday, Nov. 3, 2025, at 11 a.m. ET

CALL PARTICIPANTS

• Chairman & Chief Executive Officer — Andrew G. Inglis
• Chief Financial Officer — Neal D. Shah

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RISKS

• Gross gas production in Ghana declined sequentially due to extended scheduled maintenance of the onshore gas processing plant.
• The Winterfell 4 Well in the Gulf of America was abandoned in September following production casing collapse and operational challenges.
• The company remains close to its revised year-end leverage covenant and is actively pursuing solutions.

TAKEAWAYS

• Jubilee Gross Oil Production -- 62,500 barrels per day, representing a 13% increase quarter on quarter after the new well came online in July.
• Ghana Net Production -- 31,300 barrels of oil equivalent per day, with current production in the low 70,000s, and another well expected online by year-end.
• GTA Net Production -- 11,400 barrels of oil equivalent per day, rising over 60% sequentially, with 6.8 gross LNG cargoes lifted, and total project liftings reaching 13.5 cargoes through October.
• GTA Condensate Cargo -- First gross condensate cargo lifted in early Q4, introducing a new revenue stream, and distribution to partners on entitlement basis going forward.
• Gulf of America Net Production -- 16,600 barrels of oil equivalent per day, powered by Odd Job and Kodiak performance, partially offset by unplanned facility downtime and the Winterfell 4 Well abandonment.
• CapEx -- $67 million in the quarter, coming in lower than guidance, with year-to-date CapEx under $240 million, and full-year CapEx now projected below the $350 million forecast.
• Operating Costs -- Declined nearly 40% quarter on quarter, with progress evident across all business units, and particular reduction in GTA unit costs as production ramps.
• G&A -- Lower in the period, reflecting ongoing overhead reduction efforts, and on track for the targeted $25 million in annual savings by year-end.
• GTA Unit Operating Costs -- Currently trending at $60 million per quarter net to Kosmos, with further reduction to $50 million per quarter expected in Q4, and targeted over 50% unit cost reduction in 2026.
• Borrowing Base -- RBL semiannual redetermination completed with borrowing base exceeding the $1.35 billion facility size, and successful passage of the 2027 bonds' liquidity test.
• Liquidity Actions -- $250 million senior secured term loan from Shell arranged, with first tranche repaying $150 million of 2026 unsecured notes early in Q4, and the balance earmarked for the outstanding $100 million due in 2026.
• Hedging Portfolio -- 2.5 million barrels hedged for remainder of 2025 ($62 floor/$77 ceiling), and 8.5 million barrels hedged for 2026 ($66 floor/$73 ceiling).
• Jubilee Drilling Campaign -- Number of planned wells for 2026 increased from four to five through efficiencies, with program remaining within original capital budget.
• GTA Phase One CapEx -- Major working capital outflow marks the end of capital spend for Phase One, with no material capital outflows at GTA expected for several years.
• FPSO Lease (TEN) -- Purchase option moving forward with expectation of no additional lease payments until closeout in 2027, when a reduced buyout payment is anticipated; expected material reduction from current $60 million annual FPSO lease cost.
• Production Guidance -- Fourth quarter production expected in the 66,000-72,000 barrels per day range, with some allowance for planned and unplanned downtime, and targeted achievement at higher end of guidance.
• OBN Seismic Acquisition -- New state-of-the-art survey underway at Jubilee, expected to enhance subsurface understanding and future well selection, with management noting a license extension is being prepared for submission.

SUMMARY

Kosmos Energy (KOS +0.00%) achieved record or near-record production, driven by new well contributions at Jubilee and the continued ramp-up at GTA, while accelerating cost reductions across operating, overhead, and capital expenditures. Strategic refinancing initiatives, including the Shell term loan and redetermination of the RBL facility, extended debt maturities and addressed the most urgent near-term financial obligations. Substantial progress on overhead reduction and operational efficiency supported the ability to self-fund ongoing drilling campaigns without exceeding previous budget forecasts. The transition from project delivery to steady-state operations at GTA reduces future capital requirements, while improvements in unit operating costs position the asset for further margin expansion in 2026.

• Shah confirmed, "production is growing and approaching record high levels, while CapEx, OpEx, and overhead have all fallen quarter on quarter."
• Inglis explained, "With improved water injection and a regular follow-on infill drilling program, we're targeting sustained production at those higher levels."
• The company intends to monetize non-core assets for additional debt reduction, as Inglis stated, "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 and the Gulf of Mexico. So what are the options we have now to high-grade the portfolio and use that as an additional source of debt reduction? I think that's another area where we're being proactive."
• Winterfell lessons led to management refocusing 2026 activities solely on restoring production from the Winterfell III 4 block, with simplified completions and a rigorous operational approach.
• Expansion at GTA Phase One Plus targets near-term domestic gas markets, with management highlighting "no additional cost to go in other than the FPSO debottlenecking," according to Andrew G. Inglis, and capacity to supply around 200 million standard cubic feet per day without additional investment.

INDUSTRY GLOSSARY

• FPSO: Floating Production, Storage, and Offloading vessel used for offshore oil and gas field production and storage.
• RBL: Reserve-Based Lending, a type of credit facility secured by the value of the borrower's oil and gas reserves.
• GTA: Greater Tortue Ahmeyim, a major LNG and gas development project offshore Mauritania and Senegal.
• OBN Seismic: Ocean Bottom Node Seismic, an advanced seismic imaging method providing high-resolution subsurface data for reservoir management and drilling optimization.
• 2P Reserves: Proved and Probable reserves, representing the best estimate of hydrocarbon quantities recoverable from known reservoirs.

Full Conference Call Transcript

Andrew G. Inglis: Thanks, Jamie, and good morning and afternoon to everyone. Thank you for joining us today for our third quarter results call. I'll start off the call by taking you through Kosmos Energy Ltd.'s 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 done recently to enhance the resilience of the balance sheet, before I wrap up with closing remarks. Then open up the call for Q&A. Starting on Slide three, 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 cost to prioritize free cash flow while continuing to strengthen our balance sheet. We made important progress across all three of these areas this quarter. Starting with production. At Jubilee, the partnership brought the first producer well of the 2025-2026 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 2026 drilling campaign from four to five, while staying within the original budget, which I'll talk more about shortly. On GTA, production has continued to ramp up with the partnership listing 13.5 gross LNG cargoes through 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 tons per annum. In the Gulf of America, production remains consistently strong, and we continue to progress future developments such as Tiberias and Gettysburg.

And finally, extra organic production is set to increase with the partnership installing repaired subsea pumps at Sabre, with the first pump complete, the second in-country, and the third due to be delivered in 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, operating costs are 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 costs 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. And 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 maturity. On the RBL, we successfully completed the semiannual redetermination 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 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 four, which looks at operations for the quarter. Starting in 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 2025-2026 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 listed 6.8 gross LNG cargoes during the quarter, in line with guidance. We also lifted the first gross condensate cargo early in the fourth quarter. There was some start of maintenance on three of the four LNG trains during the third quarter, which slightly curtailed production. But with all trains online, we're now running around 2.6 million tons 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 into 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 on a following slide. On Tiberius, we executed the production handling agreement with Oxy, our fifty-fifty 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. Next, organic 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 2026. Turning to Slide five, the opportunity to deliver the field's full potential as a return to drilling. 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. We anticipate it will also be a strong producer. The next twelve months is an important period of activity for the field, with a committed drilling program of five more wells in 2026. Initially, we planned to drill four producer wells next year, but have worked with the partnership to drive a more efficient program that allows for a fifth well awarding injection to be added in 2026 while maintaining the same budget. The blue dots on the chart show production moving 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. The 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 movements and helping identify more undrilled loads 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 a license extension expected to be completed by year-end, the partnership can now plan on long-term investment in Jubilee, which should drive material uplift in 2P reserves. All the required documentation of the extension is now being prepared for submission to the government for their approval. Turning to Slide six. At GTA, we continue to see a lot of positive progress as we work with BP, the national oil companies, and the government to improve profitability.

As the green line of 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 cargoes 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 listed 13.5 gross cargoes through October, with seven to 8.5 cargoes expected in the fourth quarter. Last month, the first gross condensate cargo was listed, another important milestone for the project, and was priced at a small discount to 2.7 million tons per annum nameplate towards the end of the year.

At 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 cost, 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 costs to fall by over 50% next year. That said, we continue to advance Phase one plus 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.

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 halfway for Phase one of the project. Turning to Slide seven, in the Gulf of America, third quarter performance was in line with expectations, with a continued strong performance from Oddjob 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 loaned 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 III 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 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, which is a discovered resource opportunity we acquired in a previous lease sale. We're progressing a single well development that would be tied back to Shell's operated Appomattox platform. That concludes the review of the portfolio. Neal will now take you through the financials.

Neal D. Shah: Thanks, Andy. Turning now to Slide eight, 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 seventies, 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 cost 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 one 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 nine. 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 four-year senior secured term loan with Shell for up to $250 million with attractive terms for Kosmos Energy Ltd. 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 2026. On the RBL facility, we completed the semiannual redetermination with the borrowing base remaining in excess of the $1.35 billion facility size. Alongside that 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 product 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 enable 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 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. We've talked on today's call about our focus on cost, 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, backward 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 twelve-month leverage calculation. As you will see with our fourth quarter guidance, we remain close to our revised year-end covenant and are actively working on 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've made, and we will continue to focus on the delivery of that agenda.

With that, I'll hand it back to Andy.

Andrew G. Inglis: Thanks, Neal. Turning now to Slide 10 to conclude today's presentation. As I stated in my opening remarks, we have three clear near-term priorities. 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 and 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 cost, we're seeing solid progress across our three main areas of focus: CapEx, OpEx, and overhead, and continue to work hard on further reductions.

And 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: Thank you. We will now be conducting a question and answer session. Our first questions come from the line of Matthew Smith with Bank of America. Please proceed with your questions.

Matthew Smith: Thanks for taking my questions. Perhaps a couple. Could I first start with the reference to the 10 FPSO, the sedumary 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'd be the first one. And then perhaps the second one, sort of taking a step back, I guess, the 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 already the cash flows and perhaps the deleverage that you might expect for 2026?

Neal D. Shah: Yes. Sure, sure, Matt. This is Neal. I'll take those. So if we start on ten, one of the themes we talked about today is sort of reducing the costs 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 6% of the operating cost of 10%. And so it's been naturally an area for us and 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 or 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 payback similar to what we've seen on M&A transactions like Oxygen, etcetera, that we've looked at. And so no additional cash upfront. We sort of have the lease until 2027.

We have a discounted purchase option at that point, which lowers the operating cost and allows us to get access to 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 where production quarter on quarter we can see it increasing and costs across the business are coming down.

Again, in terms of where we get to in terms of free cash flow into 2026 and beyond, don't think it's very different in terms of what we've just said. We've talked about it as a company that can break even in the mid $50 per barrel range across all of the cost. 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's some price floors at rates ahead of that, which ensure that we're generating some free cash flow into 2026 and then have the optionality in the portfolio for the future.

Again, 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 fourth quarter and sequentially into subsequent quarters into 2026.

Matthew Smith: Got it. Thank you, Neal. Appreciate the detail.

Neal D. Shah: Great. Thanks, Matt.

Operator: Thank you. Our next questions come from the line of Bob Brackett with Bernstein Research. Please proceed with your questions.

Bob Brackett: 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 talk about taking half of that roughly away. Is that the right way to think about it, getting toward $30 of OpEx?

Neal D. Shah: Yes. So again, I think 2025 is a tricky year to baseline off of, Bob. If when you look at sort of the quarterly OpEx, we were 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, see upside or downside in terms of being able to run into 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 MMBtu breakeven on just where we are from a production perspective with the goal to get that a bit lower.

Bob Brackett: Very clear. And I'll follow-up. Any lessons learned on Winterfell? Is there a common theme to some of the challenges, or is it too early to know?

Andrew G. Inglis: Yeah. Bob, I'll take that. I think the first thing to say, these are operational issues, not reservoir issues, yes? So we've had two mishaps. You know, the first was placing the screen in the horizontal. You know, it wasn't fully packed off. And therefore, we had screen collapse. So that's one issue. I think the issue of the casing collapse sort of long exit itself actually is a little early to come to a final conclusion on the root cause. But what it does mean when you step back from it is we need to be very, very rigorous now about the future operations.

We are, as Kosmos, focusing on a single activity in 2026, which will be coming back to the Winterfell III Fault Block, probably reusing 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 the 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.

Bob Brackett: Very clear. Thanks.

Andrew G. Inglis: Right. Thanks, Bob.

Operator: Our next questions come from the line of Charles Meade with Johnson Rice. Please proceed with your questions.

Charles Meade: Yes. Good morning, Andy and Neal, and to the rest of the Kosmos team. Andy, on slide five, I thank you for all this detail on Jubilee. But I want to ask a question about what's going to drive two cargoes versus three cargoes from Ghana in 4Q. Is it just the big variable the performance or how well this J-seventy-two well holds up, or is there a 10 cargo that may or may not fall in April? Can you give us a sense of what the drivers are there?

Andrew G. Inglis: No. But no, Charles. It's just really 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 also 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 around literally around the timing effects of that on a year-end cargo.

Charles Meade: Okay. Great. And then, another cargo question, but from a 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?

Neal D. Shah: Right. I'll let Neal handle the detail of that. Yeah. And it's a bit tricky because you don't get them all the time. Probably lifting on a gross basis out of the field maybe quarterly, but this is the first one to the partnership until we split it evenly. Again, thinking going forward is they'll all be allocating on a sort of an entitlement basis going forward. And so, again, I think between us and the NOCs potentially lifting every, you know, one out of or two out of every five condensate cargoes. So it'll be a bit irregular, Charles. But, you know, there will be, you know, again, a nice source of additional income for the partnership.

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

Neal D. Shah: No. No. 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 lift it like, as you mentioned, which is sort of taking turns between us and the NOCs.

Charles Meade: Okay. Great. Thanks for the detail.

Operator: Next questions come from the line of Neil Mehta with Goldman Sachs. Please proceed with your questions.

Neil Mehta: Yes. Good morning, Andy. Good morning, Neal. You know, there's been obviously a lot of focus on the balance sheet and credit hasn't traded very well here because of macro, but also because of some of the challenges you guys talked about. So maybe you could just take some time to, for investors who are worried about the balance sheet, to talk about how you're feeling about liquidity, why you have confidence, what are you doing to mitigate some of the risks, and then spell it out in good detail.

Andrew G. Inglis: Great. 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 this quarter. Neal will talk you through the GOM Term Loan, the RBL redetermination. That's allowed us to deal with the most immediate issue, which is the 2026 bond maturity. 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 close 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.

Neal D. Shah: Yeah. And just, yeah, like Andy said, I think, you know, we continue to be proactive in terms of getting ahead of financing, getting in front of the refinancing issues. And so, you know, we've, you know, the Shell term loan was important to get early, you know, to early repay the 2026s. Yeah. We've gotten through, yeah, we've gotten through the redetermination liquidity test that where people have some questions around that hopefully have addressed some concerns on that side.

Then now we're being proactive around the 2027s and looking at, you know, as I mentioned, secured debt options, you know, potentially at the MS level to early attack, clear the maturities and create a bit of runway so that we can focus on, you know, with the near-term volatility in the oil price. You know, 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 to that process. You know? 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, you know, we're finishing up 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 the overall cost structure. Again, think we're doing the right things in the business. We'll 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.

Andrew G. Inglis: Yeah. What I'd add just, Neil, is in addition to looking at, you know, 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 and the 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 two big agenda items that Neal is working on, both secured debt against MS and the non-core assets.

Neil Mehta: Yeah. Thanks, Andy. That was very thorough. And 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?

Andrew G. Inglis: Yes. No. Thanks, Neil. I think it's sort of maybe that is an important question. I think it'd be good to give you a little bit of detail. Yeah. I'm fresh back from a meeting where, like last week in Paris, where we spent a lot of time with the NOCs and governments of Mauritania and Senegal sort of thinking through their 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 I plus 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 costs. 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 one plus without having to go through complicated redesign of the facilities. So I think that's the way to think about it, Neil. And I think the other thing that I'd add to you on the 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 zero investment, yes?

And that means that from the government's perspective, they could get domestic gas earlier. And I told you they need to build out the infrastructure to do that. There's a pipeline system being built in Senegal to get 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 earlier than the 2029 date we talked about. So actually one of the things that we talked about in Paris was getting on with the early negotiation of a gas sales agreement.

I think if you think about it, there's sort of 200 million that you can get at zero 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 cost. So there's 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 at least the money capital going in and then how do you get the most benefit actually for the host countries and build true win-win. So that for me is the way to think about the project, Neil, rather than I think Phase II and III can be more biased towards LNG. But I think that initial sort of expansion as we call it Phase I plus of the existing facilities being more targeted to the domestic gas. Now there is some debottlenecking you can do on the Gimi as well. So move it beyond the 2.7 nameplate.

I think there's an increment of LNG to come there. So when you think about it, there's a piece of it to that increment of the Gimi, but it's not 5 million tons, it's an increment on the Gimi. And then there's the residual amount that would go to domestic gas. So all in all, essentially comes at very, very low CapEx.

Neil Mehta: Thank you, Andy.

Neal D. Shah: Good. Thanks, Neil.

Operator: Our next question has come from the line of Christopher Bockay with Clarksons. Please proceed with your questions.

Christopher Bockay: Hi, guys. Thanks for taking my questions. 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 rates 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. Is it primarily driven by timing and deferrals? Or is it real cost savings? And in addition to that, related to the FPSO lease refinance for GTA, what kind of cost savings should be realized once completed? I think we can start with these two.

Andrew G. Inglis: Brian, this is Lars. 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, you know, filtering around sort of 62,000, 63,000 barrels of oil per day today. We've got a new well coming on, just started drilling by the way. We're drilling the 26th in section as we speak. And I'm 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 it at a sort of around sort of 70,000 barrels of oil per day on Jubilee. So as you go into 2026, the question is, of course, well, what's going to happen and what are you what's your view of the future? We've got four 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, 500 or something on average, that adds if you add it up in a simplistic sense, 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 at 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 say that the producers where we're targeting are in the main part of the field.

They're targeting areas where we got good pressure support in terms of challenges we've had in the past were at the end of the last drilling program, we're in Jubilee Southeast area where there's less concentration of injectors. And therefore, I think we had challenges around the connectivity, in particular, on one well. So you can't you've got to be careful when you talk about decline rates. You've got to think about it both the two dynamics, where you're putting the wells, what's the pressure for, and also the difference in the as you change the well the production between the new wells and the existing wells, yes.

But I think that's the right way to sort of think about Jubilee. I think there are things to monitor going forward. First thing, have you started drilling? Yes, we have. The objective then would be to get the well on production around the end of the year. What production rate do we get then? And then you start to build it up as you drill the next. So it's four 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.

Neal D. Shah: Yes. And that, Chris, it goes to your second question, which is what are the savings? Again, think there's a bit from Ghana, which is as Andy alluded to, was 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 25,000,000 program in terms of what we think will be lower than $3.50, in terms of what we're projecting for this year. So those are real savings, not just deferrals of capital from

Andrew G. Inglis: Yes. And maybe the thing I'd add to that is, Chris, is it's a lot of small things about our 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 it's every dollar counts, whether it's CapEx or 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 2026 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 10,000,000 to $20,000,000 overall in the Yeah. Yeah. And again, that's sort of feeds your third question as well around sort of the FPSO lease cost and yeah, we're spending about $60,000,000 this year, 15,000,000 a quarter. On the lease. And the goal would sort of get that to sort of the 40,000,000 to $50,000,000 range. So, again, I think there's still some work to be done, figure out what where exactly, we'll get an instrument price. But it'd be a material CapEx savings or an OpEx savings as we get that complete.

Christopher Bockay: Perfectly clear. One last question on GTA, if I may. And I know you touched upon this earlier, but with the Phase one nearing nameplate now, how do discussions or evaluation for phase one plus 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?

Andrew G. Inglis: Okay. Yes, I want to sort of repeat everything I said. In answering Bob's question, but I think sorry, Neil's question. But as you go back to Phase one plus, you asked a question about FID timing, yes? The point I'd like to make is that you can get 200,000,000 today of extra gas without spending any money. So no FID required on that 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 Governments, In Particular In Senegal is they want to accelerate that. They've got a very strong domestic demand.

Those of you who are Senegal watchers will know that the President and the Prime have been clear about the importance of getting domestic gas. And therefore, the this is a real win-win where you're able to leverage that. That comes sort of without any extra money. The last 100,000,000 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 twelve months. What happens is that you've got to get the work done in the 28 turnaround yes? So you need a lead time to get you to that time period.

When the FPSO has a normal shutdown, that's when you do the work. Then that means that the additional $100,000,000 would be available in '29, yes? In terms of the Gimi you know, it can do, you know, we're targeting getting to up to nameplate and I think we're demonstrating that. So I think the progress we're making is literally month on month, quarter on quarter we'll get to that position at the end of 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 was the two things that influenced 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 there is more to you can get more out of the gimmick. But the two things you've got to work on the power and the cooling. And again, when would you do that? You'd probably do it at the turnaround time so that you did it at the same time as the FPSO work was going on.

I don't think in terms of sort of pulling out spreadsheets, I wouldn't include anything until sort of 2019 on that.

Christopher Bockay: Right. Very good. Thanks, Chris. Appreciate it.

Operator: Our next questions come from the line of Stella Cridge with Barclays. Please proceed with your question.

Stella Cridge: Many thanks for all the updates today. If I could just follow-up on the point of looking at secured borrowing. On GTA. Could you just say what you think the borrowing capacity of this business might be at the moment? And what sort of structure might be possible given that, you know, it has a different profile to the more kind of liquids businesses that you have elsewhere? That would be great. Thanks.

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

Stella Cridge: Super. Thank you.

Andrew G. Inglis: Good. Thanks, Sam. Y'all are

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

Nikhil Bhat: Good morning. Thank you for taking my question. I have a couple. First one, the second quarter report mentioned that your net leverage covenant on the RBI raised to four times as of September 25. 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? If that's if sorry. This has affected the March 26, test as well. And then you, sorry. There's also a question I had on the liquidity test for the 2027s. Does this, by any chance, need to be redone in March 26 or now that you completed the test in September, there's no more no more of redoing this test.

Neal D. Shah: Correct, Nikhil. So just to your two questions, So the waiver we got through four times was for the September test, which uses the June financials on an LTM. And so the June financials, we were at 3.8 times. We increased it to four times from banks. So that gets officially tested as of September 30, not using the September 30 financial. So 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.

You know, the four and a quarter is the relevant test at the end of this year, which get tested, you know, using December 31 financial that actually gets tested by the 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 March. From a timing perspective. That make sense?

Nikhil Bhat: It does. Thank you.

Andrew G. Inglis: Thank you, Akhil. Thank you. Our next questions come from the line of

Operator: Mark Wilson with Jefferies. Please proceed with your questions.

Mark Wilson: Thank you. Most of my questions have been answered already. But I would like to know, just to check, go 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? Thank you.

Andrew G. Inglis: Yes. Thanks, Mark. Look, there's a lot going on at Jubilee. We've the current drilling program. As I said in the earlier remarks, we're targeting that at the main field. Areas where we have really good well control and therefore, we're drilling lowest targets. We've used the fast track of the NAS for that. So it's an early product, but incredibly good. I look back in my days of what a fast track like to what you're getting today. So in essence, we have been able to leverage that mass data, which is the 40, therefore, comparator of the 40 on a 2025 back to 2027.

So I think that's a that drilling program is well underpinned by the nature of the targets that we've 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 three to four 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 of quality, of that four d picture and we think will lead to greater clarity on that high grading of the hopper. And 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 unswept oil under lobes Correlation of that from the four d with a much higher uplift in the seismic 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 three months on having had a chance to play with the NAS we've probably got a stronger view. There's 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 2027. So I think that's sort of where we are with the program, Mark. And again, I think we'll see the results of this 2025, 2020 program. The first well has gone well. The next well on by the end of the year, you then got four more producers and an award injector that will take us through the back end of '26.

And then it's about optimizing the next set of wells. And the only bit I'd add is that the four d does help you optimize the water injection patterns as well. So I think we've talked about voidage replacement. I think we know we need to be above 100%. We need to be targeting water 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 has now is bringing up some new ideas about how you optimize the water injection patterns.

So I think all of that is to say 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 five producers going forward and that's our objective.

Mark Wilson: Got it. Very clear. And yes, good luck with the forward plans. Thank you.

Andrew G. Inglis: Great. Thanks, Mark.

Operator: Thank you. Our next questions come from the line of Kay Hope with Bank of America. Please

Kay Hope: Hi. Thanks so much for taking my question. I just have a quick one. I can see on Slide 11, you say you expect production in the fourth quarter of 66,000 to 72,000 barrels a day. But you mentioned in the comments that you're at about 72,000 barrels a day now. Is there a reason we should expect that average to be as low as 66?

Neal D. Shah: Yes. Sure. So hi Kay, this is Neal. Yes. So we have started off production pretty good in October so far. Again, I'd say, yes, there's normally some downtime both planned and unplanned. We talked a bit about there's a little there's one more train in GTA that will be down for a few days. Within the quarter that stops you from producing it sort of yeah, call it sort of full rates. And then we have some sort of recurring downtime to the field. Again, 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.

Kay Hope: Okay. Perfect. And 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?

Neal D. Shah: Yeah. And so you're right. In terms of we saw some big working capital flags as GT product GTA sort of finished the commissioning phase and went into the operational phase in at the end of the second quarter and to the early part of the third quarter. So we flagged that into the third quarter. Calls. We haven't seen any of those into 4Q Again, capital is really hard to predict in terms of where we are. And again, I think there you know, Andy mentioned sort of there's 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 flex again, if we see any big working capital, we'll usually flag it. We don't see any at the moment, and there's 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 in some of the cash flows, it will be sort of different. But, again, I think with our view today, it's hard to don't see anything immediately, but it's something we're just we'll have to continue to manage.

Kay Hope: But you're not telling me that you're gonna be free cash flow positive in the fourth quarter.

Neal D. Shah: If you tell me what oil prices are gonna be.

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

Andrew G. Inglis: Yeah. What I'd say, Kay, is we've we've had a strong start to the first month. So we obviously, we sit here today. We know what October is like. And we've we're well within the guidance that you talked about for 4Q. Yes? So I think this is about you talked about the downside of what would cause to hit 66%. The alternative question would be 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.

Operator: 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. Thank you for your participation.