Kosmos Energy Ltd. (KOS) Q4 FY2025 Earnings Call Transcript & Summary

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

Thank you, operator, and thanks for everyone for joining us today. This morning, we issued our fourth quarter 2025 earnings release. This release and the slide presentation to accompany today's call are available on the Investors page of our website. Joining me on the call today to go through the materials are Andy Inglis, Chairman and CEO; and Neal Shah, CFO. During today's presentation, we will make forward-looking statements that refer to our estimates, plans and expectations. Actual results and outcomes could differ materially due to factors we note in this presentation and in our U.K. and SEC filings. Please refer to our annual report, stock exchange announcement and SEC filings for more details. These documents are available on our website. And at this time, I will turn the call over to Andy.

Thanks, Jamie, and good morning and afternoon to everyone. Thank you for joining us today for our fourth quarter and full year 2025 results call. I'd like to start today's call by reaffirming Kosmos' key priorities, which have remained consistent over the last year before reflecting on our progress in 2025. I'll then talk about the operational momentum we've already built this year and the planned activity set for the remainder of the year. Neal will then take over to review our financial progress and priorities for 2026 before I wrap up with closing remarks. We'll then open the call up for Q&A. Starting on Slide 3. As we close out 2025 and enter 2026, our goals of building a sustainable, lower-cost business has not changed. We're growing production from our core assets. We're laser-focused on cost reduction, and we're targeting a meaningful reduction in debt this year. We're doing all of this while high-grading our portfolio to drive down the overall breakeven of the company. Turning to Slide 4, which looks back on 2025. 2025 was a challenging transitional year for the company, creating the platform for a sustainable, lower-cost business. We delivered safe operations with no lost time or recordable injuries during the year. We delivered strong 1P reserves replacement of around 90% or 120% when excluding the assets we're selling in Equatorial Guinea. The Ghana licenses were extended to 2040, bringing additional reserves and reinforcing a commitment to invest in Ghana over the long term. We saw production growth every quarter in 2025 as we recommenced Jubilee drilling and ramped up GTA production. GTA was fully ramped up in the fourth quarter with a floating LNG vessel producing at its 2.7 million ton per annum nameplate equivalent through the month of December. And finally, on the finance side, we continue to enhance the resilience of the balance sheet, reducing near-term maturities and adding more hedges to manage our oil price exposure. We didn't deliver everything we set out to do in 2025. Production growth came more slowly than expected and net debt ended the year higher than planned. But we laid the groundwork to deliver in 2026, and we're already seeing strong progress and momentum this year. Turning to Slide 5. As I said on the previous slides, our agenda remains consistent and our key priorities have not changed. We've had a strong start to 2026 with good progress across production, costs and the balance sheet. Starting with production. The Jubilee drilling program is continuing to deliver. The second producer well came online in January and is contributing around 13,000 barrels of oil per day gross. This includes any cannibalization from neighboring wells and takes Jubilee production to over 70,000 barrels of oil per day gross, in line with our expectations. Five more Jubilee wells are due online this year, which helps support further material production growth in the field. At GTA, after strong 4Q performance, production has remained high, averaging 2.9 million tons per annum equivalent year-to-date with 6.5 gross LNG cargoes shipped year-to-date in 2026. And in the Gulf of America, production continues to perform well, in line with our expectations. On costs, we're targeting CapEx this year of around $350 million, which includes around $300 million of asset expenditure in line with 2025 and around $40 million associated with the TEN FPSO purchase. On operating costs, we're targeting an absolute OpEx reduction of over $100 million year-on-year as we continue to look for ways to drive costs out of the business. This reduction is expected to increase to around $250 million post the sale of our production assets in Equatorial Guinea. On overhead, we expect to see the full benefit of the cost savings we identified and implemented through 2025, benefiting the company sustainably in 2026 and beyond as we focus the organization on our most important priorities. Finally, on the balance sheet, it's been a busy first few months of the year. In January, we successfully completed a $350 million bond in the Nordic market. We'll use $250 million of the proceeds to pay down our 2027 notes and $100 million to pay down the RBL. On the RBL, we received a leverage covenant waiver from the bank group for year-end 2025 and midyear '26, which allows time for our leverage to normalize with GTA now fully online and Jubilee ramping back up. On hedging, we took advantage of recent price strength to commence our 2027 hedging program. And we recently announced the sale of our producing assets in Equatorial Guinea, which enhances liquidity and accelerates debt paydown. Turning to Slide 6, which provides a summary of our reserves at year-end. On 1P reserves, we have reserve to production life of around 10 years, which underpins our near-term growth activities. We also had a strong reserve replacement ratio of around 90%, largely driven by Jubilee additions post the license extensions. Adjusting for the recently announced EG disposal, 1P reserve replacement would be around 120%, demonstrating the high grading of the portfolio. On 2P reserves, we have reserve base of around 500 million barrels of oil equivalent, representing a differentiated reserve life of around 20 years. This deep reserve base allows sustained 2P to 1P migration over time as well as additional 2P recognition as projects are sanctioned to develop already discovered resources. The 2P reserve base is slightly down year-on-year, reflecting some downward revisions largely in EG. As with previous years, our reserve data has been independently prepared by leading reserves auditor, Ryder Scott. So in summary, we continue to have a robust and diverse 1P and 2P reserve base that underpins the sustainability of the business well into the future. Turning to Slide 7. It's been a busy start to the year in Ghana with an active drilling campaign, new OBN seismic, license extensions and a commitment to purchase the TEN FPSO. Before I get into each of these developments, I want to share some insight from a meeting in February with President Mahama in Accra. We meet regularly as part of our discussions, we talk about the future of Ghana's oil and gas industry and about the critical role Jubilee and TEN play in the country's energy security, economic growth and long-term development. Oil and gas remain a vital pillar of Ghana's economy. It's a major source of government revenue, supports skilled jobs and strengthens national energy security. Continued investment in the sector today is essential if it is to deliver fully for Ghana in the years ahead. At Kosmos, we continue to see strong alignment with the country's interest and with President Mahama's administration around a clear priority. Long-term sustainable investments support higher production and ensure the sector delivers tangible benefit for the people of Ghana for many years to come. With sustained investment and a stable operating environment, the opportunity is compelling. Higher production can generate greater state revenues, while low-cost associated gas can support more reliable, affordable domestic energy for power generation and broader industrial use. Our focus is to work constructively with our partners and the government to realize that potential, driving growth, lowering costs and ensuring these world-class assets deliver long-term value for Ghana, the partners and all our stakeholders. Looking in more detail at the activity year-to-date. The drilling campaign has started positively with the J74 producer well, which came online in January. The well continues to perform strongly and is contributing around 13,000 barrels of oil per day gross with Jubilee producing more than 70,000 barrels of oil per day gross. The next producer well, J75, is expected online around the end of the quarter with a meaningful increase in production expected from current levels. After J75, we then have 4 additional wells to bring online later in the year with 3 producers expected to grow production and 1 water injector to support the higher production levels. At the end of last year, we concluded the ocean bottom node or OBN seismic acquisition over the field. The data is now being processed using the latest technology with the results expected to deliver significantly enhanced imaging to allow for better selection of future well locations, leading to improved recovery over the life of the fields. In February, the Ghanaian government formally ratified the license extensions for Jubilee and TEN to 2040. We're pleased to have played a leading role in progressing those discussions with the government. As I said on recent earnings calls, the license extensions were an important step for the partnership to support increased investment in the field for the long-term benefit of all stakeholders. And finally, in February, the partnership signed the sale and purchase agreement to acquire the TEN FPSO at the end of its lease term in early 2027. Signing the SPA will result in significant OpEx reduction from 2026 onwards as the lease payments will be classified as CapEx until early next year and then be eliminated. Turning to Slide 8, which we showed last quarter, highlighting the strong correlation between drilling activity and production performance. On Jubilee, the partnership returned to drilling in the middle of 2025 with J72, the first producer well of the '25-'26 drilling program, which largely arrested and offset field decline in the second half of 2025. As I mentioned, in early January, the J74 producer well then took production back above 70,000 barrels of oil per day gross and has stayed above that level since supported by high levels of water injection. The blue dots on the chart show the approximate timing of the next 5 wells coming online with each producer well expected to drive higher production. As a reminder, these are high-return wells with quick paybacks. The last 12 wells drilled in Ghana have an average payback of around 9 months. The latest 2 wells in the current campaign are likely to be closer to 6 months given their strong performance. These compelling economics support a consistent drilling program informed by the new seismic data. With this year-to-date performance and the active program over the next few months, our production forecast for Jubilee is in the range of 70,000 to 80,000 barrels of oil per day gross with current performance supporting the upper end of the range. This forecast uses actual data for the first 2 months of the year of around 70,000 barrels of oil per day gross plus the expected performance of the additional 5 wells. We assume a decline rate for the field of approximately 20%. Year-to-date, we've done better than this as a result of well replacement ratio of 130%, a key performance metric. In our second quarter 2025 results, I talked extensively about the impact technology is having on our business. And in Ghana, we're already seeing the positive impact of the 4D seismic shot last year. The improved imaging gives us increased confidence in the performance potential of the asset and the year-to-date performance has been very consistent with our modeling. We look forward to integrating the OBN data with the 4D NAS data to help select the best well locations for the '27-'28 drilling program as well as optimize water injection to manage future decline. With the license extensions, the partnership is now starting to plan the long-term investment in the fields. As we mentioned on previous earnings calls, Kosmos has been a strong advocate of regular drilling to maximize the value of a mid-life field like Jubilee, a position which was echoed by the operator in their recent trading update. So in summary, there's been a lot of progress in Ghana year-to-date with an active program through the remainder of the year that should see higher production from new wells and a partnership aligned to invest in the future. Turning to Slide 9. At GTA, we've also seen a lot of progress. In the fourth quarter, the partnership listed 8 gross LNG cargoes with 18.5 for the full year. We also lifted the first gross condensate cargo in the fourth quarter at a small discount to Brent, another important revenue stream for the project. Production ramped up steadily during the fourth quarter, averaging the FLNG nameplate volume of 2.7 million tons per annum equivalent throughout December and on several occasions, reaching record levels of around 3 million tons per annum equivalent. So far this year, this good performance has continued with production around 2.9 million tons per annum equivalent year-to-date, partly benefiting from the cooler seasonal weather. We are targeting 32 to 36 gross LNG cargoes and an additional 3 gross condensate cargoes in 2026. On costs, we expect operating costs to be lower year-on-year, targeting a reduction in OpEx per MMBtu of over 50%. This reflects lower costs, including the FPSO refinancing that was completed in January alongside the higher production volumes. As Golar said in their results last week, they are working with the partnership to develop value-enhancing initiatives for the project, including FLNG operational efficiencies and debottlenecking of the LNG production capacity. Production should continue to rise and unit cost should fall as we move forward with Phase 1+. We expect to agree heads of terms for domestic gas sales in 2026, and Senegal is expected to commence construction of the domestic gas pipeline network next quarter. The chart on the right shows the significant drop expected in OpEx per MMBtu as the higher volumes and cost reductions come through in 2026 as well as the impact of Phase 1+. We've shown volumes of 613 million standard cubic feet per day for LNG export and domestic gas as that is what the FPSO is capable of doing today without any cost required to debottleneck the infrastructure. As the Senegalese government builds the multiple phases of the onshore pipelines, domestic gas needs will continue to increase, driven by demand for power and industrial use such as fertilizer plants in various centers from Saint-Louis in the north to the capital Dakar. Turning to Slide 10. the Gulf of America, performance for the fourth quarter and the year was in line with expectations with good performance from Odd Job and Kodiak and minimal storm downtime offset by lower Winterfell performance. As a result of challenges in drilling and completions at Winterfell last year, we took an impairment on the assets in today's results following the fair value assessment with the auditors. While there's still a lot of resource potential at Winterfell, we're working with the operator to refine the drilling program to reduce risk going forward to ensure we produce the resource in the best and most cost-effective way. Looking ahead, we have an attractive hopper of future opportunities in the Gulf of America, which we are advancing with some of the most established players in the basin. In the Outboard Wilcox, we have advanced the low-cost development plan on Tiberius with our 50-50 partner, Oxy. Kosmos is the project operator and Oxy owns and operates the Lucius host facility, so we are well aligned. We expect to take FID in the first half of 2026 with the bulk of the CapEx in '27 and '28. Post FID, we plan to farm down our interest to around 1/3. Elsewhere in the Gulf, we formally entered into a strategic alliance with Shell earlier this year to jointly explore the prolific Norphlet. As part of the partnership, Shell and Kosmos have exchanged interest in multiple blocks with several high-quality prospects targeting over 400 million barrels oil equivalent gross, all within tieback distance to Shell's Appomattox facility. The first prospect Trailblazer is targeting over 200 million barrels of oil equivalent gross with drilling planned for 2027. To fit within our lean capital budget this year and next, Kosmos has the ability to adjust its working interest to manage our capital exposure. Neal will now take you through the financials and the progress we're making on our cost reduction targets.

Thanks, Andy. Turning now to Slide 11, which looks at the financials for the fourth quarter in detail. Production was again higher sequentially due to the continued ramp-up of GTA through the quarter, achieving well in excess of the nameplate capacity in late 2025, as Andy mentioned. We ended up only lifting 2 cargoes from Jubilee in Q4 as the third cargo slipped into early 2026. While this has minimal impact to value, it does materially change Q4 EBITDAX and leverage. Realized price was lower sequentially, reflecting lower commodity prices, although we'd expect this to bounce back in 1Q '26 with the higher prices we've seen quarter-to-date. OpEx was higher than our expectations during the fourth quarter, largely due to higher costs in Equatorial Guinea. DD&A was lower quarter-on-quarter, but above our guided range due to lower sales volumes than forecast. Most other line items were in line with our forecast, with CapEx materially lower, reflecting the lower-than-expected accrued CapEx in Ghana. Turning to Slide 12. As Andy said in his opening remarks, one of the key priorities for the company as our phase of significant investment in growth comes to an end is to reduce costs to ensure we continue to grow our margin. In 2025, we made a lot of progress with CapEx of $290 million, a year-on-year reduction of almost 70% and the lowest since 2017. This can be seen on the chart in the top right of the slide. We expect 2026 CapEx to remain around these multiyear lows and in line with 2025 when excluding the TEN FPSO purchase in Ghana. Our focus in 2026 now turns to reducing operating costs. We are targeting a reduction of greater than $100 million net to Kosmos this year, which can be seen on the chart on the bottom right of the slide. The amount of targeted OpEx savings rises to around $250 million once EG is removed from the overall cost base. Our TEN and EG assets represent our highest operating cost barrels. And with the purchase of the TEN FPSO and sale of EG, we will see a significant improvement in our operating margin per barrel. This is important as we navigate a volatile price environment. On overhead, we made a lot of progress in 2025, exceeding our cost reduction target of $25 million by year-end, and we expect to benefit from the full year impact in 2026 with further savings identified. Turning to Slide 13, capital allocation. As I said on the previous slide, we expect full year CapEx of around $350 million, including the $40 million associated with the TEN FPSO. Around 70% of the annual CapEx is allocated to Ghana with 5 Jubilee wells delivering expected paybacks of less than a year. In the Gulf of America, around 15% of the company CapEx budget has been allocated to the Winterfell-5 well and the long lead items for Tiberius. In Mauritania and Senegal, we expect minor CapEx during the year as we plan for GTA Phase 1+ expansion and advance the associated wells required towards the end of this decade. In summary, we are tightly focusing our capital on near-term high-return oil projects that deliver production growth and have the flexibility to defer more capital-intensive projects until we get our debt into the right place. Turning now to Slide 14. As Andy said in his earlier remarks, we have been actively working to enhance the balance sheet, paying down near-term maturities, adding liquidity, increasing our hedging and reducing costs. We are pleased to have completed the $350 million Nordic bond in January, which is well supported by both existing and new investors and helps diversify our sources of finance. I'd like to thank everyone who participated and made this new issuance a success. $250 million of the proceeds are being used to repay the 2027 notes with $100 million used to pay down the RBL facility. The charts on the right of the slide show the work we have done to address the nearest-term maturities. So our focus can now turn to operational delivery and debt paydown. This year, we are targeting a debt reduction of at least 10% and have made a good start with the announcement to sell our producing assets in EG last week. Further reductions are expected through free cash flow delivery and other noncore asset sales. On the RBL, we received a leverage covenant waiver from our bank group, which covers year-end 2025 and the midyear 2026 tests. This gives us runway to improve our metrics through increasing production, reducing costs and paying down debt. I'd like to thank our banks for their continued support in this process. Having made good progress on the maturity schedule, our next objective is to commence RBL extension discussions with our bank group this summer, which would push out the dark blue amortization blocks on the bottom right chart as we incorporate more Ghana reserves into our borrowing base. All in all, a pretty active year on financing, which demonstrates our ability to access different sources of capital. We've also been active on our rolling hedging program, taking advantage of recent price strength to hedge barrels for 2027. We now have 8.5 million barrels of oil hedged for 2026 and a further 2 million barrels hedged for 2027. Post the sale of BG, we will retain our hedges, increasing our hedge exposure in 2026 to over 50%. As hedges roll off, we'll continue to add more to protect against future downside, in particular, in 2027. So in summary, we're proactively tackling our level of debt and leverage with a lot of progress in 2026 so far with more to go. We're doing a lot to reduce costs further in 2026, and our capital allocation priorities are clear. With that, I'll hand it back to Andy.

Thanks, Neal. Turning now to Slide 15 to conclude today's presentation. As I said in my opening remarks, we have 3 clear priorities in 2026: grow production, reduce costs and reduce debt. This slide puts some targets against those priorities. On production, we want to deliver 15% production growth year-on-year coming predominantly from our core, Jubilee and GTA assets. Alongside that, we plan to deliver a 20% reduction in total operating costs. We expect the combination of higher production and lower costs to reduce OpEx per barrel by around 35%. That increasing margin, combined with our portfolio high grading should allow us to reduce net debt by at least 10% with scope to do better. And at the same time, we're advancing our quality growth portfolio with minimal CapEx in 2026, and we retain a deep offer of opportunities for the future. As Neal and I have highlighted in today's presentation, the team is focused on delivery, and I'm pleased with the strong start to the year. Thank you. And I'd now like to turn the call over to the operator to open the session for questions.

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

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

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

Yes, just go ahead. Yes.

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

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

No, it's seasonal, it's seasonal, Charles, yes. So if you -- what you need to think about it is your strongest quarters are going to be quarter 1 and quarter 4, yes. So if you sort of put those 2 bookends together, maybe you could sort of look at 20% from those 2 quarters. And then the residual as it were, is warmer weather in the summer in quarter 2 and quarter 3, where you're going to get lower cargoes. So I think no planned turnaround. It's really the seasonal effect. And you can't sort of take the first quarter and multiply it by full, but thing to add is that a strong start to the year, yes. And I think that's the most important part. The -- through year-to-date, we're at 2.9 million tons per annum from the facility, which is above its nameplate of 2.7 million ton per annum. So I think the thing to take from it is the strong start to the year should give confidence in the overall outlook for the rest of the year.

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

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

Yes, Alexa, this is Neal. I'll take that. Just yes, so we've had a constructive conversation with the banks so far in the year. And what we -- the 2 next periods is sort of March and September this year, which covers sort of year-end '25 and midyear '26. And so basically, the March covenant cover -- the amendment essentially covers where we ended up at year-end '25. So that's sort of covered off. And basically, in midyear '26, basically, the leverage covenant was raised from 3.5 to 4.25. And that basically accommodates sort of the historical underperformance in sort of the second half of '25 as well as lower oil prices. So it works down to sort of, call it, 60-ish Brent. So again, we've created some cushion in there. And what we wanted to do with both us and the banks to make sure that sort of we don't have to revisit it. And so it returns to normal by the end of the year. And again, based on our guidance and forecast, we should be back under sort of leverage targets by the end of the year when you take that GTA effect ramp-up effect out of the LTM calculation. So again, I think it's something that was on sort of people's minds. So we wanted to get it addressed early, get the issue cleared out for the year. And now we've got the runway to just deliver operationally and then the results will naturally lead to the deleveraging that we talked about.

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

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

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

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

Yes. Okay. Thanks, David. If I take the TEN question first. Yes, clearly, lowering the breakeven of the asset through the FPSO purchase does create a longer economic life for the field, which is important. But the other thing that we're doing is we have shot of 4D and OBN over TEN. So we're -- it's actually been focused on Jubilee first to build a drilling program for Jubilee. But as you look to '27 and '28, yes, I think there's a potential for a well in TEN on the basis of being able to bring in the enhanced seismic imaging from the NAS and the OBN. And that in combination with the lower operating cost of the asset, will the economics there will be competitive against Jubilee. And that's ultimately what we're trying to do. And I think I want to reinforce the comments that we made in the script around the quality of the economics of the Jubilee wells. They're paying back -- last 12 wells paid back the average. That's with all the ups and downs in around 9 months in the last 2 wells, I think closer to 6. So it's a very strong opportunity set that we see in Jubilee. And therefore, I believe that there is a competitive well in TEN, but the work on the seismic will enable us to uncover it. Yes. In terms of the higher rates, I think the point to note, David, is that we've gone back to the core of the field, yes. So the J72, J74 and then J75, which is the next well that we're currently completing now that will be on before the end of the quarter, they're in the main part of the field where we know we've got good pressure support. We know we've had productive horizons. And these are fundamentally bypassed oil pockets. And they are being illuminated by the seismic. So again, we want to be appropriately measured about the forecast. But I think J75, we had 40 meters of pay. It will be a 3-zone completion, similar to J72. So I think we're going to see somewhat similar to J74. So we're going to -- we should see strong performance from that well. So are there more 10,000 barrel a day wells in the field? Absolutely, yes. And I think that's the point to take away. And they come with good reserves and therefore, very strong economics.

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

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

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

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

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

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

Yes, maybe I'll take that, Christoffer. Look, I think a key theme coming out of the -- hopefully, out of the prepared remarks and the slides is we're on a journey to create a lower-cost business. And we've talked about the -- as it were the organic portfolio as it sits today, more than $100 million of cost coming out. And when you put EG onto that on a pro forma basis, it would be another probably gets you closer in aggregate to about $250 million. So really, we are building that lower cost portfolio. And clearly, on a per BOE basis, it's a significant reduction. Sort of where next, it has to be things that are really sort of not core to the future where we don't see growth, we see potentially higher costs, and we'll continue to look at those assets. At the same time, we're redirecting the capital that we would have spent on the more mature higher cost assets. We're redirecting that to growth. Clearly, the growth in this year is targeting the very strong economics in Jubilee. And then as we look out beyond into '27, '28, yes, you're right. Tiberius is an important growth project for us in the Gulf. So I think the messages are really around very, very strong focus on cost to build that lower-cost sustainable business, very strong reserve base, yes. And then associated with that is rigorous allocation of capital to the highest return projects and with a very lean capital base in '26 to enable us to do that. So yes, there will be, I think, on the margin, some continuing trimming of the portfolio, but we've got a very strong set of core assets, and those assets will continue to deliver growth.

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

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

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

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

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

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

Stella, I'll take those. In terms of Tiberius, yes, when we and Oxy will both look to sort of farm down, we're about -- we're both 50-50 partners today. And the goal is to get sort of a third partner in there. Is that 1/3, 1/3, 1/3. And so the idea is that they clearly pay their own capital cost, and there's some back cost and then potentially some additional consideration. So that's sort of the structure that we're looking at post sort of FID to bring in that partner. In terms of the Gulf term loan perspective, again, I think we talked about today sort of getting net debt down by about by at least 10% in calendar year '26. About half of that is through sort of the EG sale and the other half is through generation of free cash flow across the business in sort of a, call it, mid-60s type oil price. And so again, sort of the Gulf term loan amortization is sort of a little over $50 million this year. We'd expect to pay that out of cash flow generated from the business.

And your last question comes from Mark Wilson with Jefferies.

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

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

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

Yes. So Mark, I'll take that. So as you know, we've had a long, good working relationship with Shell. A few years ago, we sold them our exploration assets across the portfolio in terms of the frontier licenses. We signed the term loan with them in the Gulf. And for a couple of years now, we've been having sort of an ongoing conversation around how we can collaborate in the Gulf. And clearly, they're the largest producer in the area, and they have access to a bunch of infrastructure, which as we push forward our strategy around ILX in the Gulf, having access to infrastructure is clearly helpful. And so we've been discussing for some time in terms of how can we put together our capabilities to create sort of a mutual benefit for both companies. And so we agreed sort of alliance to start here around the Norphlet trend. We had some prospects. They had some prospects in and around Appomattox so that made sense to combine and then basically work to jointly develop that infrastructure and actually creates a good partnership where, again, I think we can use both companies' capabilities, their's around sort of drilling and production, ours on the sort of accelerated development path to create value for both companies. And so again, I think that there continues to be more that we can do together, and we're happy to sort of formalize sort of the first step and continue to move things forward.

And if I could add, Mark, it's not just about the license exchange. There is a commitment to drill Tiberius, which is the high rank prospect actually between us in early '27. And again, it's about a theme really about ILX. So this is Norphlet, but it's ILX around Appomattox where there is [indiscernible] available on the host platform there. So no, I like the coming together. Actually, they've obviously got a huge knowledge of Norphlet development. So being able to leverage their knowledge onto our prospects has been great. And clearly, for them, it's about finding how they sort of high grade and create a larger inventory to drill. So yes, lots to do now. And again, we look forward to updating you on Tiberius when we get started -- Trailblazer when we get started.

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

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

Yes, thank you.

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

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

Correct, yes.

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

The costs...

Chunk of costs will come out of the business.

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