Kosmos Energy Ltd. Common Shares (DE)

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 Cosmos Energy Earnings Conference Call. All lines have been placed on mute to prevent any background noise, and after the speaker's remarks, there will be a question and answer session. If you'd like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you'd like to withdraw your question, please press star one again. Thank you.

I'd 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 Ingalls, Chairman and CEO of and Neil Shah, CFO. During today's presentation, we will make forward-looking statements that refer to our estimate, plans, and expectations. Actual results and outcomes could differ materially due to factors we note in this presentation and in our UK and SEC filings. Please refer to our annual reports, 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 Cosmos' 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. Neil will then take over to review our financial progress on priorities for 2026 before I wrap up with closing remarks. We'll then open the call up for Q&A. Starting on slide three, as we close out 2025 and enter 2026, our goals of building a sustainable, lower-cost business have 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 break-even of the company. Turning to slide four, 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 with selling in extra organic. 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 name-paid 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 met that end of the year higher than planned. But we laid the groundwork to deliver in 2026 and we've already seen strong progress and momentum this year. Turning to slide five. 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 tonnes per annum equivalent year-to-date, with 6.5 gross LNG cargo 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 10 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 Extral 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 our $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 leveraged covenant waiver from the bank group for year-end 2025 and mid-year 2026. 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 trends to commence our 2027 hedging program. And we recently announced the sale of our producing assets in Equestrial Guinea, which enhances liquidity and accelerates debt paydown. Turning to slide six, which provides a summary of our reserves at year end. On 1P reserves, we have reserves 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 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 10 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 Cosmos, we continue to see strong alignment with the country's interests 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 for 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 four additional wells to bring online later in the year, with three producers expected to grow production and one 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 fields. 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 licence extensions for Jubilee 10 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 fields for the long-term benefit of all stakeholders. And finally, in February, the partnership signed the sale and purchase agreement to acquire the 10 FBSO at the end of its lease term in early 2027. Signing the SBA will result in significant OPEX reduction from 2026 onwards and as the lease payments will be classified as capex until early next year and then be eliminated. Turning to slide A, 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 2025-26 drilling program, which largely arrested an 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 it 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 five 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 nine months. The latest two wells in the current campaign are likely to be closed for the six months, given their strong performance. These compelling economics support a consistent drilling program informed by the new seismic data. With its 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 few months of the year of around 70,000 barrels of oil per day gross, plus the expected performance of the additional five 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 voltage 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 impacts of the 40 seismic shock last year. 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 OVN data with the 4D NAS data to help select the best well locations for the 2728 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've mentioned on previous earnings calls, Cosmos has been a strong advocate of regular drilling to maximize the value of a midlife 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 for 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 nine, at GTA we've also seen a lot of progress. In the fourth quarter, the partnership listed eight 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 tonnes per annum equivalent throughout December, and on several occasions reaching record levels of around 3 million tonnes per annum equivalent. So far this year, this good performance has continued with production around 2.9 million tonnes 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 three gross condensate cargoes in 2026. On cost, we expect operating costs to be lower year-on-year, targeting a reduction in OPEX and then BTU of over 50%. This reflects lower costs, including the FBSO refinancing that was completed in January, alongside the higher production volumes. As Gerlach 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 costs 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 for MMBTU as the higher volumes and cost reductions come through in 2026, as well as the impact of Phase I+. We've shown volumes of 613 million standard cubic feet per day for LNG export and domestic gas. That is what the FPSO is capable of doing today without any cost required to de-bottleneck 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 San Luis in the north to the capital, Dachau. Turning to slide 10. In the Gulf of America, performance for the fourth quarter of the year was in line with expectations, with good performance from Oddjob 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 operators 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 Tiberias with our 50-50 partner, Oxy. Cosmos 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 2027 and 2028. Post-FID, we plan to farm down our interest to around a third. Elsewhere in the Gulf, we formally entered into a strategic alliance with Shell earlier this year to jointly explore the prolific Norfolk Plate. As part of the partnership, Shell and Cosmos 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, Trailblazers, targeting over 200 million barrels of oil equivalent gross with drilling planned for 2027. The fit within our lean capital budget this year and thanks Cosmos for the ability to adjust its working interest to manage our capital exposure. Neil, we'll 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 at GTA through the quarter, achieving well in excess of the nameplate capacity in late 2025, as Andy mentioned. We ended up only lifting two 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 it to bounce back in one Q26 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 and 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, the 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 multi-year lows and in line with 2025 when excluding the 10 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 Cosmos 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 10 and EG assets represent our highest operating cost barrels, and with the purchase of the 10 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 10-FPSO. Around 70% of the annual CapEx is allocated to Ghana, with five 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 Tiberias. In Mauritania and Senegal, we expect minor capex during the year as we plan for GTA Phase I Plus 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 RVL 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 pay down. 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 non-core asset sales. On the RBL, we received a leverage covenant waiver from our bank group, which covers year-end 2025 and the mid-year 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. We should 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 EG, 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, Neil. Turning now to slide 15 to conclude today's presentation. As I said in my opening remarks, we have three 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 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 obtain a deep offer of opportunities for the future. As Neil 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.

At this time, I'd like to remind everyone, in order to ask a question, please press star, then the number one on your telephone keypad to raise your hand and enter the queue. If you'd like to withdraw your question at any time, you can simply press star 1 again. Thank you. Your first question comes from the line of Charles Mead with Johnson Rice. Your line is open.

Good morning, Andy and Neil, and to the rest of the Cosmos team there. Andy, I appreciate all the detail 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 ads 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 Is it going to be an addition of net five, perhaps, after you back out lower pressure wells?

Yeah, look, 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 zero. Yeah? Yeah. 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, all right, and you understand what I'm saying. Yeah, it's not always the same. Yeah. Yeah, all right. So, you know, but a rule of thumb, if you're sort of looking at a well that is, you know, coming on at 10,000 barrels a day, sort of on average, you might get sort of 2,500 barrel a day back out. Yeah. So I think that's the way to think about it. Yeah. For some, it could be slightly more clearly for a well like J74, you know, essentially zero. Yeah. Yeah. And again, 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, what the GRR is going to come on, what impact it has on the infrastructure, which riser it's coming into, et cetera. So it's obviously part of the forecasting process.

Yeah, I'll let your engineers do all that modeling. Second question I have. For – this is on GTA and specifically the cargo guidance for the year. If we look at your 1Q guide, you have 9 to 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 – you know, 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, yeah. So if you... What you need to think about is your strongest quarters are going to be quarter one and quarter four, yeah?

Yeah.

So if you sort of put those two bookends together, you know, maybe you could sort of look at 20 from those two quarters. And then, you know, the residual, as it were, is warmer weather in the summer in quarter two and quarter three where you're going to get lower cargos. So I think, you know, no planned turnaround. It's really the seasonal effect. And you can't sort of take the first quarter and multiply it by four. Got it. Thank you, Andy. But, you know, the thing to add is that a strong start to the year, yeah, and I think that's the most important part. You know, through, you know, year to date, we're at 2.9 million tonnes per annum from the facility, which is, you know, above its nameplate of 2.7. So I think the thing to take from it is, you know, the strong start to the year should give confidence in the overall outlook for the rest of the year.

Got it. Thanks, Amy. Great. Thanks, Charles. Appreciate it.

Your next question comes from the line of Alexa Patrick with Goldman Sachs. Your line is open.

Hey, good morning, team, and thank you for taking our question. If you could, could you talk more about the amended debt cover ratio that you announced this morning? How should we think about the next two periods coming up, where you stand, and how conversations have been going there?

Yeah, Alexa. Hey, this is Neil. I'll take that. Just, yeah, so we've had a constructive conversation with the banks so far in the year. And, you know, the two next periods are sort of March and September this year, which cover sort of year-end 25 and mid-year 26. And so, yeah, 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 mid-year 26, basically the leverage covenant was raised from three and a half to four and a quarter. And that basically accommodates sort of, you know, the historical over 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 levels. by the end of the year. And again, based on our guidance and forecast, we should be back under sort of leveraged 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.

Okay, that's helpful. And then as a follow-up, I think you've talked about cost per BOE at TOR2 declining by more than 50%. Can you help just kind of walk us through the bridge there? How much of that is just on top-line production growth versus nominal cost coming down, and how should we think about it?

Yeah, Lexa, I'll take that as Andy. Yeah, it's both effects, as you say. Clearly, you know, we produced 18.5 cargoes in Tortue last year. We're targeting a range of 32 to 36, you know, the question from Charles. So that, you know, the volumetric effect is obviously significant, yeah? That combined with, you know, 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 two combined give you a greater than 50% reduction on a MMBTU basis.

Thanks. We'll turn it back. Great, thank you, Alexa. Your next question comes from the line of David Round with Stifel.

Your line is open.

Great, thanks, guys. Thanks for the presentation. 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 10 FPSO purchase changes that thinking a 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. The second one, just on Jubilee, Andy, I think you mentioned there, you know, 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 pre-cannibalization. But 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 hoped for, let's say, that the next world could also deliver at that kind of rate.

Yeah, okay, thanks, David. If I take the 10 question first, yeah, you know, clearly lowering the break-even of the asset through the FESO 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 the 40 in OBN over 10. So we're, you know, it's actually been a focus on Jubilee first to build a drilling program for Jubilee. But as you look to 27 and 28, yeah, I think there's a potential for a while in... in 10 on the basis of being able to bring in the enhanced seismic imaging from the NAS and the OVN. You know, and that in combination with the lower operating cost of the asset, you know, will the economic sample 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, you know, the quality of the economics of, you know, the Jubilee wells. You know, they're They're paying back, you know, last 12 wells, you know, paid back, you know, the average. That's with all the ups and downs in around nine months. In the last two wells, I think, you know, closer to six. So it's a very strong opportunity set that we see in Jubilee. And therefore, you know, I believe that there is a competitive well in 10. But, you know, the work on the seismic will enable us to uncover it. Yeah, you know, 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. Yeah. So the J72, you know, 74 and then 75, 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, you know, being illuminated by the seismic. So, you know, again, we want to be appropriately measured about the forecast, but I think, you know, J75, we had 40 metres of pay, it'll be a three-zone completion. similar to 72. So I think we're going to see, you know, some of the 74. So we're going to, you know, we should see strong performance from that well. So are there more 10,000 barrel a day wells in the field? Absolutely. Yeah. And I think that's the point to take away. And they come with good reserves and therefore very, you know, very strong economics.

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

Yeah, yeah. Great, David. Yeah, sorry I didn't mean to cut you off. Yeah. No, exactly. It's 2.45. That's what I was going to say. It's 2.45 per contract with BP. So everything that's above that is sold under that contract. Yeah. It's exactly the same pricing. Yeah. Okay. Brilliant. Thank you. Great. All right. Thanks, David.

Your next question comes from the line of Christopher Bucky with Clarkson Securities. Your line is open.

Hi guys, this is Christopher from Clarksons and thank you for taking my questions. 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 EEG stake. Could you give some color on how the license extension in Ghana are affecting the borrowing base and will that extension alone replace EEG, so to say?

Yeah, so we've just started the RBL process. Again, I think the main thing is the RBL, like you said, is underpinned by the Ghana reserves and EG, we'd expect for March for both pieces still to be in there. And then as the transaction closes in Q2, then, yeah, the EG portion will come out. And so, yeah, again, there will be some pact in terms of the borrowing base from EG. We had it roughly, yeah, plus or minus $100-ish million of impact, but we were well over-collateralized 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 close the asset sale in mid-year, there'll be an impact to the RBL as a result of that transaction.

Thank you very much. My second question comes following the EEG 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 space, in your view?

Yeah, maybe I'll take that, Christopher. Look, I think a key theme coming out of the, hopefully out of the prepared remarks and the slides is You know, we're on a journey to create a lower-cost business. And, you know, we've talked about the, as it were, the organic portfolios that sits today, more than $100 million of costs coming out. And when you put EG onto that on a pro forma basis, it would be another probably, you know, gets you closer to an 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. So 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, yeah, you're right. Tiberius is an important growth project for us in the Gulf. So I think the messages really are around very, very strong focus on cost to build that lower-cost, sustainable business. Very strong reserve base, yeah? And then associated with that is rigorous allocation of capital to the highest return projects, and, you know, with a very lean capital base in 26 to enable us to do that. So, yes, there will be, I think, on the margins 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 off-pakes per MMBTU looks like at, let's say, 2.7 to 2.9 MTPA, and how much of that reduction comes from the SDSO refi versus kind of operational efficiencies?

Yeah, so, you know, 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 the slide.

Maybe if I answer the question a different way, Christopher. When you look at sort of just the absolute cost reduction in... in 26 versus 25, about half of that is the FPSL refinancing and half of that is that sort of the startup cost piece coming out. And as Andy alluded, sort of there's more to go on the operating costs from, you know, a pure perspective to pull out of the system. And then, you know, while the changes are slightly larger than that, they, you know, there's 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, you know, for those two 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%, and then you should see a further reduction into 27%.

Yeah, and the actual numbers are shown there on slide nine. But again, I think what I'd add to that, Neil, is you sort of, you know, there's no required investment really to deliver up to the 630, which is the additional increment from the domestic gas. So as that starts to come through on phase one plus, you see another step down in the net OPEX per dollar per mm BTU.

Fantastic, guys. Thank you very much.

Great, thanks, Christopher.

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

Hi there. Afternoon, everyone. Many thanks for all the updates. There was two things, if I could ask, please. The first is on Tiberius. When you were talking about the farm down, is the idea that the new partner covers their kind of pro-rata share of CapEx, or 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. What would be your base case for addressing those? That would be great. Thanks.

Yeah. Hi, Stella. I'll take those. In terms of Tiberius, yeah, when we and Oxy will both look to sort of farm down, we're about, you know, we're both 50-50 partners today. And the goal is to get sort of a third partner in there who's at a third, a third, third. And so, you know, the idea is that they clearly pay their own capital costs 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 at least 10% in calendar year 26. About half of that is through sort of the EEG 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, you know, the Gulf Term loan amortization is sort of, you know, it's a little over $50 million this year. We'd expect to pay that out of cash flow generated from the business.

That's great. Thank you.

Great. Thanks, Stella.

And your last question comes from Mark Wilson with Jefferies. The line is open.

Yes, thank you. I'd like to ask, it's 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? Thank you.

Yes, so Mark, I think that they're more sequential. And again, we've sort of, we're close to, you know, again, as operator, we've moved down the development or FID path pretty far, and we're sort of close to getting that uh sanctioned and then we'll kick yeah we've talked clearly talked to a number of people around the farm down we'll kick off a a process here quite shortly and again there's not a you know it should be fairly attractive clean project to bring in a 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. Again, we think there'll be a lot of interest as we conduct a relatively short process.

Okay, thank you. And then the other new information in the Gulf is this strategic alliance With Shell, you talk about being aligned across 10 blocks now. We'd just like to know, is there anything within that, you know, quote, strategic alliance beyond involvement in licenses, any kind of carry or information share, et cetera? Thank you.

Yeah, so, Mark, I'll take that. So, you know, as you know, we've had a long, good working relationship with Shell. You know, 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 years now, we've been having sort of an ongoing conversation on 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, you know, 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, you know, 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 Norfolk trend. We had some prospects, they had some prospects in and around Appomattox, so that made sense to, you know, combine and then basically work to jointly develop that infrastructure and actually, you know, create a good partnership where, you know, again, I think, you know, we can use both companies' capabilities, theirs around sort of drilling and and production, ours on the sort of accelerated development path that 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, you know, 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 27th. And again, it's about a theme really about ILX. So this is Norflood, but it's ILX around Appomattox where there is knowledge available on ILX. on the host platform there. So, no, I like the coming together, actually. They've obviously got huge knowledge of Norflot 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 uh to drill so um yeah lots to do now and and again we look forward to updating you on tiberius when we get started trailblazer when we get started yeah trailblazer no trailblazer understand that and then just one point a bit of housekeeping here on your your group production guidance uh the 70 to uh 78 can we

Can we just let us know where EG sits in that? Is there a number? I'll let Neil give you the exact.

Thank you.

Yeah, 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, you know, in terms of what, you know, does it close exactly in 2Q, 3Q, what we'll do is we'll reissue guidance. But we've broken out the components in the footnote there so that you can, you know, 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, yeah. Mark, so when it's closed, we'll have, yeah, some production will come out, but also some costs will come out. A chunk of cost. A chunk of cost will come out of the business.

Got it. Okay, great. Thank you. I'll hand it over. All right. Appreciate it. Thank you.

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.