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Thank you for standing by. My name is Colby, and I will be your conference operator today. At this time, I would like to welcome everyone to the Q4 2025 Kosmos Energy Ltd. Earnings Conference Call. All lines have been placed on mute to prevent any background noise, and after the speakers’ remarks, there will be a question-and-answer session. If you would like to ask a question during this time, please press star followed by the number one on your telephone keypad. If you would like to withdraw your question, please press star 1 again. Thank you. I would now like to turn the conference over to Jamie Buckland. You may begin.

Thank you, operator, and thanks 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 Andrew G. Inglis, Chairman and CEO, and Neal D. 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 UK and SEC filings. Please refer to our annual report, stock exchange announcement, and SEC filings for more details. These documents are available on our website. I will now turn the call over to Andrew.

Thanks, Jamie, and good morning and good afternoon to everyone. Thank you for joining us today for our fourth quarter and full-year 2025 results call. I would like to start today’s call by reaffirming Kosmos Energy Ltd.’s key priorities, which have remained consistent over the last year, before reflecting on our progress in 2025, then talk about the operational momentum we have 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 will then open the call for Q&A. Starting on Slide 3, as we close out 2025 and enter 2026, our goals of building a sustainable lower-cost business have not changed. We are growing production from our core assets, we are laser-focused on cost reduction, and we are targeting a meaningful reduction in debt this year. We are 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 injury during the year. We delivered strong 1P reserves replacement of around 90%, or 120% when excluding the assets we are selling in Equatorial Guinea. The Ghana licenses were extended to 2040, bringing additional reserves and reinforcing our 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 the floating LNG vessel producing at its 2.7 million tonnes per annum nameplate equivalent through the month of December. And finally, on the finance side, we continued to enhance the resilience of the balance sheet, reducing near-term maturities and adding more hedges to manage our oil price exposure. We did not 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 are already seeing strong progress and momentum this year. Turning to Slide 5, as I said on the previous slides, our agenda remains consistent. Our key priorities have not changed. We have 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 should help support further material production growth in the field. At GTA, after strong fourth quarter performance, production has remained high, averaging 2.9 million tonnes 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 are 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 are 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, the balance sheet: it has been a busy first few months of the year. In January, we successfully completed our $350 million bond in the Nordic market. We will 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 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 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 around 90%, largely driven by Jubilee additions post the license extensions. Adjusting for the recently announced Equatorial Guinea disposal, 1P reserve replacement would be around 120%, demonstrating the high-grading of the portfolio. On 2P reserves, we have a 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 that have already discovered resources. The 2P reserve base is slightly down year-on-year, reflecting some downward revisions largely in Equatorial Guinea. 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 has 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 insights from a meeting in February with President Mahama in Accra. We meet regularly, and 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 is 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 Energy Ltd., 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 for higher production and ensuring 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 around the activity year-to-date, the drilling campaign has started positively. The J-74 producer well 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, J-75, is expected online around the end of the quarter, with a meaningful increase in production expected from current levels. After J-75, 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 (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 life license extensions for TEN to 2040. We are 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 mid-2025 with J-72, the first producer well of the 2025–2026 drilling program, which largely arrested and offset field decline in 2025. As I mentioned, in early January the J-74 producer well then took production back above 70,000 barrels of oil per day gross, and it 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 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 closer to 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 two 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 have done better than this as a result of a voidage 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 are already seeing the positive impacts 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 NATS data to help select the best well locations for the 2027–2028 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 Energy Ltd. 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 has been a lot of progress in Ghana year-to-date and an active program for the remainder of the year. This should see higher production from new wells and has the partnership aligned to invest in the future. Turning to Slide 9, at GTA, we have also seen a lot of progress. In the fourth quarter, the partnership lifted eight gross LNG cargoes, with 18.5 for the full year. We also lifted the first gross condensate cargo in the field 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 around 3.0 million tonnes per annum equivalent. So far this year, this good performance has continued, with 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 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 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 costs should fall as we move forward with Phase 1 Plus. 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 Plus. We have shown volumes of 630 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 debottleneck the infrastructure. As the Senegalese government builds, in multiple phases, 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. There were also challenges in drilling and completions at Winterfell last year. We took an impairment on the asset in today’s results following the fair value assessment with the auditors. While there is still a lot of resource potential at Winterfell, we are working with the operator to refine the drilling program to reduce risk going forward and ensure we produce the resource in the best and most cost-effective way. Looking ahead, we have an attractive set 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. Kosmos Energy Ltd. is the project operator and Oxy owns and operates the Lucius host facility, so we are well aligned. We expect to take FID in 2026, with the bulk of the CapEx in 2027 and 2028. Post-FID, we plan to farm down our interest to around a third. I also want to highlight that before we entered into a strategic alliance with Shell earlier this year to jointly explore the prolific Norfolk play, as part of the partnership Shell and Kosmos Energy Ltd. have exchanged interests in multiple blocks with several high-quality prospects, targeting over 400 million barrels of 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 Energy Ltd. 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 are making on our cost reduction target.

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. As the third cargo slipped into early 2026, we ended up only lifting two cargoes from Jubilee in Q4. 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 would expect this to bounce back in Q1 2026 with the higher prices we have 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%, 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 Energy Ltd. 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 Equatorial Guinea is removed from the overall cost base. Our TEN and Equatorial Guinea assets represent our highest operating cost barrels, and with the purchase of the TEN FPSO and sale of Equatorial Guinea, 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 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 V well and the long-lead items for Tiberias. And in Mauritania and Senegal, we expect minor CapEx during the year as we plan for GTA Phase 1 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 was well supported by both existing and new investors and helps diversify our sources of finance. I would 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, and $100 million is being 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 Equatorial Guinea 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 midyear 2026 tests. This gives us runway to improve our metrics through increasing production, reducing costs, and paying down debt. I would 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 have 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 2.0 million barrels hedged for 2027. Post the sale of Equatorial Guinea, we will retain our hedges, increasing our hedge exposure in 2026 to over 50%. As hedges roll off, we will continue to add more to protect against future downside, in particular in 2027. So in summary, we are proactively tackling our level of debt and leverage with a lot of progress in 2026 so far, with more to go. We are doing a lot to reduce costs further in 2026, and our capital allocation priorities are clear. With that, I will 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 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 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 are advancing our quality growth portfolio with minimal CapEx in 2026, and we will obtain a deep hopper of opportunities for the future. As Neal and I have highlighted in today’s presentation, the team is focused on delivery, and I am pleased with the strong start to the year. Thank you. I would now like to turn the call over to the operator to open the session for questions.

At this time, I would 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 would 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 Arthur Meade with Johnson Rice. Your line is open.

Yes. Good morning, Andy and Neal, and to the rest of the Kosmos Energy Ltd. team there. Andy, I appreciate all the detail that you have 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, is it going to be an addition of net five, perhaps, after you back out lower-pressure wells?

Yes. Thanks, Charles. Look, it is not the same for every well. That is the most important thing to remember. For instance, when we brought the last well on, J-74, we were actually able to bring it into a new riser. So that actually relieved pressure on other wells, and I think the net back-out was close to zero. So it is not always the same. It depends also on the GOR of the well. So we have to be careful not to just do it by rule of thumb. But if you were to get into that conversation, and you understand what I am saying, it is not always the same. But a rule of thumb, if you are looking at a well that is coming on at 10,000 barrels a day, on average you might get around 2,500 barrels a day back-out. That is the way to think about it. For some, it could be slightly more; clearly for a well like J-74, essentially zero. 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, the GOR it is going to come on, what impact it has on the infrastructure, which riser it is coming into, etc. So it is obviously part of the forecasting process.

I will let your engineers do all that modeling. Second question I have is on GTA and specifically the cargo guidance for the year. If we look at your Q1 guide, you have nine to ten, and I think you said you are already at six and a half. So you are maybe tracking towards the high end there. But if we look at your annual guide of 32 to 36, the low end of your quarterly guide tracks to the high end of your annual guide. So I am curious, is there a turnaround baked in somewhere in the annual guide, or is this just some of the seasonal effects?

It is seasonal, Charles. Your strongest quarters are going to be Q1 and Q4. So if you put those two bookends together, maybe you could look at 20 from those two quarters, and then the residual is warmer weather in the summer in Q2 and Q3, where you are going to get lower cargoes. So there is no planned turnaround; it is really the seasonal effect. And you cannot take the first quarter and multiply it by four. But the thing to add is that it is a strong start to the year, and I think that is the most important part. Year-to-date, we are at 2.9 million tonnes per annum from the facility, which is above its nameplate of 2.7. So 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.

Got it. Thanks, Andy.

Thanks, Charles. Appreciate it.

Your next question comes from the line of Alexa Petrick 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?

Yes, Alexa. This is Neal. I will take that. We have had a constructive conversation with the banks so far in the year. The two next periods are March and September this year, which cover year-end 2025 and midyear 2026. The March covenant amendment essentially covers where we ended up at year-end 2025, and in midyear 2026 the leverage covenant was raised from 3.5x to 4.25x. That accommodates the historical underperformance in 2025 as well as lower oil prices. So again, we have created some cushion in there, and what we wanted to do—with both us and the banks—was to make sure that we do not have to revisit it, and it returns to normal by the end of the year. Based on our guidance and forecast, we should be back under leverage targets by the end of the year when you take that GTA ramp-up effect out of the LTM calculation. It was on people’s minds, so we wanted to get it addressed early, get the issue cleared out for the year, and now we have the runway to just deliver operationally, and then the results will naturally lead the deleveraging that we talked about.

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

Yes, Alexa, I will take that. It is both effects, as you say. Clearly, we produced 18.5 cargoes in Tortue last year. We are targeting a range of 32 to 36, so the volumetric effect is obviously significant. That, combined with around a 10% overall reduction in operating costs year-on-year—some of that coming from operations, some of it coming from the FPSO refinancing—the two combined give you a greater than 50% reduction on an MMBtu basis.

Thanks. We will 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 have always talked about that being your best return on capital. But specifically, it has always been around whether the TEN FPSO purchase changes that thinking. If it does, when we could see a well, or whether you are in a position to even think about that at the moment. Second one, just on Jubilee. Andy, I think you mentioned 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 is pretty cannibalized. The J-74 is actually nicely above that level. So I am just wondering if there is anything exceptional about that well and any reason why we should not hope that the next wells could also deliver at that kind of rate?

Thanks, David. If I take TEN 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 thing that we are doing is we have shot the 4D OBN over TEN, so the focus has actually been Jubilee first: build a drilling program at Jubilee. As you look to 2027 and 2028, I think there is a potential for a well in TEN on the basis of being able to bring in the enhanced seismic imaging from the NATS and the OBN. That, in combination with the lower operating cost of the asset, will mean the economics will be competitive against Jubilee, and that is ultimately what we are trying to do. I would want to reinforce the comments we made in the script around the quality of the economics of the Jubilee wells. They are paying back—the last 12 wells paid back on average, with all the ups and downs, in around nine months. The last two wells, closer to six. So it is 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. In terms of the higher rates, the point to note is that we have gone back to the core of the field. So J-72, J-74, and then J-75, which is the next well that we are currently completing now that will be on before the end of the quarter, are in the main part of the field where we know we have good pressure support, we know we have had productive horizons, and these are fundamentally bypassed oil pockets. They are being illuminated by the seismic. We want to be appropriately measured about the forecast, but I think J-75—we had 40 meters of pay—will be a three-zone completion, similar to J-72. So I think we are going to see some of the characteristics of J-74, and we should see strong performance from that well. Are there more 10,000 barrel-a-day wells in the field? Absolutely. And I think that is the takeaway, and they come with good reserves and therefore very strong economics.

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

Great, David. I am sorry, I did not mean to cut you off. Exactly. It is 2.45; that is what I was going to say. It is 2.45 per the contract with BP. So everything that is above that is sold under that contract. It is exactly the same pricing.

Okay. Brilliant. Thank you.

Great. Thanks, David.

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

Hi, guys. This is Christopher from Clarkson. Thank you for taking my questions. First of all, congrats on an eventful quarter and some strong recent months. I have a couple, so I will just take one at a time. First question is related to the RBL, which is currently secured against Ghana and the recently divested Equatorial Guinea stake. Could you give some color on how the license extension in Ghana affects the borrowing base? And will that extension alone replace Equatorial Guinea, so to say?

We have just started the RBL process. The RBL, like you said, is underpinned by the Ghana reserves and Equatorial Guinea. We would expect for March for both pieces still to be in there, and then as the transaction closes in Q2, the Equatorial Guinea portion will come out. There will be some impact in terms of the borrowing base from Equatorial Guinea—we had it roughly plus or minus $100 million of impact—but we were well over-collateralized from a Ghana perspective. You will not see much impact from Equatorial Guinea in Q1, but clearly, by the time we close the asset sale in midyear, there will be an impact to the RBL as a result of that transaction.

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

Maybe I will take that, Christopher. A key theme coming out of the prepared remarks and the slides is we are on a journey to create a lower-cost business. We have talked about the organic portfolio as it sits today: more than $100 million of costs coming out, and when you put Equatorial Guinea onto that on a pro forma basis, it could get you closer in aggregate to about $250 million. So we are really building that lower-cost portfolio and, clearly, on a per-BOE basis it is a significant reduction. Where next? It has to be things that are not core to the future—where we do not see growth and we see potentially higher costs—and we will continue to look at those assets. At the same time, we are redirecting the capital that we would have spent on the more mature, higher-cost assets to growth. Clearly, the growth in this year is targeting the very strong economics in Jubilee, and then as we look out beyond into 2027 and 2028, you are right, Tiberias is an important growth project for us in the Gulf. So the messages are really around very strong focus on cost to build that lower-cost sustainable business, very strong reserve base, and then associated with that is rigorous capital to the highest-return projects and with a very lean capital base in 2026 to enable us to do that. So yes, there will be, I think, on the margins, some continuing trimming of the portfolio. But we have 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 are guiding to more than 50% year-on-year unit cost reduction in 2026. Can you please help me understand what the steady-state cash OpEx per MMBtu looks like at, let us say, 2.7 to 2.9 MTPA? And how much of that reduction comes from the FPSO refi versus operational efficiencies?

When you look at the absolute cost reduction in 2026 versus 2025, about half of that is the FPSO refinancing and half of that is the start-up cost piece coming out. As Andy alluded, there is more to go on the operating costs from a peer perspective to pull out of the system, and while the changes are slightly larger than that, there is a slightly increased FLNG toll just because we are pushing more volume through Golar and they get paid on a per molecule basis. Net-net, those two are a little larger than 10%, but when you include the FLNG higher toll, it gets to around 10% on the total into 2026. Then you should see a further reduction into 2027.

And the actual numbers are shown there on Slide 9. What I would add is there is no required investment to deliver up to the 630 million standard cubic feet per day, which is the additional increment from the domestic gas. As that starts to come through on Phase 1 Plus, you see another step down in the net OpEx per MMBtu.

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. Good afternoon, everyone. Many thanks for all the updates. There were two things, if I could ask, please. The first is on Tiberias. When you are talking about the farm down, is the idea that the new partner covers their pro rata share of CapEx, or could you 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. Thanks.

Hi, Stella. I will take those. In terms of Tiberias, when we and Oxy both look to farm down—we are both 50/50 partners today—the goal is to get a third partner in there, ideally a third/third/third. The idea is that they clearly pay their own capital cost, there are some back costs, and then potentially some additional consideration. That is the structure we are looking at post-FID to bring in that partner. In terms of the Gulf term loan perspective, we talked about getting net debt down by at least 10% in calendar year 2026. About half of that is through the Equatorial Guinea sale and the other half is through generation of free cash flow across the business in a mid-sixties type oil price. The Gulf term loan amortization is a little over $50 million this year. We would expect to pay that out of cash flow generated from the business.

That is great. Thank you.

Thanks, Stella.

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

Yes, thank you. I would like to ask a follow-up to that Tiberias question. Certainly, 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 are we pursuing those two situations in parallel? Should we consider an FID and a farm down as things that come together, one and the same? Thank you.

So, Mark, I think they are more sequential. As operator, we have moved the development-to-FID path pretty far, and we are close to getting that sanctioned. We have clearly talked to a number of people around the farm down. We will kick off a process here quite shortly. It should be a fairly attractive, clean project to bring in the third partner, and as you have seen generally in the Gulf of America, there has been a lot of interest around people participating in new developments in cost-competitive, large-resource projects. We think there will be a lot of interest as we conduct a relatively short process.

Okay. Thank you. And then the other new information in the Gulf was this strategic alliance with Shell. You talked about being aligned across ten blocks now. Is there anything within that “strategic alliance” beyond involvement in licenses—any kind of carry or information share, etc.? Thank you.

We have 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 have been having an ongoing conversation around how we can collaborate in the Gulf. Clearly, they are 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 helpful. We have been discussing for some time how we can put together our capabilities to create a mutual benefit for both companies. So we agreed an alliance to start around the Norfolk trend. We had some prospects; they had some prospects in and around Appomattox that made sense to combine and then basically work to jointly develop that infrastructure and create a good partnership where we can use both companies’ capabilities—there is around drilling and production, ours on the accelerated development—to create value for both companies. There continues to be more that we can do together, and we are happy to formalize the first step and continue to move things forward.

And if I could add, Mark, it is not just about the license exchange. There is a commitment to drill Trailblazer, which is the high-ranker between us, in early 2027. Again, it is about a theme around ILX. This is Norfolk, but it is ILX around Appomattox where there is knowledge available on the host platform. I like the coming together. They have huge knowledge of Norphlet development, so being able to leverage their knowledge onto our prospects has been great. And clearly, for them, it is about finding how they high-grade and create a larger inventory to drill. Lots to do now, and we look forward to updating you on Trailblazer when we get started.

And then one point, a bit of housekeeping here. On your group production guidance, the 70 to 78, can you let us know where Equatorial Guinea sits in that? Is there a number?

Yes, so it is dug in the footnotes, but it is about 6,000 barrels a day in the guidance on average that is contributed by Equatorial Guinea. It is in the full-year guidance. Given the uncertain closing time—whether it closes exactly in Q2 or Q3—we will reissue guidance, but we have broken out the components in the footnote so that you can make an assumption around that and therefore the impact to the full year depending on when it closes.

And equally true, all the costs from Equatorial Guinea are in the year as well. So when it is closed, some production will come out and also some costs will come out—these are a chunk of costs that come out of the business.

Got it. Okay. Great. Thank you. I will hand it over.

Appreciate it. Thank you.