KOS

Good day, everyone. Welcome to Kosmos Energy 1st quarter 2026 conference call. As a reminder, today's call is being recorded at this time. Let me turn the call over to Jamie Buckland, Vice President of Investor Relations.

Thank you, operator. Thanks to everyone for joining us today. This morning, we issued our 1st quarter 2026 earnings release. This release and the slide presentation to accompany today's call are available on the Investors page of our website. Joining me on the call today to go through the materials are Andy Inglis, Chairman and CEO, and Neal Shah, CFO. During today's presentation, we will make forward-looking statements that refer to our estimates, plans, and expectations. Actual results and outcomes could differ materially due to factors we note in this presentation and in our U.K. and SEC filings. Please refer to our annual report, stock exchange announcement, and SEC filings for more details. These documents are available on our website. At this time, I will turn the call over to Andy.

Thanks, Jamie. Good morning and afternoon to everyone. Thank you for joining us today for our first quarter 2026 results call. I'll start today's call by reviewing progress against the four goals for 2026 that we laid out with our full year results in March. I'd then like to spend some time talking about the current market dynamics and how Kosmos is uniquely positioned to benefit by being priced at premium benchmarks before focusing on each business unit and the operational progress we've made year to date. I'll then hand over to Neil to talk about the financials before I wrap up with closing remarks. We'll open up the call for Q&A. Starting on slide 3. Two months ago, we released our full year 2025 results, and I focused on four key objectives for Kosmos in 2026, which is shown on the slide.

This year we are targeting production growth from our core assets, continued progress in cost reduction with a particular focus this year on operating costs, having made significant reductions in CapEx and overhead last year. Meaningful net debt reduction and advancement of our high-quality growth portfolio with minimal CapEx this year. I'm pleased to say we're making excellent progress against all these goals. Compared to the same quarter last year, production is up around 25%. Absolute operating costs are down around 22%. In addition, we've reduced net debt by around 7% from year-end 2025. I'll go into more detail on each as we move through the slides. Starting with production on slide 4. With the ramp-up of GTA and Jubilee production, we posted record quarterly production in the first quarter, as can be seen on the top chart on the slide.

This record production has come at a time when we've seen record high pricing and also record high differentials. The dark blue line on the left axis of the bottom chart shows Dated Brent pricing year to date. Dated Brent is the benchmark used for pricing our Ghana cargoes. In times of market tightness, Dated Brent can trade at a premium to Brent futures, reflecting the strong near-term demand for the barrels in the physical market. Dated Brent hit an all-time record high in early April and has continued to trade at a premium to Brent futures. Also worth noting are the differentials we're seeing on those barrels. The barrels we sell typically include a differential which is either a discount or premium to the benchmark, such as Dated Brent. That discount or premium depends on factors such as crude quality, location, and regional market conditions.

The red line on the chart shows an illustrative differential for West African crude year to date. Through January and February, those differentials were slightly negative, Started to grow through March into April as the Middle East conflict continued. While the data on the chart is illustrative, we've seen those differentials rise to a meaningful premium through this period of market tightness. Turning to slide five. This slide looks at how our barrels are priced in different geographies and the time lag we see between production and revenue. Our three core production hubs, Ghana, GTA, and the Gulf of Mexico, are all priced off premium benchmarks. In fact, across the US E&P sector, Kosmos is one of the most exposed companies to international prices as a percentage of sales. Around 50% of our production, primarily Ghana, is priced off Dated Brent, the dark blue line on the chart.

Since the Middle East conflict broke out, the Dated Brent premium over WTI has more than tripled. Ghana cargoes are typically priced off an average five or 10-day period before or after the cargo loading. Our March Jubilee cargo had already been hedged, so we didn't benefit from the rise in prices seen in the month. We do have a growing amount of unhedged production as we move through the year that should capture additional upside. In the Gulf of America, we sell most of our barrels against Heavy Louisiana Sweet or HLS, which generally trades at a small premium to WTI, the red line on the chart. Production in the Gulf is typically sold on a one-month trailing average, so we'll start to see the benefits of higher prices as we move into the second quarter.

On GTA, the gas production is priced off ICE Brent, the green line on the chart, which also generally trades at a premium to U.S. prices. Production is priced on a 3-month historical average price, so we'll start to see the full benefit of higher prices in 2Q. However, the lag effect also means we'll continue to see firmer GTA pricing beyond any future price declines. In summary, we've seen record production, record prices, and record differentials, but given the pricing structure we have in our various sales contracts, we won't see the benefit of higher prices that started in late 1Q until the second and third quarters. I'd now like to talk about each of our business units in more detail. Turning to slide 6, we saw to the progress we're making in Ghana.

This is a slide we've used for the last two quarters and has been updated for recent activity. As the operator discussed in our full year results last week, the 2025, 2026 drilling campaign continues to perform strongly. The J-74 well came online in early 2026, followed by the J-75 well at the end of the quarter. Both wells performing in line with expectations and gross Jubilee production for the first quarter was around 70,000 barrels of oil per day. The plots on the chart have been updated slightly since last quarter and reflect the partnership's decision to enhance efficiency by drilling a series of wells before completing them simultaneously. This means there will be a gap in new production additions during the second quarter, with 2Q production expected in the mid-70s.

Three new producer wells are due online in relatively quick succession in June and July, as previously communicated by the operator. Each of these wells is being drilled and completion operations start shortly. Based on the logging results, these three wells should drive a material uplift in production around 20,000 barrels of oil per day gross in aggregate before some natural decline is expected in the fourth quarter as the drilling campaign concludes. Year to date performance and the upcoming activity set continues to support the upper end of our 70,000 to 80,000 barrel per day gross oil production guidance for Jubilee this year. Looking at the bottom right of the slide, we are pleased to see the operator announce their refinancing earlier in the year, which was accompanied by a commitment to drill in 27 and 28.

The partnership is aligned on securing a rig for a program of up to 10 wells, with drilling targets to restart around mid-2027. As we previously discussed, this regular drilling program is key to sustain the improved performance we're seeing from Jubilee this year. Also worth noting is the value creation from the current drilling program with well paybacks in a mid-cycle price environment around 6 months and a lot shorter in the current environment. Turning to slide 7. GTA has continued to perform strongly this year with around 2.85 million tons per annum equivalent gross produced in the first quarter in excess of the floating LNG nameplate capacity of 2.7 million tons per annum. 9.5 gross LNG cargos were listed during the quarter in line with guidance.

For the year ahead, our gross cargo guidance of 32-36 LNG cargos is unchanged. 1 gross condensate cargo was listed in the quarter, which went to BP. The second and third condensate cargos later in the year, including 1 this quarter, are expected to be assigned to Kosmos and the NOCs. Due to some seasonality that we've found in the past, daily LNG production is expected to fall from higher winter levels as the sea and air temperatures warm up through the summer months. Volumes should pick up again later in the year as cooler temperatures return. On costs, we remain on track to deliver our 50% reduction target for OpEx per MMBtu this year and cost scope for further cost reductions in 2027.

On the phase 1 expansion, which should materially enhance project returns, there's been good progress on the ground in Senegal year to date. Approximately 50% of the land has been cleared for the onshore section of the northern segment of the pipeline, with the remaining 50% expected to be done this quarter. This northern segment will connect to the 250 megawatt Gandon power station being built near Saint-Louis. The onshore pipelines are expected to be exported from China in May, with arrival in Senegal scheduled around the middle of the year. The West African Development Bank has been appointed the mandated lead arranger to raise approximately $270 million to finance the infrastructure. The board of directors of the bank approved at the end of March the first tranche of around $90 million. Turning to slide 8.

Production in our Gulf of America business unit for the first quarter was in line with expectations with continued solid performance from our Odd Job and Kodiak fields. In April, the Winterfell 2 well was shut in pending a future intervention, and full year Gulf of America production is now expected towards the lower end of our guidance. On the growth side of the business, we were pleased to take the final investment decision on the Kosmos-operated Tiberius project alongside our 50/50 partner, Oxy. With expected development costs of around $10 a barrel and operating and transport costs of around $20 a barrel for the first phase, this is a low-cost, high-margin development. The first phase will be a single well tieback that will produce into Oxy's nearby Lucius platform.

CapEx is planned largely to be spent in 2027 and 2028, with first oil expected in the second half of 2028. We commenced the farm-out process to reduce our working interest to around a third. As mentioned with our full-year results in March, we recently entered into a strategic exploration alliance with Shell in the Gulf of Mexico, an exchange interest across multiple blocks across the North Pole play, which houses several material exploration prospects. We expect to drill the first of these, Trailblazer, in the first half of 2027. Trailblazer is targeting around 200 million barrels of oil-equivalent gross resource. I'll now turn to Neal to take you through the financials.

Thanks, Andy. Turning now to slide 9, which looks at the financials for the first quarter in detail. Production year-on-year was around 25% higher, driven by both GTA ramp-up and new wells coming online at Jubilee, resulting in record production of 75,000 BOE per day for the quarter. Realized price was slightly lower year-on-year, reflecting the changing production mix with more gas volumes from GTA. As Andy talked about earlier in the materials, due to the lag in pricing, we don't expect to see the full benefit of higher prices until the second and third quarters this year. OpEx of just under $20 per BOE was in line with our guidance and marks a decrease year-on-year of 47%, reflecting the continued progress we're making this year in reducing costs, having focused on CapEx and overhead last year.

Most of the other line items came in within our previous guidance ranges, except tax, which was impacted by the large mark-to-market change in derivatives. Looking ahead to Q2, we've included the usual guidance in the appendix to the slides. Q2 production is expected to be slightly lower than 1Q, largely due to the seasonality on GTA we've talked about and lower Ghana production on the back of Winterfell 2. In Ghana, we're guiding to 3-4 cargoes in 2Q, which includes a 10 cargo in the quarter. This also drives higher Q2 OpEx as a result of the accrued 10 FPSO lease payments prior to the agreement to purchase the vessel. OpEx is expected to normalize in the third and fourth quarters. One Jubilee cargo is expected at the very end of the quarter, which is the reason for the 3-4 cargo range for Q2.

For the full year, guidance remains unchanged. One area that we continue to monitor is tax as we incorporate higher oil prices into our actuals, and we'll provide further updates through the year. Just a reminder that we only pay cash tax in Ghana at the moment, given net operating losses in the U.S. and cost recovery at GTA. Turning to slide 10. We've had a busy start of the year on the financing side, completing several important objectives that set us up well for the year ahead. In January, we completed the $350 million Nordic Bond and have repurchased $250 million of 2027 notes with the proceeds. We also paid down $100 million of the bank facility with the remainder of the proceeds.

In March, we took advantage of the strong share price rally this year to raise around $200 million of equity, which was also used to accelerate our debt paydown. The company exited the quarter with around $500 million of liquidity post these transactions, with additional liquidity to be created from the EG sale and from free cash flow going forward. On the reserve-based lending bank facility, the banks approved a covenant waiver through the mid-year, and we're already seeing leverage drop sharply on the back of the equity raise and strong operational progress. We expect this to continue as we start to see the full benefits of higher production and higher pricing coming in over the coming months.

The lending banks have also approved the sale of our producing assets in Equatorial Guinea, which we expect to close around the middle of the year, with the proceeds used to further pay down the facility. On hedging, we continue to be active, targeting more hedges in 2027 at higher floors and higher ceilings than our existing 2027 hedges. Last week, we were pleased to see Fitch upgrade our corporate rating to B minus, a positive move to reflect the progress we've been making this year with discussions ongoing with S&P as well. Despite the higher pricing we've seen so far in 2026, our capital allocation for the year remains unchanged. We remain focused on increasing our financial resilience and utilizing our free cash flow to accelerate debt paydown with de-leveraging. With that, I'll hand it back to Andy.

Thanks, Neal. Turning now to slide 11 to conclude today's presentation. As I said in my opening remarks, we have 4 key objectives for 2026: grow production, lower costs, reduce debt, and advance our quality growth portfolio with minimal CapEx in 2026. This slide highlights the targets we've set against those objectives. On production, we now expect to complete the sale of EG around the middle of the year. Making that adjustment to the second half, we still feel we can achieve production growth close to that 15% target.

On costs faced on year-to-date performance so far, we feel confident that we can meet and potentially exceed our 20% operating cost reduction target. In aggregate, we're on track to deliver a reduction of around 35% in operating costs per BOE year-on-year. On debt with EG sale, equity raised and higher pricing, we're doubling our debt reduction target from 10% to around 20% by year-end and have made significant progress already. We are advancing our growth portfolio with Tiberius FID, progress on GTA expansion, and the exploration alliance with Shell in the Gulf of Mexico. We look forward to delivering on these objectives to support long-term value creation for our investors. Thank you. I'd now like to turn the call over to the operator to open the session for questions. Operator.

We will now begin the question-and-answer session. If you would like to ask a question at this time, simply press star followed by the number one on your telephone keypad. We will pause for a brief moment to compile a Q&A roster. Our first question comes from the line of Charles Meade with Johnson Rice. Charles, please go ahead.

Yes. Good morning, Andy, to you and the whole team there, or good afternoon as it may be. I wanna ask the first question on Jubilee. The OBN seismic shoot that you guys did at the end of the year last year, or the results or insights from that, are those already informing this 26 drilling program or is that something where we're really gonna see more of the benefit in the 27, 28 program?

Yeah. Hey, Charles. No, The OBN is really gonna have an impact on the 27, 28 program. Yeah. The 26 program though is leveraging the 4D NAZ that we shot, you know, ahead of the OBN. We've got the product from that and that did influence the selection of the 26 drilling program, which is going well. I think the objective then is to build the results from the early products of the OBN and then the later products of the OBN into the 27 program, match that with the NAZ. You're getting a continuous upgrade in the quality of the seismic and therefore, you know, the opportunity to de-risk the future drilling programs.

You know, as I said in my remarks, you know, we're seeing the impact of a continuous drilling program on Jubilee in 2026. You know, carrying that through into 2027, 2028 is clearly important. These are economically good wells. You know, In my remarks, I talked about, you know, a 6-month payback in a mid-cycle price environment. Clearly, we're doing better than that. A lot of, you know, as you know, there's a lot of opportunity in Jubilee and the seismic upgrade through the 4D NAZ and then the follow one of the OBN is continuing to make a difference.

Right. That's what I was aiming to get at. The follow-up on Tiberius in the Gulf of Mexico. I think you have a point in your slide that you expect a farm-out proceeds to cover any 2026 CapEx. That, you know, in broad strokes, it seems to me that, you know, the farm-out proceeds to you will, you know, be, you know, in the same order of magnitude as what the, you know, dry hole costs, proportion of dry hole costs would have been. It doesn't, you know, it doesn't look like there's a, you know, a big premium that you're looking for on this farm-out, but maybe you can tell me if that's the right read.

Yeah. Obviously, I don't want to disadvantage ourselves in the process that's ongoing at the moment. Look, I think it's a great time to be doing the farm-out. You know, we clearly have a project that's underway. FID has been taken, strong alignment between ourselves and Oxy, and therefore there's been significant interest in the opportunity. You know, we're obviously looking to maximize the farm-out proceeds, and we may do a little better than we'd anticipated.

Got it. Thank you, Andy.

Great. Thanks, Charles.

Your next question comes from the line of Lydia Gould with Goldman Sachs. Lydia, please go ahead.

Good afternoon, thanks for taking my question. You targeted 20% reduction in operating costs this year. Could you expand on some of the key strategic initiatives that are in place across the portfolio to meet this target, particularly at GTA? Thanks.

Yeah. Hi, Lydia. Yeah. Look, it's a you know, it's a combination. I think, you know, I wanna emphasize the fact that we've used the opportunity to high grade the portfolio and address some of our highest cost assets. Those highest cost assets were in Equatorial Guinea, where clearly we're selling the asset. Also it was on TEN because of the lease cost on the FPSO. Both of those are making a significant difference. There is then on top of that, there is an ongoing reduction in GTA. There's an absolute reduction in operating costs as you take out some of the additional costs that were in last year because of the startup process.

Clearly you're seeing a big impact on the per BOE number or MMBtu number because of the ramp-up in production. The combination of those sort of ongoing processes and the asset high grading, you know, delivers that 20% reduction in absolute operating costs that we're seeing in 2026 versus 2025. I think there's ongoing opportunity. We haven't stopped there. You know, I think there's ongoing opportunity in Ghana in 2027 as you look at the ability then to sort of, you'll have the operator then having the operations of both FPSOs. I think there's opportunity to create synergies there. Then there are different operating models in Mauritania, Senegal for GTA, which are being explored by BP.

I think, you know, this is just the start of a journey of continuing to drive costs down. The big step in 26 comes from that underlying activity, but also the high grading of the portfolio.

Thank you.

Great. Thanks, Lydia.

Your next question comes from the line of David Round with Stifel. David, please go ahead.

Great. Thanks, guys. A key theme in recent years has been around this cost reduction and capping CapEx actually specifically. I'm just interested in whether this commodity backdrop makes that harder to achieve and how you're thinking more generally about CapEx in 2027 and beyond, please.

Hi, David. Good questions. You know, we go through price cycles, and I think you do see some tightening. I think it's very hard to predict today what the long-term effect is on the inflation environment. I think it's too early to say that. I think the things that we're doing now are just not about smarter procurement, if you like. It's about underlying changes in how you do activity. I think that means that the cost reductions that we're targeting, the ongoing cost reductions we would target in Ghana and GTA are about changing the way you do business. Therefore, the activity changes, therefore the cost comes down. I think those are enduring.

I don't think they sort of are simply about the procurement cycle you're in. Clearly, the high grading of the portfolio is independent of that. I think, you know, that opportunity remains, and I don't think, you know, the magnitude may vary a little, but the opportunity remains. Then I think on CapEx, you know, we've clearly targeted CapEx hard in both 2025, 2026. I think that we're focused again on ensuring that we're being very rigorous about the allocation of capital. I think we've been clear around the growth opportunities that we're pursuing. It is Tiberius, it is the GTA expansion, trailblazer exploration.

In a timing sense of the spend flowing through, I think, you know, Tiberius is relatively low spend in 2027. The biggest spend is really in 2028. Probably, you know, if it's $100 million on Tiberius net, it's probably one third, two thirds in that sense. The GTA, you know, it's probably overall for phase one plus, there really isn't any expenditure on the facilities. You know, you can move from 430 to 630 production through the FPSO with no spend. It's about the additional wells that will sustain the portfolio beyond the end of the decade. The spend for that will really be in 2028, 2029.

When you take all of that, I don't think you'll see a significant, it's early days yet, but the capital for 2027 is going to be pretty tight. Maybe a little higher than today. For 2026, maybe around $400. Underneath that, you've got the sustaining CapEx that we're spending today in drilling in Ghana and the Gulf. That will sort of be pretty similar in 2027. You've got a little more growth CapEx, yeah. That allows you then, though, to continue to move forward these high quality prospects.

Okay. Thanks, Andy. That's very clear. Very quick follow-up then, actually, if I might. Can you just remind us if there is a specific leverage target, please?

Well, I'll pass that over to Neal.

Yeah. You know, David, we've always talked about getting to sort of 1.5 times in a normalized oil and price environment. You know, again, I think what you'll see this year is we'll, you know, we've said we'll take off, you know, around 20% of the debt. Which we started this year at $3 billion, which will get into sort of the mid-twos, you know, with higher oil prices, you can continue to flex that down. The EBITDA, the EBITDA of the business jumps quite largely. You know, last year we did something in the $500 million-$600 million range. We should be north of $1 billion this year in terms of where we get to. That leverage ratio compresses quite quickly.

I think, you know, again, from a, you know, as Andy said, you know, the capital has continued to stay a bit tight in 2027. That allows us to advance the projects and at the same time generate free cash flow to pay down the debt. The goal is to do both at the same time and get leverage, you know, what we'd like to see is sort of the net debt fall below $2 billion first in terms of a milestone. We'll make a good dent in that progress this year. You know, again, we're seeking to sort of maximize every dollar in terms of debt pay down.

Great. That's very clear. Thanks, guys.

If you would like to ask a question, just press star followed by the number one on your telephone keypad. Our next question comes from the line of Bob Brackett with Bernstein Research. Bob, please go ahead.

Good morning. I'd like to talk a bit about Senegal and GTA. You mentioned the Phase 1+, which I expect is a 300 million cubic feet a day gas pipeline that brings ultimately molecules up to that Gandon power plant. Can you talk about how to think about the unit economics? You mentioned it's reducing OPEX. How do we think about the volume? Is it your 27%? How do we think about price?

Yeah, Bob. Yeah, good questions. You know, I think that the first thing is I you know, it's somewhere that, you know, the expansion of GTA, I sort of think about it being sort of 200 million rather than 300. You can go from today, we're pushing about 430 million standard cubic feet through the FPSO. You can get to 630 without actually spending any capital on it, you know. You know, if you wanna go up higher than that, there is an increased demand. You know, there are incremental spend on capital to get there. Relatively modest.

If you think about the first wave being sort of 200, you know, the first piece of that domestically is a piece that will be used in Mauritania, a piece of it will be used in Senegal. The first piece in Senegal will flow to the Gandon Power Station, as you said. The RGS, which is the pipeline company in Senegal, will continue to build that pipeline south from Saint-Louis to Dakar. There's actually 4 phases. You can look online and see what they're doing, and it ultimately allows you to build out that sort of power station infrastructure, you know, down towards Dakar. It's gonna be a phased process that'll start to build through 2027, 2028, 2029, and to the end of the decade.

You know, actually, in terms of unit economics, the capital spend for us is very low. Sort of de minimis is the way to think about it for that 200 million standard cubic feet. There is capital spend to sustain the profile at the back end of the decade, which is associated with more wells to keep you at that sort of 630 million-650 million standard cubic feet. It ultimately is a very low cost expansion and therefore, you know, the margin that you're getting from it is high. You're almost, you know, from an operating cost perspective, there is no FLNG lease and therefore your margin on those versus the export is higher.

Again, I think the easy way to think about it, Bob, is just, you know, again, we've said sort of phase 1 OpEx is around sort of $5-$6 per MMBtu. That's fixed cost, essentially. The costs don't change with the expansion on the operating cost. Therefore, you get a sort of multiplying effect in terms of reducing that to sort of the sub 4 type area. Again, I think every incremental molecule helps bring down that break-even even faster.

For the domestic gas, you're not paying the FLNG cost, which is part of that sort of $4.

A follow-up, please. I'm seeing mixed messages in the press around Yakaar Teranga. Can you give us an update on what's happening there?

I don't think it's sort of mixed messages, Bob. I think that the key message out of it is around the importance of domestic gas for Senegal's growth. You know, relatively large population, growing population. Reducing the cost of power, electricity is a key priority for the government. You know, their goal is to ensure that they can advance those projects to do that in a timely way. It was about saying we wanna invest in GTA. You know, we want to enable the that source of domestic gas to be our focus. We did relinquish Yakaar Teranga. The government has picked it up.

Petrosen, I believe will lead that development, and it will be another source of gas for the country. You know, given the scale of the economic growth, I think the that can be seen basically from population growth, then it needs all the gas that the country needs all the gas that it can take. Mauritania is a slightly smaller, is a smaller population, so their pull for domestic gas will be lower and can be fed by GTA. This is good for both countries. You know, you know, clearly world events today are all about how do you create security and affordability. The extension now of both GTA and Yakaar Teranga will enable Senegal to achieve those goals, and we're fully supportive of it.

Very clear. Thanks.

Great. Thanks, Bob.

Our next question comes from the line of Mark Wilson with Jefferies. Mark, please go ahead.

Yeah, thank you. I'm gonna ask a question for an investor to start off with. It's probably more for Neal. Just wondering about the derivative cash losses in Q1 and what we should expect in 2026. Obviously, this speaks to this maximizing of de-leveraging. The cash derivatives, Neal?

Yeah, it's clearly a large mark-to-market change. Again, we came into the year with an asset, about $50 million, and then there's a $250 million mark-to-market loss just given, you know, we got payout in January and February on those hedges, and then clearly the market moved. From a cash perspective, it costs about $30 million. Not a ton of cash actually. Clearly the implied shift in the forward curve has an impact on the derivative side. Our hedges are largely focused on sort of the first half of this year. You know, we talked about we have 6 million barrels left for the rest of the year.

About half of that matures in Q2, and the other half over the 2nd half of the year. You know, there's a larger exposure in Q2 and then sort of less, and then that sort of steps down again in Q3 and Q4. It'll, it'll, yeah, ultimately depend on sort of what the actual realized Dated Brent price is. We feel okay with our exposure on 2026 and have really been, you know, working on adding, you know, some additional downside protection in 2027. I think we're good in terms of where we are. We'll, we'll have more physical exposure from a pricing perspective, as we talked about in the call, Mark, into Q.

There's a bigger, yeah, call it unhedged volume that we'll be able to realize in the second quarter with more physical volume being sold versus the hedges. I think Q2 is sort of shaping up quite nicely, and then the hedging exposure comes down, at least more access to the upside from the physical sale.

Okay. Thank you. Andy, can I a slightly bigger picture question. I'm just wondering what contact you've had with the, if at all, with the new management set up at BP, given Tortue's pro-performing so well, I'm just wondering if there's any commentary you could give there. Thank you.

No, look, you know, things change and they don't change. For us, clearly, and for BP, ensuring that GTA runs both efficiently from a cost perspective, but equally well from a production perspective, we deliver on the cargo forecast, et cetera. That's all going well, Mark, and You know, we sort of see no change. Clearly, Meg, the new CEO, has significant experience of Senegal from her experience at Woodside with Sangomar. As it were, we bring, you know, it's great. Somebody who has deep industry knowledge and very specific knowledge actually of that specific geography. You know, the real sort of answer is we know, as you'd expect, is that we're focused on the operational side at the moment and ensuring that we deliver on the targets we've set. Actually, that's exactly what we're doing.

Okay. Thank you. Just one last point. Just checking on.

Yeah

The Jubilee guidance. Is there any scheduled downtime on the vessel in the rest of the year, maintenance or anything?

I think you've asked that question before, right?

It's fairly recent.

Yeah. I like that question.

You do like that question, Mark. Yeah. The honest answer is no. Okay. None in 22 and none in 27. I think that's what the operator told you last time. No. The answer is no scheduled maintenance. Look, if you, if I go to the essence of your question, right, are we comfortable with our guidance? The answer's sort of yes. You know, we, and why, you know, as we started the year, we were clear it's all about forecasting. Yeah. Of course, you know, sort of getting close to the middle of May, you have a lot of extra information. You know, the field started the year at, you know, we ended the year of 2025 at 57,000 barrels of oil per day.

We've stabilized it. We've added 2 wells. It's delivered at 70,000 barrels of oil per day, year to date. Very strong performance with 2 wells added. We're now have drilled 3 wells. We have all of the logging information, pressure data, et cetera. You know, we're confident. We're adding wells that'll will add an additional 20,000. You build the base of 70, you add another 20, and you can see on our plot that we showed in the, in the presentation, you know, the resulting production profile. I think, you know, the, to the point really to add is, look, we, we're further down the process. We've clearly delivered strongly in the first 4 or 5 months of the year.

We've got additional data from the wells that we've drilled, and we're now starting that completion process. I think with as every month goes by, we're more confident that we can deliver on the guidance that we've given with no shutdowns in 26.

I've made a very clear note of that. I won't have to ask again. Thank you very much.

You bet. Thanks, Mark.

Your next question comes from the line of Stella Cridge with Barclays. Stella, please go ahead.

Hi there. Good morning, good afternoon, and many thanks for all the updates today. I just wondered if I could ask you for a bit more color or comments on how you're thinking about the debt profile going forward. You've obviously taken many actions year to date to address, you know, many different parts of the capital structure. The RBL discussions, you say they're going to commence around about mid-year. Could you give us any sense of what you think the lenders will be looking for there? Would it be sort of the visibility around Jubilee, for instance, you know, in this supportive oil price environment?

Yes, Stella.

Go for it.

No. Good. Yeah, well, I'm happy to give that, and then if you have another question, we can follow up. Yeah, like you said, we've been quite busy on the financing front. Again, what we wanted to accomplish is pretty clear in terms of clearing out the near-term maturities and bolstering liquidity to stabilize the ratings and continue to reduce the absolute amount of debt. Again, as I say, we're well on track to deliver all of that. You know, we've cleared the 2026s and most of the 2027s at this point. Liquidity is, you know, $500 million and growing. We're on our way down on the debt pay down to get to, you know, into the low 2s from a leverage standpoint by the end of the year.

Again, I think all that's on track, and that leaves sort of the Yeah, as you referenced, sort of the next financing objective for us to work on is the extension of the RBL. Just to recall, this would be the 6th RBL extension that we go through or that I've been through here at Kosmos. You know, again, normally just, you know, it's a 7-year facility. It doesn't amortize for 3 years, and then you end up extending the tenor every 3 years. You know, met with the banks recently. Again, they've continued to be really supportive. You know, they are looking for Jubilee performance to continue to improve, but again, I think that process is well underway, as Andy noted.

Otherwise, again, I think they wanna see the same thing that our creditors and equity holders wanna see, which is us to bring the leverage down. As we execute the plan, again, I feel pretty good about going into that process in the middle of this year. Then that'll basically kick the maturity from the ultimate maturity from sort of the 2029 to sort of the 2032, 2033 timeframe.

Super. Thank you for that. Just the final bit I had wanted to ask about. I thought it was very interesting in the Fitch report that they were talking about, you know, potentially you trying to get down into the kind of $800s to refinance a smaller amount of the RBL. Is that something you could comment on as well?

Yeah. You know, we exited 1 Q with about $1 billion drawn on the facility. You know, with the EG proceeds coming in around $150-ish million free cash flow. You know, again, I think naturally the RBL will reduce into that range from a drawn perspective. From a total facility size perspective, though, which is, you know, what we'll generally extend, I wouldn't expect much change. You know, we were at sort of $1.3 billion facility size. We'll probably, you know, we probably don't need that much just because we're bringing down the amount of the absolute amount of both bonds and bank within the capital structure. You know, maybe it's $1 and a quarter-ish in terms of facility size. I wouldn't expect the size to change dramatically, although, again, I think the bigger focus on our side is just reducing the drawn, the actual drawn amount.

That's all clear. Thanks. Excellent.

Since there are no further questions at this time, I would like to bring the call to a close. Thanks to everyone joining today. You may disconnect your lines at this time. Thank you for your participation.