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DATE

Tuesday, May 5, 2026 at 11 a.m. ET

CALL PARTICIPANTS

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

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TAKEAWAYS

  • Production Growth -- Total production increased approximately 25% year over year, reaching a record 75,000 BOE per day, attributed to ramp-up at GTA and new wells at Jubilee.
  • Operating Cost Reduction -- Absolute operating costs decreased about 22% year over year; OpEx per BOE fell by 47% to just under $20, with progress attributed to portfolio high-grading and asset sales.
  • Net Debt Reduction -- Net debt declined by roughly 7% from year-end 2025, with a target for a 20% reduction by year-end 2026, up from the original 10% goal.
  • Liquidity Position -- Kosmos exited the quarter with around $500 million in liquidity after a $350 million Nordic bond issue, $250 million of 2027 notes repurchased, $100 million bank facility repayment, and a $200 million equity raise.
  • GTA LNG Output -- GTA produced around 2.85 million tons per annum gross, exceeding nameplate capacity of 2.7 million; 9.5 gross LNG cargos lifted, with 32–36 cargos projected for the full year.
  • Jubilee Field Performance -- Gross oil production reached approximately 70,000 barrels per day in Q1, with three additional producer wells to be completed in June and July, expected to add 20,000 barrels per day gross before natural decline in Q4.
  • Gulf of America Production Outlook -- Winterfell-2 shut-in will drive full-year Gulf of America output to the lower end of guidance; final investment decision (FID) was taken on the low-cost Tiberius project, with first oil targeted in H2 2028.
  • Sales Pricing Structure -- Roughly 50% of Kosmos’ production, primarily from Ghana, is priced off Dated Brent, which saw its premium over WTI more than triple since the Middle East conflict began; rising price and differential benefits will be recognized in revenue during the second and third quarters due to contractual lags.
  • OpEx Guidance and Drivers -- Full-year guidance for operating cost reduction remains at 20%, with year-to-date trends indicating potential to exceed this target, supported by the Equatorial Guinea asset sale and TEN FPSO lease replacement.
  • Capital Structure Management -- Proceeds from the Equatorial Guinea sale, set to close mid-year, will be used to pay down the reserve-based lending facility; banks have approved a covenant waiver through mid-year and the asset sale.
  • Hedging Update -- Company maintained active hedging in early 2026, resulting in a $30 million cash derivatives loss in Q1 despite a $250 million mark-to-market loss; more physical exposure to unhedged pricing is expected in Q2 and beyond as hedges roll off.
  • Tiberius Farm-Out -- Kosmos commenced a farm-out process for Tiberius in the Gulf of America, aiming to reduce its working interest to around one-third; farm-out proceeds are anticipated to cover 2026 CapEx for the project.
  • GTA Expansion Financing -- West African Development Bank mandated as lead arranger for GTA expansion financing with a $270 million target; $90 million tranche approved by the Board at March-end.
  • Credit Rating Upgrade -- Fitch upgraded Kosmos' corporate credit rating to B- in April, reflecting financial progress in 2026; S&P discussion is ongoing.
  • Leverage Target -- Company targets net debt falling below $2 billion and a long-term leverage ratio around 1.5x in a normalized oil price environment, as leverage compresses with projected EBITDAX increases above $1 billion for the year.

SUMMARY

Kosmos Energy Ltd. (KOS 4.59%) reported acceleration on its main 2026 objectives, highlighting above-capacity LNG performance at GTA, operational momentum at Jubilee, and a strengthened balance sheet through liquidity actions and net debt reduction. Strategic initiatives included a finalized Tiberius FID, the advancement of a multi-phase GTA expansion project, and a significant step-up in deleveraging targets backed by ongoing asset divestitures. Management underlined that positive pricing differentials will increasingly benefit results starting in the second quarter due to inherent contractual lags, positioning the company to capture more upside from the current oil market environment.

  • The Equatorial Guinea divestiture will reshape Kosmos’ production mix and further accelerate debt repayment as the transaction closes.
  • Asset high-grading, notably the exit from Yakaar-Teranga, allows the company to concentrate on more commercially favorable projects, especially in Mauritania and GTA.
  • Long-term cost improvements are supported by business-model changes, with management stating that anticipated reductions are “about changing the way you do business,” rather than solely being procurement-driven.
  • RBL facility discussions will commence mid-year, with lenders mainly seeking visible operational consistency at Jubilee and continued progress on leverage reduction.
  • Phase 1 expansion of GTA infrastructure is progressing both physically and financially, with half of the land for Senegal’s onshore pipeline cleared and pipeline exports scheduled around mid-year.
  • Scheduled maintenance at Jubilee is not anticipated for 2026 or 2027, supporting production guidance confidence.

INDUSTRY GLOSSARY

  • BOE (Barrels of Oil Equivalent): A standard unit for measuring oil and gas production, combining oil, gas, and NGL volumes based on energy content.
  • GTA (Greater Tortue Ahmeyim): A cross-border offshore gas project developed by Kosmos Energy, BP, and partners, producing LNG and condensate.
  • FPSO (Floating Production Storage and Offloading): A vessel used for the processing and storage of hydrocarbons produced offshore.
  • FID (Final Investment Decision): The point at which a company formally commits capital to the construction and development of a project.
  • RBL (Reserve-Based Lending): A revolving credit facility secured against the value of the company’s producing hydrocarbon reserves.
  • OpEx: Operating expenditure, specifically the costs required to run production and related activities.
  • MMBTU: One million British thermal units, a standard unit for measuring energy, typically used for natural gas.
  • Dated Brent: A physically settled oil price benchmark used to price crude produced in the North Sea and, by extension, other international oil streams.
  • TEN: An oil and gas development project offshore Ghana comprising the Tweneboa, Enyenra, and Ntomme fields operated by Tullow Oil with Kosmos as a partner.
  • OBN (Ocean Bottom Node): A seismic survey technology that uses ocean-floor sensors to acquire high-resolution data for subsurface imaging.
  • 4D NAS (4D Non-Azimuthal Seismic): A type of time-lapse seismic imaging utilized to monitor changes in oil and gas reservoirs over production cycles.
  • HLS (Heavy Louisiana Sweet): A crude oil benchmark with pricing relevance in the U.S. Gulf of Mexico.
  • NOC (National Oil Company): A state-owned oil and gas company, often partnering with private-sector E&P companies.

Full Conference Call Transcript

Andrew Inglis: Thanks, Jamie, and 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 of premium benchmarks before focusing on each business unit and the operational progress we've made year-to-date. I'll then hand over to Neal to talk about the financials before I wrap up with closing remarks. We'll then 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% and 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 see 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 but 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 5. 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 America, are all priced of premium benchmarks. In fact, across the U.S. 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 cargos are typically priced off an average 5- 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, but 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 1-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 at 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. So, 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, which looks at 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-'26 drilling campaign continues to perform strongly. The J74 well came online in early 2026, followed by the J75 well at the end of the quarter. Both wells are 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 has been drilled and completion operations start shortly. Based on the logging results, these 3 wells should drive a material uplift in production of 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 barrels a day gross oil production guidance for Jubilee this year.

Looking at the bottom right of the slide, we're 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 targeted to restart around mid-2027. As we previously discussed, this regular drilling program is key to sustaining the improved performance we've seen 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 of around six 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 lifted during the quarter, in line with guidance. For the year ahead, our gross cargo guidance of 32 to 36 LNG cargos is unchanged. One gross condensate cargo was lifted in the quarter, which went to BP. The second and third condensate cargos later in the year, including one this quarter, are expected to be assigned to Kosmos and the NOCs.

Due to some seasonality that we flagged 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 then 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 see 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 middle of the year. The West African Development Bank has been appointed as 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 toward 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 an expected development cost of around $10 per barrel and operating and transport costs of around $20 per barrel for the first phase, this is a low-cost, high-margin development.

The first phase will be a single well tie-back 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 have commenced a 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 America and exchanged interests across multiple blocks across the North Pole play, which houses several material exploration prospects. We expect to drill the first of these, Tiberius, in the first half of 2027. Tiberius is targeting around 200 million barrels of oil equivalent gross resource.

I'll now turn to Neal to take you through the financials.

Neal Shah: 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 mentioned earlier, 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 ad overheads 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 have included the usual guidance in the appendix to the slides. Q2 production is expected to be slightly lower than 1Q, largely due to seasonality on GTA we talked about, and lower Gulf of America production on the back of Winterfell-2.

In Ghana, we're guiding to three to four cargos in Q2, which also includes a TEN cargo in the quarter. This also drives higher Q2 OpEx as a result of the accrued TEN 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 three or four 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 will 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 US and cost recovery at GTA. Turning to Slide 10. We've had a busy start to the year on the financing side, completing several important objectives that set us up well for the year ahead. In January, we completed a $350 million Nordic bond and 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 are 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-, a positive move to reflect the progress we have been making so far in 2026, but discussion ongoing with S&P as well. Despite the higher pricing we have 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 deleveraging. With that, I will hand it over to Andy

Andrew Inglis: Thanks, Neal. Turning now to Slide 11 to conclude today's presentation. As I said in my opening remarks, we have four 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 for the second half, we still feel we can achieve production growth close to that 15% target. On costs, based on year-to-date performance so far, we feel confident that we can meet and potentially exceed our 20% operating cost reduction target.

So, in aggregate, we're on track to deliver a reduction of around 35% in operating cost for BOE year-on-year. On debt with the EG sale, equity raise and higher pricing, we're doubling our debt reduction target from 10% to around 20% by year-end and have made significant progress already. And we are advancing our growth portfolio with Tiberius FID, progress on GTA expansion and the exploration alliance with Shell in the Gulf of America. We look forward to delivering on these objectives to support long-term value creation for our investors. Thank you. And I'd now like to turn the call over to the operator to open the session for questions. Operator?

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

Charles Meade: I want to ask the first question on Jubilee. The OBN seismic shoot that you guys did at the end of the year last year, is that, are the results or insights from that, are those already informing this '26 drilling program? Or is that something where we're really going to see more of the benefit in the '27, '28 program?

Andrew Inglis: Charles, no, the OBN is really going to have an impact on the '27, '28 program, yes. So, the '26 program, though, is leveraging the 4D NAS that we shot ahead of the OBN. And so, we've got the product from that, and that did influence the selection of the '26 drilling program, which is going well. So, 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 NAS. And so, you're getting a continuous upgrade in the quality of the seismic and therefore, the opportunity to derisk the future drilling programs.

And as I said in my remarks, the, we're seeing the impact of a continuous drilling program on Jubilee in '26. Carrying that through into '27, '28 is clearly important. And these are economically good wells. In my remarks, I talked about a 6-month payback in a mid-cycle price environment. Clearly, we're doing better than that. So, a lot of, as you know, there's a lot of opportunity in Jubilee and the seismic upgrade through the 4D NAS and then the follow-on of the OBN is continuing to make a difference.

Charles Meade: Right. That's what I was aiming to get at. And then 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 '26 CapEx? That maybe in broad strokes, it seems to me that the farm-out proceeds to you will be on the same order of magnitude as what the dry hole cost, proportion of dry hole cost would have been. And so, it doesn't look like there's a big premium that you're looking for on this farm-out, but maybe you can tell me if that's the right read.

Andrew Inglis: Yes. 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 in the farm-out. 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. So, we're obviously looking to maximize the farm-out proceeds, and we may do a little better than we'd anticipated.

Operator: And your next question comes from the line of Lydia Gould with Goldman Sachs.

Lydia Gould: You target a 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?

Andrew Inglis: Yes. Lydia, yes, look, it's a combination. And I think I want to emphasize the fact that we've used the opportunity to high-grade the portfolio and address some of our highest cost assets. And those highest cost assets were in Equatorial Guinea, where clearly, we are selling the asset. And also, it was on TEN because of the lease cost on the FPSO. So those, both of those are making a significant difference. 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 start-up process.

But clearly, you're seeing a big impact on the per BOE number or MMBTU number because of the ramp-up in production. But the combination of those sort of ongoing processes and the asset high-grading delivers that 20% reduction in absolute operating costs that we're seeing in '26 versus '25. And I think there's ongoing opportunity. We haven't stopped there. I think there's ongoing opportunity in Ghana in '27 as you look at the ability then to sort of, you'll have the operator than having the operations of both FPSO. I think there's opportunity to create synergies there. And then there are different operating models in Mauritania and Senegal for GTA, which are being explored by BP.

So, I think this is just the start of a journey of continuing to drive cost down and the big step in '26 comes from that underlying activity, but also the high grading of the portfolio.

Operator: And your next question comes from the line of David Round with Stifel.

David Round: 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 '27 and beyond, please?

Andrew Inglis: Yes. David, yes, good questions. We go through price cycles, yes. 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 inflationary environment. I think it's too early to say that. But 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. And I think that means that the cost reductions that we're targeting and 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. So I think those are enduring.

I don't think they sort of are simply about the procurement cycle you're in. And clearly, the high grading of the portfolio is independent of that. So I think that opportunity remains, and I don't think the magnitude may vary a little, but the opportunity remains. And then I think on CapEx, we've clearly targeted CapEx hard in both '25, '26. I think that we're focused again on ensuring that we're being very, 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 Tiberius is relatively low spend in '27.

The biggest spend is really in '28, probably if it's $100 million on Tiberius net, it's probably 1/3, 2/3 in that sense. The GTA, it's probably overall for Phase 1 plus there really isn't any expenditure on the facilities. You can move from 430 to 630 production through the FPSO with no spend. Therefore, it's about the additional wells that will sustain the portfolio beyond the end of the decade. And therefore, the spend for that will really be in '28, '29.

So we take all of that, I don't think you'll see a significant, it's early days yet, but the capital for '27 is going to be pretty tight, maybe a little higher than today for '26, maybe around $400 million. But 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 '27. And then you've got a little more growth CapEx. But that allows you then though to continue to move forward these high-quality prospects.

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

Andrew Inglis: I'll pass it over to Neal.

Neal Shah: Yes. And so David, we've always talked about getting to sort of 1.5x in a normalized oil price environment. And again, I think what you'll see this year is we said we'll take off around 20% of the debt. We started this year at $3 billion, which we get into sort of the mid-2s. And then with higher oil prices, you can continue to flex that down. And then the EBITDAX of the business jumps quite largely. So last year, we did something in the $500 million to $600 million range, which should be north of $1 billion this year in terms of where we get to. And so that leverage ratio compresses quite quickly.

But I think, again, from, Andy said, the capital has continued to stay a bit tight in '27, but that allows us to advance the projects and at the same time, generate free cash flow to pay down the debt. So the goal is to do both at the same time and get leverage, what we'd like to see is sort of the net debt fall below $2 billion first in terms of a milestone. So we'll make a good dent in that progress this year. And again, we're seeking to sort of maximize every dollar in terms of debt paydown.

Operator: [Operator Instructions] And our next question comes from the line of Bob Brackett with Bernstein Research.

Bob Brackett: I'd like to talk a bit about Senegal and GTA. You mentioned the Phase 1 plus, which I expect is a 300 million cubic feet a day gas pipeline that brings ultimately molecules up to that Gandon Power Station. 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%? And how do we think about price?

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

But if you think about the first wave being sort of $200 million, the first piece of that domestically, piece of it 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. Then the RGS, which is the pipeline company in Senegal, we'll continue to build that pipeline south from Saint-Louis to Dakar. There's actually four phases. You can look online and see what they're doing and ultimately allows you to build out that sort of power station infrastructure down towards Dakar.

So it's going to be a phased process that will start to build through '27, '28, '29 and to the end of the decade. So 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. But ultimately, it is a very low-cost expansion. And therefore, the margin that you're getting from it is high.

You're almost, from an operating cost perspective, there is no FLNG lease. And therefore, your margin on those versus the export is higher.

Neal Shah: And again, I think the easy way to think about it, Bob, is just, again, we've said sort of Phase I OpEx is around sort of $5 to $6 per MMBTU. That's fixed cost essentially. The costs don't change with the expansion on the operating cost. And therefore, you get a sort of multiplying effect in terms of reducing that to sort of the sub four type area. So again, I think every incremental molecule helps bring down that breakeven even faster.

Andrew Inglis: And then for the domestic gas, you're not paying the FLNG cost, which is part of that sort of $4.

Bob Brackett: 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?

Andrew Inglis: Yes. 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, relatively large population, growing population, reducing the cost of power, electricity is a key priority for the government. And therefore, their goal is to ensure that they can advance those projects and do that in a timely way. But at Kosmos, it was about saying we want to invest in GTA. We want to enable that source of domestic gas to be our focus. And therefore, 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. But given the scale of the economic growth, I think, 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 population. So the pull for domestic gas will be lower and can be fed by GTA. So this is good for both countries. ?And clearly world events today are all about how do you create security and affordability and the extension now of both GTA and Yakaar-Teranga will enable Senegal to achieve those goals and we are fully supportive of it.

Operator: Our next question comes from the line of Mark Wilson with Jefferies.

Mark Wilson: I got a question from 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. And obviously, this speaks to this maximizing of deleverage.

Andrew Inglis: So yes, the cash derivatives, Neal?

Neal Shah: Yes. Yes, it's clearly a large mark-to-market change. And again, we came into the year with an asset of about $50 million, and then there's a $250 million market-to-market loss, just given we got payout in January and February on those hedges, and then clearly, the market moved. From a cash perspective, it cost us about $30 million and not a ton of cash, actually. But clearly, the implied shift in the forward curve has an impact on the derivative side. Our hedges are largely sort of yes, focused on sort of the first half of this year.

So 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 second half of the year. And so there's a larger exposure in Q2 and then sort of less, and then that sort of steps down again in Q3 and Q4. And so again, it will ultimately depend on sort of what the actual realized Dated Brent price is. But we feel okay with our exposure on '26 and have really been working on adding some additional downside protection in '27. And so again, I think we're good in terms of where we are.

We'll have more physical exposure from a pricing perspective, as we talked about in the call in 2Q. And so there's a bigger, call it, unhedged volume that we'll be able to realize in the second quarter, with more physical volume being sold versus the hedges. So again, 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.

Mark Wilson: Okay. And Andy, a slightly bigger picture question. I'm just wondering what contact you've had with, if at all, with the new management setup at BP, given Tortue is performing so well. I'm just wondering if there's any commentary you could give there.

Andrew Inglis: No. Look, 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. So that's all going well, Mark. And we sort of see no change. Clearly, Meg, the new CEO, has significant experience of Senegal from her experience at Woodside with Sangomar. So as we bring, it's great, somebody who has deep industry knowledge and very specific knowledge actually of the, of that Pacific geography.

So the real sort of answer is, 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. And actually, that's exactly what we're doing.

Mark Wilson: Okay. And then just one last point, just checking on the Jubilee guidance. Is there any scheduled downtime on the vessel in the rest of the year, maintenance or anything?

Andrew Inglis: I think you've asked that question before. You do like that question. The honest answer is no, okay? So none in '26 and '27. I think that's what the operator told you last time. So, no, the answer is no scheduled maintenance. And look, if I go to the essence of your question, right, are we comfortable with our guidance? The answer is sort of yes. And why? As we started the year, we were unclear about forecasting yet. But of course, now, sort of getting close to the middle of May, you have a lot of extra information. The field started the year at, we ended the year '25, at 57,000 barrels of oil per day. We've stabilized it.

We've added two wells. It's delivered at 70,000 barrels of oil per day. year-to-date. So very strong performance with two wells added. We have now drilled three wells. We have all of the logging information, pressure data, et cetera. So, we're confident we're adding wells that will add an additional 20,000. So, you built a base of 70,000, and you add another 20,000. And you can see on our plot, which we showed in the presentation, the resulting production profile. So, I think to the point really, to add is, look, 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. So, I think 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.

Operator: And your next question comes from the line of Stella Cridge with Barclays.

Stella Cridge: 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 have taken many actions year-to-date to address many different parts of the capital structure. The RBL discussions, you said, are going to commence around a bit midyear. 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, in this supportive oil price environment?

Neal Shah: No, I'm happy to do that. And then if you have another question, we can follow up. But yes, like I said, we've been quite busy on the financing front. And again, what we wanted to accomplish is pretty clear in terms of clearing out the near-term maturities and bolstering liquidity, sort of stabilizing the ratings and continuing to reduce the absolute amount of debt. So again, as I say, we're well on track to deliver all of that. We've cleared the '26s and most of the '27s at this point. Liquidity is $500 million and growing.

And we're on our way down on the debt paydown to get into the low 2s from a leverage standpoint by the end of the year. So again, I think all that's on track. And that leaves sort of, 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 sixth RBL extension that we've gone through or that I've been through here at Kosmos. And so again, normally, it's a 7-year facility, it doesn't amortize for 3 years, and then you end up extending the tenure every 3 years. And so, I met with the banks recently.

Again, they continue to be really supportive. They are looking for Jubilee performance to continue to improve. But again, I think that process is well underway, as Andy noted. And otherwise, again, I think they want to see the same thing that our creditors and equity holders want to see, which is for us to bring the leverage down. So as we execute the plan, again, I feel pretty good about going into that process in the middle of this year. And then that will basically kick, the ultimate maturity from sort of '29 to sort of the 32, 33 time frame.

Stella Cridge: And just want to ask, I thought it was very interesting in the report that they were talking about potentially you're trying to get down into the $800 million to refinance a smaller amount in the RBL. Is that something you could comment on as well?

Neal Shah: Yes. And so we exited 1Q with about $1 billion drawn on the facility, with the EG proceeds coming in around $150-ish million free cash flow. Again, I think naturally, the RBL will reduce into that range from a drawn perspective. From a total facility size perspective, though, which is what will generally extend, I wouldn't expect much change. We were at a sort of $1.3 billion facility size. We probably don't need that much just because we're bringing down, the absolute amount of both bonds and bank within the capital structure. So maybe it's 1.25-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 actual drawn amount.

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