Kosmos Energy Ltd. Q1 FY2026 Earnings Call

Good day, everyone. Welcome to Kosmos Energy First Quarter 2026 Conference Call. As a reminder, today's call is being recorded at this time. I would like to turn the call over to Jamie Buckland, Vice President of Investor Relations.

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

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 off 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 off 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.

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 and 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 U.S. 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, and discussions are 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.

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?

Our first question comes from the line of Charles Meade with Johnson Rice.

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, are the results or insights from that already informing this 2026 drilling program? Or is that something where we're really going to see more of the benefit in the 2027, 2028 program?

Charles, no, the OBN is really going to have an impact on the 2027-2028 program. So, the 2026 program, though, is leveraging the 4D NAS that we shot ahead of the OBN. We've got the product from that, and that did influence the selection of the 2026 drilling program, which is going well. 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 2027 program, and match that with the NAS. So, you're getting a continuous upgrade in the quality of the seismic and therefore the opportunity to de-risk the future drilling programs. As I said in my remarks, we're seeing the impact of a continuous drilling program on Jubilee in 2026. Carrying that through into 2027 and 2028 is clearly important. These are economically good wells: in my remarks, I talked about a six-month payback in a mid-cycle price environment. Clearly, we're doing better than that. 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.

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 2026 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.

Yes. Obviously, I don't want to disadvantage ourselves in the process that's ongoing at the moment. 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. Therefore, there's been significant interest in the opportunity. We're obviously looking to maximize the farm-out proceeds, and we may do a little better than we'd anticipated.

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

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?

Yes, Lydia. It's a combination. 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, which we are selling, and also on TEN because of the lease cost on the FPSO. 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. You're also seeing a big impact on the per BOE number or per MMBtu number because of the ramp-up in production. The combination of those ongoing processes and the asset high-grading delivers that 20% reduction in absolute operating costs that we're seeing in 2026 versus 2025. There is ongoing opportunity. I think there's ongoing opportunity in Ghana in 2027 as you look at the ability to have the operator managing the operations of both FPSOs. 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. This is just the start of a journey of continuing to drive costs down and the big step in 2026 comes from that underlying activity, but also the high-grading of the portfolio.

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

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?

Yes, David, good questions. We go through price cycles, and you do see some tightening. 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. The things that we're doing now are just not about smarter procurement; it's about underlying changes in how we do activity. That means 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 and the cost comes down. Those are enduring. The high-grading of the portfolio is independent of that. On CapEx, we've clearly targeted CapEx hard in both 2025 and 2026. We're focused on ensuring that we're being very rigorous about the allocation of capital. We've been clear around the growth opportunities that we're pursuing: Tiberius, the GTA expansion, and trailblazer exploration. In a timing sense of the spend flowing through, Tiberius is relatively low spend in 2027; the biggest spend is really in 2028. If it's $100 million net on Tiberius, it's probably a one-third/two-thirds split in that sense. For GTA, 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. The spend for that will be in 2028-2029. So I don't think you'll see a significant jump; it's early days yet, but the capital for 2027 is going to be pretty tight, maybe a little higher than 2026, maybe around $400 million. Underneath that, you've got the sustaining CapEx that we're spending today in drilling in Ghana and the Gulf. That will be pretty similar in 2027, and then you've got a little more growth CapEx. But that allows you then to continue to move forward these high-quality prospects.

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?

Yes. We've always talked about getting to around 1.5x in a normalized oil price environment. This year, we said we'd take off around 20% of the debt. We started this year at about $3 billion, which we get into sort of the mid-2s, and then with higher oil prices, you can continue to flex that down. The EBITDAX of the business jumps quite considerably. Last year we did something in the $500 million to $600 million range, and this year we should be north of $1 billion in terms of where we get to. So that leverage ratio compresses quickly. From a milestone perspective, we'd like to see net debt fall below $2 billion first. We'll make a good dent in that progress this year. We're seeking to maximize every dollar in terms of debt paydown.

And our next question comes from the line of Bob Brackett with Bernstein Research.

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?

Bob, good questions. I think that the first thing is the expansion of GTA—I think about it being closer to $200 million rather than $300 million. You can go from today, we're pushing about 430 million standard cubic feet through the FPSO, and 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 and incremental capital to get there, but it's relatively modest. Think about the first wave being around $200 million. The first piece of that domestically will be used in Mauritania, a piece in Senegal. The first piece in Senegal will flow to the Gandon Power Station. Then the RGS, which is the pipeline company in Senegal, will continue to build that pipeline south from Saint-Louis to Dakar. There are four phases ultimately, and that will allow you to build out power station infrastructure down towards Dakar. It's going to be a phased process that will build through 2027-2029 and to the end of the decade. In terms of unit economics, the capital spend for us is very low—de minimis for that initial 200 million standard cubic feet. There is capital spend to sustain the profile at the back end of the decade associated with more wells to keep you at 630 million to 650 million standard cubic feet. Ultimately, it is a very low-cost expansion and therefore the margin is high. From an operating cost perspective, there is no FLNG lease for the domestic gas, so your margin on those molecules versus the export is higher.

The easy way to think about it, Bob, is we've said Phase I OpEx is around $5 to $6 per MMBtu. That's essentially fixed cost. The costs don't change with the expansion on operating cost, and therefore you get a multiplying effect in terms of reducing that to the sub-$4 area. Every incremental molecule helps bring down that breakeven even faster.

And for the domestic gas, you're not paying the FLNG cost, which is part of that benefit versus export.

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 mixed messages. The key message is the importance of domestic gas for Senegal's growth: a relatively large, growing population and the need to reduce the cost of power. The government's priority is to advance those projects in a timely way. For Kosmos, our focus was on investing in GTA and enabling that source of domestic gas. 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. Given the scale of economic growth, the country needs all the gas it can take. Mauritania is a smaller population, so the pull for domestic gas will be lower and can be fed by GTA. This is good for both countries. The extension of both GTA and Yakaar-Teranga will enable Senegal to achieve security and affordability, and we are fully supportive of that.

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

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.

So yes, the cash derivatives—Neal?

Yes. It's clearly a large mark-to-market change. We came into the year with an asset of about $50 million and then recorded a $250 million mark-to-market loss given the market moved and some of those hedges paid out in January and February. From a cash perspective, it cost us about $30 million and not a ton of cash. The implied shift in the forward curve has an impact on the derivative side. Our hedges are largely focused on the first half of this year. We have 6 million barrels left for the rest of the year—about half matures in Q2 and the other half over the second half of the year. So there's a larger exposure in Q2 and then it steps down in Q3 and Q4. It will ultimately depend on the actual realized Dated Brent price. We feel okay with our exposure on 2026 and have been working on adding additional downside protection in 2027. We'll have more physical exposure from a pricing perspective in Q2, so there's a bigger unhedged volume that we'll be able to realize in the second quarter with more physical volume being sold versus the hedges. Q2 is shaping up nicely and the hedging exposure comes down, giving more access to the upside from the physical sales.

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

Things change, and they don't change. For us and for BP, the focus is ensuring GTA runs efficiently from a cost perspective and delivers on production and cargo forecasts. That's all going well. Meg, the new CEO at BP, has significant experience of Senegal from her time at Woodside with Sangomar, which is helpful. As expected, we're focused on the operational side and ensuring that we deliver on the targets we've set. That's exactly what we're doing.

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?

No, there is no scheduled maintenance in 2026 and 2027. Are we comfortable with our guidance? Yes. As we started the year, forecasting was unclear, but now, getting close to mid-May, we have a lot of extra information. The field started the year at 57,000 barrels of oil per day at the end of 2025. We've stabilized it and added two wells, delivering 70,000 barrels of oil per day year-to-date. Very strong performance with two wells added. We have now drilled three wells and have all logging information, pressure data, etc. We're confident we're adding wells that will add an additional 20,000 barrels. So you build a base of 70,000 and add another 20,000. You can see our plot and the resulting production profile. We're further down the process, having delivered strongly in the first four to five months of the year. We have additional data from the wells we've drilled and are starting the completion process. As every month goes by, we're more confident that we can deliver on the guidance with no shutdowns in 2026.

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

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 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?

I'm happy to do that. We've been quite busy on the financing front. What we wanted to accomplish was clear in terms of clearing out near-term maturities, bolstering liquidity, stabilizing ratings, and continuing to reduce the absolute amount of debt. We've cleared the 2026s and most of the 2027s. Liquidity is $500 million and growing. 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. The next financing objective is the extension of the RBL. This would be the sixth RBL extension we've gone through at Kosmos. Normally it's a 7-year facility, it doesn't amortize for 3 years, and then you end up extending every 3 years. I met with the banks recently; they continue to be supportive. They are looking for Jubilee performance to continue to improve. That process is well underway. They want to see the same thing our creditors and equity holders want to see: for us to bring the leverage down. As we execute the plan, I feel pretty good about going into that process in the middle of this year. That would move the ultimate maturity from around 2029 to the 2032-2033 time frame.

I thought it was interesting in the report that they were talking about potentially trying to get down into the $800 million drawn to refinance a smaller amount in the RBL. Is that something you could comment on as well?

We exited Q1 with about $1 billion drawn on the facility, with the Equatorial Guinea proceeds coming in around $150 million plus free cash flow. Naturally, the RBL drawn amount will reduce into that range. From a total facility size perspective, which is what will generally extend, I wouldn't expect much change. We were at about a $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 around $1.25 billion in terms of facility size. I wouldn't expect the size to change dramatically. The bigger focus on our side is just reducing the actual drawn amount.

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.