Good day, everyone. Welcome to Kosmos Energy's First Quarter 2025 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 at Kosmos Energy.

Thank you, operator, and thanks to everyone for joining us today. This morning, we issued our first quarter 2025 earnings release. This release and the slide presentation to accompany today's call are available on the investors page of our website. Joining me on the call today to go through the materials are Andy 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 Andy.

Thanks, Jamie, and good morning and afternoon to everyone. Thank you for joining us today for our first quarter results call. I'll start off the call by reinforcing the messages I gave in February with our full year results, which apply even more so in today's volatile market. Kosmos continues to focus on prioritizing cash generation, rigorous cost control, and enhancing the financial resilience of the company. I'll then provide an update on the operational progress we've made so far this year and the outlook for the remainder of 2025. Neal will then walk you through the quarter's results and the balance sheet before I wrap up with closing remarks. We'll then open up the call for Q&A. Starting on Slide 3. While we're seeing heightened volatility in our sector and across global markets more broadly, our priorities remain unchanged. I talked in detail in February about prioritizing cash generation, and that continues to be our primary focus. And we deliver that through a combination of increasing production and lowering costs. Starting with production. We were pleased to announce the export of the first cargo from the GTA project last month. All four trains on the FLNG vessel are now operational with daily production ramping up towards the contracted sales volume equivalent to 2.45 million tonnes of LNG per annum, with potential to go higher. I'll talk more about that on the following slide. In Ghana, we expect the drilling rig to arrive later this month with 2 Jubilee wells planned in 2025, which should help deliver production growth in the second half of the year. The partnership also plans to drill an additional four Jubilee wells in 2026 which should further enhance production with low-cost, high-margin barrels even in a lower oil price environment. In the Gulf of America, we're currently drilling the fourth Winterfell well, which is expected online in the third quarter. On costs, and I talked in February about a material reduction in costs across both capital expenditures and overhead with the ability to exercise greater control over our CapEx going forward. We expect CapEx to fall by over 50% year-on-year with evidence of this in 1Q with CapEx of $86 million, $200 million lower than the same quarter last year. We are also committed to reduce our annual overhead by $25 million by year-end and have already made significant progress against that target through April. And finally, as we navigate a volatile market backdrop, the important actions taken last year to enhance the financial resilience of the company have put us in good shape for the year ahead. In 2024, we raised new capital, refinanced and upsized our reserve-based lending facility, which pushed out our average maturity length. We continue to protect our balance sheet with a rolling hedging program and have minimal near-term maturities and ample liquidity. Our portfolio is also made up of assets, particularly on the oil side with low operating costs and low breakevens. Neal will go into more detail on the actions we're taking later in the presentation, but the activities we have completed leaves us the flexibility to maintain the resilience of our balance sheet through the current volatility. So in summary, we're focused on keeping the business in good shape through a period of market uncertainty with growing production, material cost reduction, and an unchanged priority on cash delivery to pay down debt. Turning to Slide 4. We achieved several key milestones in Mauritania and Senegal in recent months with first gas and LNG production in the GTA project, followed by the first LNG cargo. With the export of this first cargo, Mauritania and Senegal have become the latest LNG exporting nations, and Kosmos is proud to become an LNG producer. On the FLNG vessel, all four liquefaction trains are now operational with production ramping up towards a contracted daily rate equivalent of 2.45 million tonnes per annum. The second cargo lifting is underway and our full year gross cargo guidance of 20 to 25 cargo remains unchanged. We also expect the first condensate cargo to be exported in the second half of the year. On costs, we're targeting material reductions in both operating costs and our FPSO lease costs. We expect routine operating costs to reduce in the near term as the commissioning work naturally comes to an end. In addition, we're working with BP on the FPSO refinancing, which should further reduce OpEx, targeting completion in the second half of the year. Over the medium to longer term, the operator is investigating alternative operating models that could materially reduce costs and enhance the overall returns of the project. We look forward to working with them on this initiative. We see future upside potential at GTA with increased production through the existing facilities and a potentially material step-up in production through some low-cost modifications to those facilities. The FOG vessel has a nameplate capacity of 2.7 million tonnes per annum, and the liquefaction trains are being tested at around 10% above this equivalent nameplate capacity. Next, we'll test the common systems at the maximum rate to get a better picture of where we can safely operate the facility above the contracted sales volume. We're also working with the operator in the Gulf of America to explore potential upgrades to the FLNG vessel, which could help increase LNG production capacity to beyond 3 million tonnes per annum. Initial work suggests this can be achieved with relatively modest upgrades. This would likely be done as part of Phase 1 plus where work has begun with the project partners to fully leverage the existing infrastructure. Phase 1 plus is a low-cost brownfield expansion to potentially double future gas sales with minor modifications to the FPSO in addition to the upgrades to the FLNG vessel and the provision of additional domestic gas. The performance of the GTA reservoir based on data from the initial production has been positive, which creates the potential to reduce future well counts and CapEx. We'll continue to update the market as we make further progress. Turning to Slide 5, which looks at operations in Ghana. It's been a busy start to the year in Ghana, where we've completed two major pieces of work. Firstly, the partnership shot a new 4D seismic survey, the first over the field in around eight years, and that data is now being processed using state-of-the-art algorithms. We believe the enhanced 4D image will greatly improve our reservoir models and when combined with AI-supported production optimization will enable the partnership to high-grade the future infill drilling campaigns and optimize reservoir management strategies to drive higher field recovery over the life of the asset. The second major piece of work was the scheduled Jubilee FPSO shutdown, which was completed safely and on budget in early April. The work scope should help to sustain high levels of reliability and higher production as we drill new wells in the future. This year, the operator has been delivering good facilities uptime and consistent water injection into the fields necessary to mitigate the natural decline rate. On drilling, the rig is expected to arrive this month with 2 Jubilee wells planned in 2025. The partnership then plans to drill four Jubilee wells in 2026 with an option for additional wells if the external environment supports. Jubilee infill wells provide the highest returns across our portfolio, with full payback typically in months due to the low operating and development costs and high cash margins of the barrels, even in a lower oil price environment. And finally, last month, I had a very productive meeting with President Mahama in Accra to discuss his vision for the future of Ghana's energy sector. We share a very aligned agenda around the importance of investment in the oil and gas sector to support the long-term economic and social development of the country. We look forward to continuing to work with the President and his government to invest in and advance Ghana's energy sector under his leadership. Turning to Slide 6. In the Gulf of America, production for the first quarter was in line with expectations and included a planned 30-day shutdown of the facility that hosts the Kodiak field, which has been completed. Our Gulf of America production has ramped back up to around 20,000 barrels of oil equivalent a day net. On Winterfell, the workover of the number three well was unsuccessful, and we are currently working with partners to evaluate a future sidetrack to access those reserves. The rig is currently drilling the Winterfell 4 well, and that is expected online in the third quarter. On Tiberius, where Kosmos is operated, we're making good progress on an improved lower-cost development plan, which will be supported by new ocean bottom node seismic being acquired this year. We're working closely with Oxy, who are 50-50 partners on the project and also own the nearby Lucious facility, which we expect would host production from the field. Post acquisition of the new seismic, the farm-out process will continue with the aim of bringing in a partner ahead of project sanction. In Equatorial Guinea, production for the quarter was steady at around 9,000 barrels of oil per day net. Post the recent infill drilling campaign, activity is relatively light this year as the partnership focuses on well work to support current production levels. In addition, we're working with the operator to reprocess the seismic we have with modern technology to high-grade the future infill drilling potential. There's a lot of opportunity in Equatorial Guinea. So the key is making sure we have the best understanding of the subsurface before our next drilling program. Neal will now take you through the financials.

Thanks, Andy. Turning now to Slide 7, which looks at the quarter in detail. Production for the first quarter was impacted by a number of one-offs. We had heavy scheduled maintenance as communicated in February, primarily driven by the Jubilee and Kodiak shutdowns, which led to a large underlift in 1Q. Entitlement production did come in slightly lower than guidance, primarily due to the timing of the GTA ramp-up. As Andy talked about earlier, the GTA ramp-up has progressed in April and our full year GTA cargo guidance is unchanged. 2Q production guidance reflects this GTA ramp-up with production in the second quarter expected to be around 15% higher than the first quarter at the midpoint of our guidance. OpEx per barrel of oil equivalent was in line with guidance, but higher year-on-year, reflecting the lower production and higher maintenance in 1Q 2025, including a construction support vessel at Jubilee prior to and during the scheduled shutdown and the Winterfell-3 workover. The biggest change was CapEx, which is materially lower year-on-year, in line with our commitment to deliver capital for the year of $400 million or lower. G&A, exploration, and interest expense were also all down year-on-year. Tax was lower year-on-year, primarily reflecting lower commodity prices. As you'll see in the appendix, we have included our updated guidance. Full-year guidance has not changed. However, I want to point out a couple of items related to 2Q. The increase in 2Q OpEx is a function of our 110 cargo being lifted this quarter. Higher CapEx in 2Q is a function of some activity moving to 2Q from 1Q and commencing the drilling activity in Ghana and the Gulf of America. Turning to Slide 8. As Andy touched on earlier, 2024 was an important year of financing activity to position us well for the future. Last year, we refinanced and upsized the reserve-based lending facility, and we have recently concluded the spring redetermination with our banks. That process went well with the borrowing base well in excess of the current facility size, with the banks using a long-term price deck below the current strip. Importantly, this borrowing base excludes any value for our GTA and Gulf of America assets, which could be used to access financing in the future. We continue to actively manage all the levers we have to maximize cash generation to repay debt, including our 2026 maturity. As part of that effort, post quarter end, we continued our rolling hedging program, adding a further 2 million barrels. We now have around 40% of remaining 2025 oil production hedged, with a floor of approximately $65 per barrel and a ceiling of approximately $80 per barrel. In addition, as I mentioned on the previous slide, first quarter CapEx this year was materially lower year-on-year as can be seen on the chart on the bottom right, and we are working to reduce full year CapEx further from the $400 million we communicated at our full year results. Going into next year, we have minimal capital committed, which provides us a lot of flexibility to further manage our activity set. While the environment is volatile, we continue to be active in managing our options to maintain our financial resilience.

With that, I'll hand it back to Neal. Thanks, Neal. Turning now to Slide 9 to conclude today's presentation. Our focus on cash generation and cost discipline remains unchanged, is even more important given the current market volatility. Production is rising as we ramp up GTA, and the near-term drilling in Ghana and the Gulf of America is expected to lead to further production gains in the second half of the year. We're prioritizing cash generation through the rigorous cost and capital discipline we've outlined in today's materials. We have assets with low breakevens to generate cash in a low commodity price environment. And the long-term value proposition of the company is underpinned by a 2P reserves to production life of over 20 years. Thank you. I'd now like to turn the call over to the operator to open the session for questions.

Thank you. Our first questions come from the line of David Round with Stifel. Please proceed with your questions.

Great, thanks. Thanks guys. A couple from me, please. Firstly, just on the nameplate capacity test at GTA, can you talk about the time frame there for actually understanding the potential rates? And what do you actually need to see to have confidence that the higher rates might be sustainable there? Second one, just in your presentation, you talked about breakevens a few times. So interested if you can talk about where you see your breakevens today, and potentially how those might evolve in future years?

Yes. David, yes, thanks for those two questions. In terms of the nameplate capacity, as I said in the remarks, the nameplate capacity of the FLNG vessel is 2.7 million tonnes per annum. The process of getting to that level and beyond is testing each of the trains individually, and we're going through that process now. And we've tested several, and they are sort of coming in at around 10% higher, which is typical. Work is ongoing then to test the overall system, and that will give us the rate that we can deliver reliably and safely above that 2.7. So that's the first step. And I think that work is sort of going to go on through the second quarter, yes. And then beyond that, once we know we're at that level, the objective for them will be to deliver reliably at that. And therefore, you have the option of additional volumes above the ACQ of 2.45. So that's the process. And there's sort of nothing unusual here. I think if you look at LNG facilities around the world, they typically operate at around 10% higher than nameplate. And that's what we're seeing on the FLNG vessel at GTA. Moving to your second question on the breakevens. I think, look, at oil prices around current levels for the remainder of the year as a whole. We expect to be free cash flow positive, and we'd obviously use that free cash flow to pay down debt. Then as you look beyond where we are today, we've got a ramp-up in volume in the second half of the year and into 2026, as we expect production to rise, with the ramp-up with GTA that I've just talked about, and then with Jubilee drilling, which should commence shortly. And again, as we've talked about today, we've been clear about our focus on cost control, which is bringing down CapEx and reducing the overhead. And I think as we showed with the first quarter CapEx, we're making good progress on that. So we haven't given CapEx guidance for '26, but in a low price environment, Neal talked about the minimal committed CapEx we have for '26, which is really just the four-well Jubilee program. So if you have that plus maintenance CapEx across the rest of the portfolio, we get to a target breakeven of around $50 per barrel Brent. And in that scenario, you still see production growth year-on-year, '25 to '26, but we would be deferring future growth projects in that lower price environment. And the thing I'd add is in that scenario, I think probably around 85% of the lion's share of capital is going into the Jubilee infill wells. Which again, as we said in the remarks, are our highest return projects, and they've got a very low breakeven, probably on a project basis around $30 a barrel. So even in a low price world, those are things that are going to be adding value for the company. So I think, I just want to make sure I've sort of communicated two things, your sense of where that breakeven would be going forward, where the capital would be allocated, and our ability to manage in that lower price world.

That's very clear; thanks, Andy.

Great. Thanks, David.

Thank you. Our next questions come from the line of Lydia Gould with Goldman Sachs. Please proceed with your questions.

Good morning. Thanks for taking my question. My question is around credit and the balance sheet. How are you thinking about financial leverage in a lower commodity price environment, and liquidity in those circumstances? Would love your perspective on how you're thinking about the 1.5 times leverage target as well?

Yes, thanks, Lydia. I'll pass the question across to Neal.

Yes. Hi Lydia. So I'd say again, I think our focus on reducing financial leverage and maintaining sufficient liquidity for the business hasn't changed. So again, the direction of travel for us is to continue to generate free cash, which as Andy just commented, we can generate an oil price around this price level and use that to pay down debt. As a result of that, leverage will come down over time. And so, the pace really changes based on the oil price. But again, that's something outside of our control. But we've taken the steps to both increase production, lower the capital expenses, and operating expenses that allow that and are conducive to that environment. I'd say in addition to that, we talked a bit about hedging on the call. That's another tool that we're actively using to protect and insulate the cash flow from the business. If I hit your second part of the question around liquidity, yes, again, I'd still say we've got questions around the debt maturities in '26 and '27. We did a lot of work last year to manage those maturities down. We'd still anticipate paying the bulk of the outstanding '26 notes with cash flow generated from the business. And then if oil prices move lower, or stay lower for an extended period of time, we have clearly other options in terms of leaning into existing liquidity as well as accessing financing on some of our unencumbered assets. So the Gulf of America assets and our assets in Mauritania and Senegal clearly don't have any debt. And that's a - they provide us some flexibility if we want to go raise cost-effective secured financing against those assets. And so, we have a lot of levers that we can manage if the environment gets worse.

Thanks, team.

Great. Thanks, Lydia.

Thank you. Our next questions come from the line of Bob Brackett with Bernstein Research. Please proceed with your questions.

Good morning. This might be a stretch, but if I talk about Tiberius, and I see you're looking at a lower cost development plan with new OBN seismic data, and if I compare that to some of the Department of Interior studies around commingled production, or higher drawdown production, how do you think about the evolving policy in the Gulf of Mexico, and is that driving anything that you're doing there?

Yes. No. Interesting question, Bob. Yes, I'd say there's nothing specific today that is changing our plans. It remains, I think, a basin where we see the ability to conduct business. It's a basin where we can leverage technology. I think over half of the seismic in the Gulf of Mexico now is OBN, and that provides us with, we think, a much-enhanced image, and therefore the ability, to derisk and optimize the development. So a piece of the optimization is the leverage of that OBN, and then a piece of it is actually work that we're doing with Oxy, our co-partner there, 50-50. But it's tied back to Lucius. That's our objective and the ability then to figure out how you fully optimize the existing infrastructure on Lucius. So I don't think for Tiberius in the Pacific, there's been something that the Interior, Department of Interior has done, which is making a big change for us. This is work that we have going for some time now, and for me, it's more about the ability to leverage the technology, the pace at which that's evolving. And then, I would say just good, honest engineering to take out costs. I think those are the things.

Very clear. Thanks.

Thanks, Bob.

Thank you. Our next questions come from the line of Matt Smith with Bank of America. Please proceed with your questions.

Hi there, Andy. Hi, Neal. I guess my questions were really around. In the current price environment, the current oil prices, would you be comfortable deploying that growth CapEx on the Tortue expansions that you referenced earlier? Specifically, I think the Phase 1+. So would you be willing to deploy that growth CapEx at the current oil price, was really the first question. And the second question related, was are you considering in any greater way sort of monetizing part of your stakes in Senegal or Mauritania at the moment? Must that be Tortue itself or the peripheral discoveries as well?

Yes, good questions, Matt. Look, it's a tough one to answer because it also depends on what the price is, right? I think we've been very clear on the call today about our ability to manage a lower price environment. It is about the committed CapEx, and that scenario I talked about when David asked the original question. I think going forward, we would say that the growth CapEx on Phase 1+, is not committed to today. Therefore, we have the option around the pace, and I think that's the important thing around the resource there is that, it's not an option we're going to lose. It's about the pace of the development, and it's therefore about ensuring that we're doing it in a way, which doesn't interfere with the overall financial resilience of the company. So I feel good about the fact that we have greater clarity now, I think, on what that option is. I think we have greater alignment with ourselves, BP and the national oil companies. I think really strong alignment now, and the work that we're doing now is at the front end. So it's very low CapEx allowing us over the next 12 to 18 months to understand the engineering and make sure that we've got the right basis on which to proceed. So it's a really low-cost spend initially. And clearly, you'll monitor that progress and therefore decide when you would move into a higher CapEx spend. Look, and then in terms of monetization, there's value being added to GTA as we speak we're ramping up, we're demonstrating the field is working, we've got optionality, I think, of moving beyond the ACQ. I think there's work to be done, Matt, to make sure that we fully describe the full potential of GTA before we start to think about any dilution. So nothing sacred, everything ultimately in the portfolio has a value. What we need to do, is make sure that we're in the point of the cycle, where we properly describe the value. I feel good about the subsurface. We talked about that in the remarks. I think that the initial production data, we're getting now is very positive. So that's a good sign. I think we need to demonstrate that the facility has greater potential than what is currently described in terms of the offtake, and therefore build that into future models. So I think we're a little ways away from that, but it's something that we're working towards getting ourselves to the place where we've fully described the potential of GTA.

Okay. Great. Thank you, Andy. Happy to pass on.

Thank you.

Thank you. Our next question has come from the line of Stella Cridge with Barclays. Please proceed with your questions.

Hi there. Afternoon everyone. Many thanks for all the updates. And there were a couple of areas I wanted to ask on, the first you talked about a recent meeting in Ghana and engaging positively there. I noted recently a fellow on their call talked about potential multiple future rounds of investment in Ghana. I just wondered what was your takeaways from those discussions? Are there any kind of key action points in the near term regarding the partnership there over the longer term? That was the first one. And just the second one was that I noted that there was a cash outflow from notes receivable in Q1. I just wondered, will there be any more outflows from receivables? Or could potentially there be any inflows from Senegal or Mauritania in the future? That would be great.

Yes, look - thanks Stella. I'll ask Neal to pick up the question around the cash outflow. Ghana, we've been there for a long time. We've seen obviously multiple governments. And for me, it was great to meet President Mahama again. He was clearly there in power eight years ago, and it was an opportunity to connect with him, sort of his view and vision of the industry in Ghana. My big takeaway is that he has a very clear mandate, I think, to reenergize the sector. There is, I think, a lot of potential remaining in the basin. But it's a potential that is actually around sort of near-term activity where you're getting the most out of your existing fields that are on production. And I think the big point to take away from it is that I think I've talked on previous calls about the potential that we see in Jubilee. The remaining reserves to be produced. An important element of that is you have an aligned agenda with the government, and obviously, with the national oil company. That's what I took away from it that we have the same aligned agenda. It's a place where Kosmos is welcome. And we're embarking on a program now with obviously two wells in '25. But then four wells in '26, to ramp up Jubilee production, and then the potential to work and continue to work on enhanced recovery from the field. So I think the big message is around the fact that we have a country where we're welcome. We have a long history there, and we have a very much aligned agenda as we look to maximize both the efficiency and the effectiveness of the recovery, which will benefit both the country and Kosmos's shareholders. So I think that's a big message from that. And as I say, we're starting on that journey now with the infill program that will have the drilling rig arriving this quarter. Maybe if I just pass the call across to Neal, just to cover your question about the cash flow.

Yes, I think the question you asked is just around the NOC financing that was in 1Q. And so, that's part of the development loan that we put in place with GTA that comes to a close basically this quarter. And so in terms of our obligation to finance their development expense. And then as you noted, there will be a repayment schedule in terms of then starting to get that cash flow back. So again, in the second half of the year, it would stop being an outflow. And then as we deliver the increase in production and reductions in operating expenses, then there's capacity for that cash flow to start being repaid back to both us and BP as part of that repayment of the NOC loans. And so, we're sort of near the peak of that in terms of capital expended.

That's it from me, thanks for the answers.

Great, thanks, Stella.

Thank you. Our next questions come from the line of Nikhil Bhat with JPMorgan. Please proceed with your questions.

Good morning. I just have one quick one. More of a clarification on your LNG offtake agreement with BP. Could you please remind me if there's any annual quota of volumes of cargoes that you're contracted to sell to BP? And also if there's - could you remind me of the contracted price again, please? Thanks.

Yes. The annual contract quantity is 2.45 million tonnes per annum. And the price is 0.95 or 9.5% slope against Brent FOB.

Thank you.

Does that make sense, Nikhil? I know that's sort of short machine gun stuff, but that is precisely the answer.

Thank you.

Our next question comes from the line of Mark Wilson with Jefferies. Please proceed with your questions.

Thank you and good afternoon, everyone. First off, on Tortue, just if you could give a bit more color on what is it you've seen with the subsurface performance that you mentioned is ahead of expectations, which sounds good. And then second point, I wonder what are the steps to domestic obligation offtake physically with pipeline? And also financially, does that connect to what Neal was just talking about NOC payback? Do you need that domestic obligation in place?

Yes, Mark, yes. So looking on the subsurface, you still go back in time. Obviously, you understand this, but seismic, you then - we had three exploration wells, one appraisal well, then we've got four development wells. The four development wells, we did flow back for a short period of time. It's tough on those shorter flowbacks to sort of see where you are getting any connected volumes. Yes. And I think the big new piece of data we've got is from the flowback from the first two wells, actually, we're seeing a greater connection in volume than we had originally mapped. So I think that's a very positive, obviously, because as you start to think about the future, therefore, you have the opportunity to reduce the number of wells you need for a given amount of recovered volume, which again would enhance the returns from the project. In terms of the second question, Mark, just remind me. Domestic gas and the build-out of the infrastructure, yes. Okay. Yes. So we don't - in essence - yes, the obligation, just so we're clear on the obligation. The obligation is with the offtaker, which is the national oil company to build any infrastructure. So they're responsible for building the pipeline from the hub terminal to - which is the offtake point to their - whatever their chosen landing point is. So we don't have any capital liability for that. I think that was really the essence of your question, wasn't it?

Yes, it is. And obviously, until they do that, you - I guess, can sell at nameplate capacity?

You have more gas to sell. Yes, exactly. You've got more gas to sell, yes. So - and I don't think there's - if you think about the limit to the system, the FPSO, all right, and then its associated infrastructure you can do well more than 3 million tonnes per annum, yes. So it's the - in terms of delivering LNG, the constraint is the capacity of the facility itself. And then if it's at its full capacity, and that number is beyond the 2.7 million tonnes per annum, there's still gas available for domestic. So we're not - it's not about sort of one being exchanged for the other. There's plenty of capacity in the system.

Absolutely. It makes sense. Thank you. I'll hand that over.

All right, good. Thanks, Mark.

Thank you. 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 now disconnect your lines, and thank you for your participation.