Good day, everyone. Welcome to Kosmos Energy's First Quarter 2021 Conference Call. At this time all participants are in a listen-only mode. A question and answer session will follow the formal presentation. Just 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, Darryl, and thanks to everyone for joining us today. This morning, we issued our first quarter 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. Today, almost to the day, marks the 10-year anniversary of Kosmos' IPO on the New York Stock Exchange. The official birthday is tomorrow. So I want to start the call with a look back at how far the company has come over these 10 years and also look forward to where we expect the company to head over the next decade. I'll then talk about the operational highlights for the quarter, review our upcoming appraisal and infrastructure-led exploration activity before handing over to Neal to discuss the 1Q financials and the balance sheet. Starting on Slide 2. In 2011, at the time of the NYSE listing, Kosmos was a successful frontier explorer. The company's operations were centered on Ghana with production from a single FPSO with Jubilee. Oil prices averaged $111 per barrel that year, and consensus was that there wasn't enough supply to meet growing future oil demand. Full year production in 2011 was just 16,000 barrels of oil per day and Kosmos had net 2P reserves around 70 million barrels, almost all of which was oil. Over the last 10 years, Kosmos has successfully transformed from a frontier oil explorer to a full-cycle E&P. We brought online 10 fields in Ghana, discovered multiple giant gas fields in Mauritania and Senegal and have since taken FID on Phase 1 of the Tortue LNG project. We have diversified our production and added ILX opportunities with value-accretive acquisitions in Equatorial Guinea and the U.S. Gulf of Mexico. Last year, we monetized our longer-dated frontier exploration assets. Over that time, production also nearly quadrupled, and our reserve base increased around sevenfold to where we are today. While we've grown the business and adapted our strategy to meet the rapidly evolving world around us, one characteristic that hasn't changed is our commitment to corporate responsibility and our dedication to supporting the economic and social development of our host countries. Around the time of our listing, Kosmos set out to improve transparency across the oil and gas industry by publishing all of our petroleum contracts online. To this day, we believe we are still the only U.S. oil and gas company to do this. To enhance the societies in which we work, we set up the award-winning Kosmos Innovation Center in Ghana, which later expanded into several other countries in West Africa. The Kosmos Innovation Center invests in promising young entrepreneurs and small businesses to bring lasting benefits to the host countries and contributes to the creation of healthier and more diverse economies. In recent years, we have increased our commitment to the environment, integrating the impact of climate change into our strategic business decisions, shaping our portfolio to be fit and relevant for the future and setting a goal of carbon neutrality in our Scope 1 and Scope 2 emissions by 2030 or sooner. As we look at the company today, Kosmos is an oil-focused full-cycle exploration and production company with production from three separate hubs, a world-scale LNG development, and a deep hopper proven base in ILX opportunities. We've created a strong platform, which we believe will allow us to successfully navigate the next 10 years with defined high-quality projects in our current portfolio to further grow and diversify production. Over the next several years, we believe we have line of sight to grow organic production to around 100,000 barrels of oil equivalent with potential options to supplement that further with compelling value-enhancing inorganic opportunities. In 2023, we expect first gas from Tortue Phase 1 with the second phase planned to come online in the middle of this decade. This significant ramp-up in company production is expected to make Mauritania and Senegal a major production hub for Kosmos with the gas weighting of our portfolio increasing considerably. All credible scenarios by leading analysts from economists to financial advisers to scientists have modeled a pathway to 2050 with a significant proportion of natural gas in the energy supply mix. It's our view that the world cannot achieve the Paris goals and lift millions of people out of poverty in a developing world through a just transition without natural gas playing a major role. With our growth in natural gas and a firm commitment to emissions reduction, Kosmos is playing its part towards the Paris goals. We're already making good progress towards those goals with our measure, reduce, mitigate approach to emissions and our investment in high-quality nature-based carbon capture projects in Ghana and the U.S. This consistent agenda to tackle climate as part of our broader commitment to advancing our ESG responsibilities has been a major part of Kosmos' business over the last 10 years. With a portfolio of advantaged assets, we expect to remain well positioned to further drive that agenda over the next 10 years. Turning to Slide 3. I spoke of our 4Q results in February about the operational momentum that we expect to see return in 2021. We've made a strong start to the year, and this slide shows the progress we've made across the portfolio in the first quarter. On production, we plan to drill 9 infill wells in 2021, three times as many as we drilled in 2020. This activity started in line with our 2021 work plan with full wells already drilled in Ghana and the Gulf of Mexico, and our second well in Ghana currently drilling. In Equatorial Guinea, our production enhancement activities for this year have started successfully. We expect to shortly begin our initial infill drilling campaign at three development wells with the rig scheduled to arrive at the end of this quarter. On development, Phase 1 of the Tortue LNG project is continuing to advance, with 58% complete at the end of the first quarter. On the FPSO sale and leaseback, the documentation is being finalized and the government approval process is well underway with the transaction expected to close this quarter as previously guided. On exploration, we started the year with success at Winterfell in the Gulf of Mexico, and partners have fast-tracked an appraisal program with an appraisal well expected in the third quarter. We're also planning to drill the Zora ILX well in 3Q, more on this shortly. On financing, in late February, we successfully completed a high-yield bond offering. This morning, we announced the completion of our RBL extension in conjunction with our spring redetermination. These transactions have collectively strengthened the balance sheet, increased liquidity and pushed out all near-term debt maturities. Having started the year strongly, we remain on track for the full year to deliver between $100 million and $200 million of free cash flow from the base business at $55 per barrel Brent. Slide 4 looks at the ramp-up in activity across our three production hubs in more detail. In Ghana, we continue to work closely with the operator to enhance facility performance and drive higher reliability, and we're making good progress. FPSO uptime in 1Q was 98% at Jubilee and 99% at TEN, carrying on the momentum for the second half of 2020. Water injection at Jubilee, which is helping provide reservoir support, is now at levels not seen since 2012. Gas offtake of approximately 110 million standard cubic feet per day from Jubilee and TEN is around double the 2019 level, and there is scope for this to increase further. Greater gas offtake means less gas being injected into the reservoir. Combined with improved water injection, this is expected to have a positive impact on the GOR of Jubilee, which should mitigate decline from existing wells. The CALM buoy at Jubilee was commissioned in the first quarter, removing the need for shuttle tankers, which reduces OpEx and streamlines our operations. As I mentioned in my opening remarks, we're back to drilling in Ghana and have just finished drilling a producer well at Jubilee. This is the first well drilled on Jubilee since 2019. It came in as planned and is the first of four wells planned in Ghana this year. The rig has now moved to drill a water injection well at Jubilee, after which it's expected to complete both wells, increasing Jubilee production by an estimated 15,000 to 20,000 barrels of oil per day gross, which should continue to drive our production higher. In 3Q, our initial two wells, the partnership planned to drill and complete a TEN gas injector well before drilling and completing a third Jubilee well in 4Q, which is expected online around year-end. In Equatorial Guinea, we've been active in 1Q with the Okume upgrade project nearing completion, adding additional power, water injection and gas lift capacity, necessary for further facilities debottlenecking and additional ESPs. In April, we completed the first of three ESPs for 2020 and upgraded the G-19 flowline, which has significantly enhanced production from that well. We've contracted a rig for our upcoming drilling campaign, and it's expected to arrive in-country later this quarter. The three planned wells this year will be the first infill wells drilled in Equatorial Guinea since 2015. In the U.S. Gulf of Mexico, Kodiak-2 was brought back online late in 1Q after a successful remediation of the subsea infrastructure issue identified in the fourth quarter of 2020. The Kodiak-3 well came online last month, and we plan to drill the Tornado-5 infill well this quarter with production expected in 3Q. Kosmos delivered approximately 53,000 barrels of oil equivalent per day for the first quarter, in line with guidance, and our production activities remain on track to the year-end exit rate of 60,000 barrels of oil equivalent per day. Turning to Slide 5. The momentum we've seen in 1Q across our production activities is meshed in our development project. Tortue Phase 1 ended the first quarter around 58% complete with strong progress across all of the major work streams, which can be seen on the images on the slide. The top image is the FPSO where the hull was launched last month. The bottom image shows the progress being made on the breakwater, five caissons are complete with work ongoing on the next two. In April, the first caisson on offloading took place. The full caisson construction process through to offloading has all gone to plan, and the offloaded caisson is now in wet storage ahead of transit to the final breakwater location later this year. This is an exciting time for the project as the infrastructure starts to move offshore. Overall, we're making progress in Phase 1 as it is expected to be around 80% complete at year-end. On the FPSO sale and leaseback, documentation is being finalized and the government approval process is well underway. Late last month, the energy ministers from both countries held a joint meeting on the project where they endorsed the FPSO financing, continuing the strong and consistent support by both countries for the project. As a result, we feel good about where we are, and as previously communicated, we remain on track for a 2Q completion. Turning to Slide 6. We talked in February about the ILX success we had with Winterfell in the Gulf of Mexico at the beginning of the year. Winterfell is a Miocene subsalt discovery found in track time covenant in the Gulf of Mexico. The exploration well tested two reservoir sections in a single fault block. The seismic response is now being calibrated with the well data. The Winterfell discovery derisks more than 100 million barrels of gross resource potential across Kosmos' acreage position across multiple fault blocks and reservoir sections. Over the last quarter, the partnership has been working on a fast-track appraisal plan expected to begin in 3Q with an appraisal well. This well is designed to test the fault block to the northwest of the discovery, which is the same seismic signature as Winterfell. The well is also expected to test a deeper horizon with an exploration tail, which can be seen on the seismic cross-section on the bottom image of this slide. We believe that with a successful appraisal well, we have discovered more than a sufficient resource potential in the core development area to underpin a development decision. We anticipate the development will likely be phased with up to three potential drill centers. This discovery located in an infrastructure-rich part of the Gulf of Mexico provides the potential to develop a highly economic, low carbon project. Turning to Slide 7, which looks at Zora, our next potential ILX hub. Zora is planned to be the first exploration well in another mini basin. The initial prospect, Zora, is a supra-salt Miocene target in the same play as nearby analogous producing fields such as Odd Job, Horn Mountain, and Marmalard. Kosmos will operate the well with a planned working interest of 37.5%. We have received all of our permits, and the rig has been contracted with drilling planned in 3Q. As you can see from the map on the slide, the Zora prospect is near host facilities, which can facilitate a low-cost and lower carbon development in the event of success. The image also shows that Zora sits near several other prospects where Kosmos has built a material interest. We believe that our successful Zora well will lower the risk of these nearby opportunities, thus providing the potential to create a new production hub with around 200 million barrels of gross resource potential in total.

Thanks, Andy. Good morning and good afternoon to everyone. Slide 8 shows the financial results for the quarter, which were in line with our previous guidance. As previously anticipated, production was down year-on-year, largely due to the lack of drilling activity in response to the pandemic. Drilling activity is ramping up back quickly in 2021, and we expect to see these declines reverse as new wells come online in Ghana, Equatorial Guinea, and the Gulf of Mexico. The realized price in 1Q, which had been adjusted for derivatives and cash settlements, is slightly lower than at this time last year, reflecting the hedges we have put in place that capped some of the oil price upside within the quarter. Importantly, the lower per barrel realization also reflects the lower sales volumes in 1Q, a result of our lifting schedule in Ghana and Equatorial Guinea. We only lifted 1.5 out of 12.5 cargoes expected in 2021 in the first quarter. This, combined with our spend in Mauritania and Senegal and working capital movements, resulted in negative free cash flow in the quarter. As cargo timing evens out over the rest of the year and we lift more volume than entitled, we would expect the opposite effect, improving realizations as well as free cash flow. In addition, as we complete the FPSO and NOC financing for Mauritania and Senegal, we expect there will be a net cash inflow in Mauritania and Senegal for the balance of the year. We worked hard in 2020 to drive down costs to make Kosmos a leaner organization, and this can be seen across the OpEx, exploration expense, interest, and CapEx lines on this slide. Turning now to Slide 9. We have taken big steps this year to further strengthen the balance sheet and our liquidity position. In late February, we successfully completed a $450 million senior notes offering to reduce outstanding balances on the credit facilities and for working capital. This morning, we announced the extension of our RBL facility along with this predetermination. The facility maturity was pushed out two years with final maturity now in 2027. And we agreed on a borrowing base with the banks of $1.24 billion, with $1 billion currently drawn on the facility. We have reduced the facility size from $1.5 billion to $1.25 billion to reduce our liquidity reliance on the RBL facility as planned. The two charts on the slide show the debt maturity profile at year-end compared to the end of the first quarter, adjusted for the RBL extension and the second quarter RCF repayment. As you can see, we have taken important steps to address the maturity schedule early and clear all material near-term debt maturity. At the end of the first quarter, the company had approximately $0.8 billion of liquidity. With the maturity schedule largely addressed, we remain focused on reducing the absolute amount of debt and leverage through paydown of debt from free cash flow. We expect leverage to fall rapidly from 2Q and throughout the year as cargo timings normalize and hedges roll off. We are forecasting 4.5 cargoes in the second quarter from Ghana and Equatorial Guinea, which is three times higher than the 1.5 cargoes from the two production hubs in the first quarter.

Thanks, Neal. So to summarize, we've made a strong start to the year, executing our planned activity in the quarter on schedule with momentum building across the portfolio. Production is expected to increase through the year with nine infill wells across our three production hubs. Tortue Phase 1 remains on track to be around 80% complete by year-end with the FPSO sale and leaseback expected to close this quarter. We plan to drill the first Winterfell appraisal well and the Zora ILX well in the third quarter to deliver near-term production growth that is low-cost and lower carbon. Finally, on finance, having completed the bond and the RBL financing, we will now kick off the work stream to refinance the Mauritania and Senegal NOC loans and expect that to complete in the second half of the year. With all of that, we're firmly on track to hit our year-end exit production rate target of 60,000 barrels of oil equivalent per day and remain on track to generate $100 million to $200 million of free cash flow from the base business at $55 per barrel Brent. Thank you, and I'd now like to hand the call over to the operator to open the session for questions.

Our first questions come from James Hosie with Barclays. Please go ahead with your question.

Thanks, Andy and Neal, a couple of questions from me. Just first off, you've retained your 2021 base business free cash flow guidance at $100 million to $200 million at $55 Brent. Can you give us some indication of the sensitivity to prices currently being about $10 higher, if not more? And also, there is a $95 million working capital outflow in the quarter. Should we expect that to reverse for the remainder of the year? And then in Ghana, for the resumed drilling and Jubilee, it increased production later in the year. When do you expect the Ghana partnership to make a decision on a contract for a second drilling rig?

Thank you, James. I'll address the question about Ghana first and then hand it over to Neal for the discussion on price sensitivity and working capital. Currently, we are in the midst of our planning process with our partners in Ghana as part of our regular midyear review, which will lead to the approval of work programs and budgets for 2022. This decision is expected to take place in the third quarter. On a positive note, we see significant opportunities in both Jubilee and TEN. We have made a good start to the drilling program this year, with the first well drilled right on schedule. This strong beginning helps build momentum and supports discussions with partners about increasing drilling capacity next year. The two main points up for discussion will be the robustness of our portfolio and the quality of our performance, which has begun well. Neal?

Yes. James, regarding your first two questions, for free cash flow, a change of about $5 in oil prices translates to an additional $30 million or $35 million sensitivity for 2021, considering our current hedge position. Typically, you would expect that sensitivity to be larger, but we have retained some upsides to existing hedges. For your second question about working capital, there are a few key factors at play. One significant factor is the underlift within the quarter, where we're continuing to pay out jibs monthly, but we only recognize the volume once we've sold the oil. As the timing of oil cargoes balances out for the rest of the year, we will see that impact our working capital as that component reverses. There are also typical first-quarter outflows that will normalize over the year, along with an aspect related to Mauritania and Senegal. I expect that most, if not all, of these factors will reverse throughout the year.

Okay. Just a follow-up on Andy. On the second drilling rig, should we think of that as being a second rig dedicated to TEN with the other rigs in Jubilee? Or is that more kind of flexibility around it than that?

Yes. Look, there's more flexibility around it than that, James. Obviously, we want to make sure that we're efficient in terms of the way in which we deploy the assets. So I think that's a conversation that's still ongoing in the partnership. And then clearly, what we need to do is ensure that we're high-grading the drilling opportunities to drill the best wells first. So I think you will see a larger activity set on TEN. And so how we optimize that sort of rig timing and then the rig deployment is just part of that process of taking the deep inventory of opportunities and making sure we're doing the best wells first.

I wanted to ask first about the elevation of Tim Nicholson and Jon Shinol to lead your exploration program. Can you give us a sense of what, if anything, we're going to see different from Kosmos, whether in the kinds of things you're pursuing or the way in which you pursue them? And can you give us a sense of how much those two fellows have worked in the Equatorial Guinea assets of late?

Yes, Charles. I think that both Tim and Jon have got an incredibly strong track record of exploration in proven basins, sort of heritage, cobalt. And obviously, deepwater, Gulf of Mexico, an incredible track record there. So I think we have the right skills for the strategy, yes? We're clearly focusing on our proven basins in Equatorial Guinea, in the Gulf of Mexico, and also Ghana. So it's bringing those skill sets to bear across that, high grading those opportunities and opportunities that deliver a fast payback, high-return projects by leveraging the infrastructure. So I'm very pleased to have both of them in the company and very pleased for them to be taking a leadership position now with that proven basin strategy. And yes, actually, over the last more than two years, they've both been working on Equatorial Guinea, they've been working on the Gulf of Mexico and they've also been working on Ghana, right? So actually the work products that we're generating in Equatorial Guinea, they've been very much part of. If you go back in time, I think we acquired the assets in '17, shopped the seismic in '18. The processing was done in '19 and 2020 was all about the interpretation of it, the high grading of the opportunity set. So they've been absolutely involved in all of that.

Could you provide an update on the Tortue project, specifically regarding the remaining 20% of work to be completed by year-end 2021?

Yes. By year-end 2021, we will have the drilling campaign underway. The aim is to have the subsea infrastructure in place to start drilling the wells for the initial start-up. Our target is to have the caissons fully deployed by the end of the year. This will allow us in 2021 to build out the jetty structure behind the caissons, enabling us to bring in the FLNG vessel by year-end. Once the drilling of the wells is complete, we will then have the capability to position the FPSO at the site, which is planned for late 2021. Additionally, there will be the integration of the project through pre-commissioning and commissioning work on each component, leading up to first gas. These are the major tasks that will need to be executed in 2022.

I just wanted to build on the Tortue comment. You're at 60,000 barrels a day as a company right now, by 2026, I believe that you'd want to get to 100,000 barrels a day. Phase 1, we talked about, but Phase 2 is also really important. So what are the gating factors to get to FID on Phase 2? And how are you thinking about the incremental economics of Phase 2 relative to Phase 1?

Thank you, Neil. It's interesting because part of the focus is on optimizing Phase 2. As I've mentioned in earlier quarters, our collaboration with BP has allowed us to step back and determine the most efficient next steps. This involves fully utilizing the infrastructure we established for Phase 1, including using all of the gas processing facilities on the FPSO and maximizing pipeline capacity. With the breakwater built, our goal is to expand the FLNG capacity behind it. These are the key areas we've been addressing, and with BP, we are aligned on the approach for moving towards a 5 million tonne per annum facility, which effectively optimizes our resources. This strategy not only minimizes the capital investment required but also enhances financing options for Kosmos. I'm genuinely enthusiastic about our Phase 2 construct, as the economic benefits appear significantly stronger. Given the context of brownfield expansion worldwide, this plan stands out as one of the most economical projects. Strong economics stem from this leverage, and it's crucial to keep the engineering work progressing at the right pace. We're committed to reaching the appropriate completion level for Phase 1, and through the concept optimization this year, we are targeting a Final Investment Decision in 2022, likely around the end of that year, with first gas expected approximately three years later.

Yes. Just following up, you talked about carbon neutrality on the project Scope 1 and 2 emissions by 2030. Can you help us understand how you get there and give us some granularity upon achieving that goal?

Yes. So look, Neil, there were two big things that we're working on. One is the sort of measure and reduce the carbon from our own operations. And that is something that we're focused on. We start from a very strong position in the Gulf of Mexico because of the natural lower carbon intensity of those assets. Because you're using existing infrastructure, you don't have flaring there. You're tied into the gas networks. You have a carbon intensity of around sort of under 10 kilograms per barrel produce. You're starting with a strong set of assets, but there are opportunities to continue to mitigate and reduce. Then in terms of those emissions that we can't address that way, we're addressing through nature-based offsets. We're looking at a reforestation project in Ghana and sort of wetlands reforestation in the U.S. and then also potential wetlands projects in the Gulf of Mexico. Again, all of these will be about finding a way of a nature-based solution, which is high-quality, both in terms of the carbon offset but also in terms of it creates jobs, it's sustainable, and there's a larger economic impact to the economy. The wetlands projects have another benefit in terms of addressing the erosion of the coastline and how we can pursue projects that help to mitigate that. So it will be a combination of both of those.

At the risk of over-interpreting your Slide 2, where you talk about the next 10 years, that long-term number of around 100,000 BOE per day is consistent roughly with keeping production of your existing assets, oil assets, flat and getting to Phase 1 and Phase of Tortue. Is that the strategy, which then defines what to do with cash or barrels if you're above or below that? Or is that sort of a conservative baseline of what you'll achieve with potential to be bigger? Or am I over-interpreting?

No, good question, Bob. You've made an important point. It indicates that we currently have strong resource potential, which enables us to enhance our portfolio on the oil side by investing in the best projects that meet our criteria and generate free cash flow. We have a robust oil business that we can sustain. Ultimately, the level of investment will depend on our ability to generate free cash flow from that business. We're not short on resources or opportunities. The goal is to deleverage the company and generate free cash flow. In Tortue, we have a significant growth opportunity, with a sustainable source of cash flow for many years. As you know, LNG projects often involve high upfront costs. We are mostly past that with Phase 1. Phase 2 is designed to have low capital expenditures for first gas, leading to a reliable stream of steady cash flow from the business. This strategy is what creates that scenario and connects the resources to the project and the cash flow.

Okay. And so that plan achieves an increased gas percentage, but you'll still be predominantly oil. Are there thoughts of strategically selling down oil assets to rotate into gas assets? Or is that too far out to think about?

Yes, Bob, again, a great question. I think that ultimately, the gas component in the portfolio is significant because we'll look at upstream companies in terms of what they sell and the carbon intensity of what they sell, not just from the production aspect but in terms of their usage. So having a growing gas element to our portfolio is important, yes? Equally, we need to make sure that those are quality projects and compete for capital. We've got a strong internal growth wedge. And as you know on Tortue, there is growth beyond 5 million tonnes per annum. So the pace at which that continues to grow. I like the optionality we have, I like the balance we have. We have the ability to dial up or down as the world continues to evolve around us. The inherent strength of the portfolio from both dimensions, gas and oil, is important.

My first question is about the upcoming ILX program. Andy, regarding the Winterfell, you mentioned that if the appraisal of the north fault block is successful, it would reduce the risk of a commercial tieback development. I see there are several prospects shown, which I believe cover the 100 million. What level of 2C are you aiming to demonstrate with the discovery and the appraisal? Similarly, for Zora, with its potential of 200 million gross resources, how much of that does Zora account for annually? Additionally, am I correct in understanding that you're planning to slightly farm down before drilling at Zora?

Yes. So if you sort of look at Winterfell first, I think it's important that we're not to sort of get ahead of our skis. I think that we see significant additional potential in Winterfell. We had a successful first well on the fault block that we drilled. We've got a follow-up well to come. It's on the fault block to the Northwest. We derisked it with the well result from the first well, so same seismic signature. I think there we will get to a commercial threshold where a significant proportion of that 100 million-barrel-plus potential in that middle sector will have been proven up, which gets you to that commercial threshold. There is quite a lot of reserve intensity in the central part of the opportunity set. But there remains additional upside from drilling to the south and to the north. So I'm not going to give you a hard number, but the 100 million-barrel-plus, I think we'll get up to a number that's close to that from the central portion where we've circled on the view graph from those initial two fault blocks. Obviously, it will depend on the appraisal result and the exploration tail, but that's the opportunity set we're looking at. So that in itself is material. On Zora, again, we see Zora as around a 30 million to 40 million barrel type prospect. You've got four or five prospects there. That's what builds out the opportunity set that you see the 200 million barrel potential. To underpin an initial development, you probably need probably two of those to have come in, that would underpin the initial development. Again, I think you'd probably see a phased type approach where you drill, bring on the initial prospects, use the nearby infrastructure and then from there.

That's very clear. Then a point, I guess, for Mel, OpEx in the first quarter was actually below guidance, 13.9 BOEs, the guidance for the rest of the year stays. I was just wondering if any of the infill drilling costs in other areas actually go into that OpEx to make it retain the higher than Q1 for the rest of the year? That's one point. And then if I may, I'd just like to ask about Ghana production and the 15,000 to 20,000 that could be added from the first producer injector pair. Speaking to your exit rate of 60,000, are you also assuming a Ghana exit rate 15,000 higher than the two fields are producing at the moment at a gross level?

Sure. I'll address the ILX question, and then Andy can cover the production forecast. The first quarter operating expenses were significantly lower than expected due to the production mix. We had a higher proportion of production because of the underlift from the Gulf of Mexico, which has a lower operating expense per barrel. When we look at the guidance from quarter to quarter, as we adjust based on the locations from which cargoes are lifted at different operating expense levels, the overall figure isn’t materially different. It's encouraging to see some cost reductions, but in the larger context of our operating expense guidance, there hasn't been a significant change regarding the ILX. To answer your question, it does not affect the overall operating expense impact.

Yes, Mark, regarding the forecasting for Ghana, the first quarter was strong, with 70,000 barrels a day from Jubilee and approximately 39,000 from TEN, indicating solid performance. Looking ahead for the year from the existing wells, we have achieved good reliability, which should continue to support the base production. We have been successful in managing water injection and gas extraction, which also helps to mitigate the decline rate. Moving forward, we need to maintain our operational reliability and effectively manage water and gas to strengthen the year-end exit rate from the existing wells. Additionally, drilling has begun positively, and we need to complete the second producer or injector on Jubilee, which has the potential to contribute an extra 15,000 to 20,000 barrels a day in gross production. This would hopefully enhance our stable production base. While it's a bit early to provide updated guidance on Jubilee's exit rate, the trends we are observing, if maintained, appear to be encouraging.

Our next question has come from the line of Nick Stefano with Renaissance Capital. Please proceed with your question.

It's Nick from RenCap. Happy 10-year anniversary on the listing. I have a couple of questions to ask. The first one is for Neal. I found it extremely interesting that the RBL banks had the ESG KPIs for the margin. I'm curious about how this came about. Was it initiated by Kosmos, or were the banks changing their focus in the oil lending business to incorporate ESG goals? If you could elaborate on that, I would appreciate it. My second question is for Winterfell. I want to revisit Mark's question. From my understanding of the slide, for each appraisal or exploration well, you would drill in each of the fault blocks. If there's a discovery, you could complete it and attach a flow line to make it a producer. If that’s the case, you would be counting well locations. However, it seems you are trying to prove this up to build something larger. Can you discuss what additional infrastructure you might need beyond just curing the other flow line and completing the well?

Thank you, Nick, for the question. I'll address the first part and then pass it to Andy for the second. Regarding the first point, we've had productive discussions with the banks in recent months about extending our facility. We’ve gained access to the banking market at favorable levels due to two main factors: our strong cash generation capabilities from existing assets and the defined growth potential in our portfolio, particularly with Tortue. Additionally, our commitment to strong ESG practices has been a key focus for the company. We've been transparent about our agenda and our goals for the coming years. When it comes to incorporating this into the facility, we've noticed it included in other facilities outside our region. However, we believe it's crucial for our company, and we want our banks to align with this vision. During discussions, we advocated for including this aspect within the banks. Many banks view it as a significant positive. It wasn't so much imposed on us, but rather something we encouraged to ensure our vision aligns with their objectives. As a general trend, with increased investor focus on ESG, banks are prioritizing companies that have strong cash-producing assets and the right asset quality while also supporting a robust ESG agenda. We’ve positioned ourselves effectively, and this will differentiate Kosmos in terms of attracting support for our company.

Yes. Nick, on Winterfell, I think the task for the second appraisal well is ultimately to prove up a core area for the initial development phase. What we want to do is ensure that we're rightsizing the flow lines back to potential hubs. There are several that we could tie back to. We want to ensure that we've designed the initial piece of infrastructure optimally, yes? The question is, certainly, you'll have a drill manifold there. You drill the wells, you can come back and complete those wells. The optimum size of flow line is really the case. Then with that infrastructure in place, it's about creating some optionality around that infrastructure that's laid in to look at the second and third drill centers that will be tied back, and there's opportunity to tie back a certain volume if you're successful. If you get to a tipping point, you might potentially add a second flow line. This is all about ensuring that the capital goes in is properly sized at the initial way you don't overinvest in uninvested but create the optionality for the future. We see significant upside beyond the initial core development. We need to put in the right flow line size and create the optionality for it to be for the tiebacks from a potential second and third hub and then what incremental flow line capacity would you put in at that point.

Andy, just one question for me. One of the partners in Jubilee and TEN has been looking to monetize its position there. Does Kosmos have preferential rights option in those properties? And could Kosmos look to exercise its pref rights in Ghana dependent on pricing?

Good question, Richard. As with all agreements, I think you sort of pref rights are in the eye of the holder. I don't want to sort of get into a debate as it were on the line around how and if those could be exercised. It obviously depends on the structures, all sorts of things, yes? The answer to the question is that in one of the licensed blocks, I think that there is the opportunity for pref rights, but it depends on the structure that comes through. What's more important is really back to sort of our agenda, which is about we want to generate free cash flow from our existing assets. We want to ensure that we're deleveraging the company. If we were to look at an opportunity like that, it would have to fit into that construct, yes? The answer to the question is ultimately that we continue to screen opportunities that will be cash flow generating that would delever the company. If there are opportunities that turn up that look like that, we would certainly consider them.

This will be quick. On Slide 6, that Winterfell slide, the lower right, one thing that's curious here. I don't know if there's anything to this, but I just wanted to pull on this thread and see if there's more to the story, maybe. It looks to me that you've got the pliocene here underlying these miocene targets. I was wondering what's going on here? Is this a big inverted section? Or am I misunderstanding something? Is there any kind of bigger narrative there?

No, I don't think so, Charles. When we look at Winterfell, we see an opportunity that has significant upside to it, and we need to pursue through a proper appraisal program. I think we're happy with the initial well. It's proven up the seismic; we calibrated it to the wells, and we're off with the second appraisal well with a deeper tail on it. I wouldn't overread anything into it. This is a good start to a subsalt prospect where the tougher part of it is always getting the seismic calibration correct, and we've made a strong start to that with the initial discovery well.

I wanted to come back to discuss Winterfell since everyone is asking about it, Andy. From what I'm reading, there's 100 million in the central area that the appraisal can confirm, and there are another 100 million in the other fault blocks as well.

What we're saying is we've got over 100 million barrels of potential, Mark. Okay? Let's not get ahead of ourselves, yes? I think that's the most important thing. We believe that with the initial discovery well and the drilling of the second fault block, we've got enough resource to get to an initial development phase, yes? A significant proportion of the 100 million barrels, yes? What lies to the north, what lies to the south will depend on the drilling results. If we have success with the appraisal well and continue to calibrate the seismic, then obviously, we will gain confidence.

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. Thank you for your participation.