Good day, everyone. Welcome to Kosmos Energy Ltd.'s fourth quarter and full year 2024 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 Ltd. Please go ahead.

Thank you, operator. Thanks to everyone for joining us today. This morning, we issued our fourth quarter and full year 2024 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 UK and SEC filings. Please refer to our annual report, stock exchange announcement, and SEC filings for more details. These documents are available on our website. At this time, I will turn the call over to Andy.

Thanks, Jamie, and good morning and afternoon to everyone. Thank you for joining us today for our fourth quarter and full year results call. I'd like to begin today's call by talking about our cash generation. We'll then provide an update on the operational and financial progress we made in 2024, before discussing the outlook for 2025 and how we will focus on cash generation through maximizing revenue and rigorous cost management. Starting on slide three, Kosmos Energy Ltd. has a unique portfolio for a company of our size with a diverse set of world-scale oil and gas assets. The quality of the portfolio can be seen in the longevity of the asset base with a growing 2P reserve life of more than twenty years. Our oil assets are characterized by low operating costs and high cash margins, while our gas assets are positioned to deliver growth in revenue with increasing margins targeting long-term sustainable cash flow, particularly as gas and LNG continue to grow in the global energy mix. 2025 is an important year for Kosmos Energy Ltd. With increased production and reduced capital expected to drive an attractive free cash flow yield, which can be seen on the chart on the right-hand side of the slide, plotted against our U.S. and international peers, as well as the majors. Given the ongoing ramp-up of GTA and planned maintenance at other fields in the first quarter of the year, we have used an annual free cash flow from 2Q 2025 forward which we believe is sustainable in the medium term. In addition to our strong cash generation potential, the portfolio also has significant future optionality with material discovered oil and gas opportunities such as Tiberias and Yakataranga, alongside a quality hopper of infrastructure-led exploration prospects in the Gulf of America. Turning to slide four, in the second half of 2022, we set a target to grow production capacity by around fifty percent through several projects across the portfolio. The chart on this slide shows the foundation we've built to achieve that target which can be achieved with the ramp-up of GTA and Winterfell and new wells in Ghana. Importantly, as these projects start up, the CapEx associated with them is ending. In 2025, total CapEx is expected to fall significantly from over $800 million on average in 2023 and 2024 to $400 million this year, a reduction of over fifty percent. We'll be working on ways to potentially reduce it further where possible. We're not just refining the work scope, but the associated costs are also being managed rigorously. The resources needed to build and grow the portfolio are not the same as those needed to sustain it. Therefore, we're targeting a reduction in the annual overhead of around $25 million by the end of 2025, largely from a reduction in contractors and external consultants, and having the right workforce focused on the right things. This includes focusing our exploration effort in the Gulf of America given the depth of the discovered resource base we have across the rest of the portfolio. With growing production and a lower cost base, our focus is on free cash flow generation. In the near term, we intend to prioritize cash for debt pay down until we reach our leverage goal of below 1.5 times at mid-cycle oil prices. We will balance cash across further debt pay down and shareholder returns. Turning now to Slide five. Underpinning the company's cash generation potential is a strong and diverse reserve base with diversity across multiple geographies, spread broadly fifty-fifty across oil and gas. At the end of 2024, we saw a 2P reserve replacement ratio of 137%, replacing last year's production and adding more reserves during the year. The upward revisions were largely driven by gas as we continue to progress the GTA project. With the project starting to ship its first cargo and more drilling in Winterfell and Jubilee later this year, there is scope for further upward revisions in 2025. Year-end 2024 2P reserves of 513 million barrels of oil equivalent represent a reserves-to-production ratio of twenty-two years, a major differentiator for Kosmos Energy Ltd. versus our U.S. and international peers as can be seen in the chart on the bottom of the slide. Including the extensive 2C resource base beyond that, the number is closer to thirty years, highlighting the organic runway we have for many years to come. Over time, through enhanced seismic imaging, further infill drilling and project sanctions, we expect to migrate 2C resources into 2P reserves and 2P reserves into 1P reserves. The takeaway message from this important slide is while many companies across the sector face declining inventory and reserve lives, we have the reserves and resources to support sustainable cash generation for many years to come. Turning to slide six where I'd like to briefly touch on some of the highlights from 2024. We achieved a lot in 2024, ending the year with a better, more resilient company. Looking at some of the achievements: Safety is a key focus at Kosmos Energy Ltd., and we continue to operate safely during the year with zero lost time injuries or total recordable injuries. High safety performance with incident rates well below industry averages is a trend we have maintained for many years. As previously mentioned, our 2P reserves grew year on year to 530 million barrels of oil equivalent, a reserve replacement ratio of 137%, highlighting the longevity of the portfolio. We achieved first oil at Winterfell in the summer of 2024 and expect production to rise later this quarter as Winterfell three comes back online with a fourth well expected online early in the second half of the year. Late in the fourth quarter, the partnership achieved first gas production at the GTA project. First LNG production was achieved earlier this month and first cargo lifting is expected shortly. Through the year, we raised a total of $900 million in new bonds at competitive rates. We refinanced and increased the capacity of our RBL facility. These activities significantly enhanced our financial position and extended our weighted average maturities with minimal near-term maturities over the next two years. Neal will now provide some color on the last point and will take you through the results for the quarter and the year.

Thanks, Andy. Turning now to slide seven. Production for the fourth quarter was lower than guidance, partly due to lower Jubilee production previously flagged by the operator. Actions have been taken to resolve the water injection and reliability issues at Jubilee with voyage replacement over 100% so far year to date. We also saw a slight delay in the production ramp-up from the EG infill wells and Winterfell one and two were down most of the quarter prior to being brought back online late in the year. The 4Q production issues have been largely addressed but with several planned maintenance programs in the current quarter, production is expected to be broadly flat quarter on quarter. Detailed guidance is provided as an appendix to the slides. The 1Q planned maintenance program includes the shutdown of the Jubilee FPSO for a one-month turnaround of the topsides, which hosts the Kodiak field, and some other scheduled maintenance in Equatorial Guinea. We're also seeing GTA ramp up during 1Q and expect to end the quarter near full capacity. Looking at the cost side, costs were largely in line with budget with CapEx slightly higher due to GTA startup costs. Turning to slide eight. 2024 was an important year in enhancing the financial resilience of the company. As Andy mentioned, we issued $900 million of new bonds, refinanced and increased the capacity of our reserve-based lending facility, bringing in two new banks. Collectively, these transactions increased our average debt maturity to around four years. The top right chart shows our current maturity schedule. We have minimal near-term maturities—only $250 million due in 2026, which we anticipate repaying from cash flow. It's also important to note we have managed our debt to ensure we don't have any large single maturity in any given year, enabling us to repay the debt from future cash flow, further de-risking the balance sheet. The chart on the bottom right shows how we continue to actively manage future price volatility through our rolling hedging program. We currently have around 60% of our first half oil production hedged with downside protection of approximately $70 per barrel, providing solid protection for our cash flow. We will continue to be proactive in the management of oil price volatility through 2025 and into 2026. Turning to slide nine, our financial priorities for the year. Andy was clear in his opening remarks that cash generation is our key financial priority in 2025 and beyond. We therefore intend to be very disciplined in our cost management, targeting meaningful reductions in both CapEx and overhead. As we come to the end of a capital-intensive period for the company, we expect capital spending to fall sharply with a 2025 capital budget of $400 million or below—a reduction of more than 50% year on year. We're also working hard to decrease overhead, targeting a reduction of around $25 million by year-end 2025. As we generate cash flow expected from the second quarter onwards, we will prioritize debt pay down, initially focusing on the RBL as our highest cost prepayable debt as well as the outstanding 2026 and 2027 notes. The final deliverable for the year from a financial perspective is the refinancing of the GTA FPSO. The financing was initially put in place with the operator during COVID, and we're working with them on bringing down the overall cost which should lower our unit operating costs on the project. So in summary, 2025, our goals are clear: growing production and lowering costs to prioritize cash generation. With that, I'll hand it back to Andy to take you through the assets and the outlook for the year ahead.

Thanks, Neal. Turning now to Slide ten. I want to start with GTA and talk about the journey we've been on to create a new Atlantic basin LNG hub and why we're excited about the future. The timeline on the top of the slide starts in 2015 when Kosmos Energy Ltd., as operator, had the initial exploration success at Tortue discovering a field with around 25 TCF of gas in place, making it the second largest hydrocarbon discovery in the world that year. A year later, we ran our farm-out process with BP coming in as operator for total consideration to Kosmos Energy Ltd. of around $950 million which includes funding the first $550 million of our development CapEx on the GTA project. In late 2018, the project took final investment decision with first gas production announced at the end of 2024. While there have been some challenges along the way including COVID-related delays and a major typhoon that damaged the FPSO, the project has taken around five years to develop. Earlier this month, we announced the first of a series of important milestones related to the delivery of the project. First LNG production was delivered in early February, and we are very close to loading the first cargo from the project, with an LNG tanker standing by at the hub terminal. This new Atlantic basin LNG hub is ideally located for certain markets in Europe, with short sailing distances and low transportation costs. There's also an advantage because the GTA gas contains minimal CO2 or hydrogen sulfide—important for both the environment and ongoing maintenance of the infrastructure. Turning now to Slide eleven, which looks at the future. The partners will soon start to receive revenue from the project, another key milestone. Once fully ramped up, expected in the second quarter, the project's off-takers' contracted volume of 2.45 million tons per annum requires around 400 million standard cubic feet of gas per day. This equates to approximately thirty gross cargoes a year. Project partners will co-lift the cargos, which should result in a steady revenue stream and limited over-lift or under-lift impact quarter on quarter. With GTA Phase one starting up, the partnership has been working collaboratively on the expansion for future phases. The operator, national oil companies and Kosmos Energy Ltd. have a shared vision to fully utilize the existing infrastructure to drive a low-cost brownfield expansion that increases future LNG output while ensuring the local market's gas needs are met. There's a chart on the bottom left that shows there is more than enough recoverable gas in place to build out multiple future phases each capable of producing for over twenty years. Initial data from the producing GTA wells has been positive, providing confidence in the reserve base for future expansion phases. The partnership is initially focused on Phase One Plus, a brownfield expansion which leverages the infrastructure we put in place for the first phase. In year one it is really a transition year, and we'll see higher operating costs as we complete the commissioning phase and ramp up volumes to full capacity. Unit cost should trend lower over time as the facility ramps up to its limit and start-up costs are behind us. While we have sold 2.45 million tons per annum under the BP sales contract, the floating LNG vessel should be able to achieve a nameplate production of around 2.7 million tons per annum or higher, as typically seen on LNG plants. In addition, as Neal mentioned, we're working with our partners to refinance the FPSO lease which should further reduce operating costs. In the medium term, adding growth from the Phase One Plus expansion and additional uncontracted volumes should continue to drive higher margins. In summary, it's been a journey to get where we are today. The project has a lot more running room and we're excited about the future potential. Turning to Slide twelve, which looks at operations in Ghana. Net production in 2024 was just over 41,000 barrels of oil equivalent, below the operator's target for the year. This was primarily driven by the J-69 well and issues at Jubilee coupled with insufficient voidage replacement or water injection due to reliability issues primarily related to power generation. We have worked with the operator to address these field management issues. The moderate decline ahead of the upcoming drilling campaign improved power reliability delivering voyage replacement in excess of 100%, consistent with what has been delivered through the first two months of 2025, as can be seen on the chart on the slide. Looking ahead, we have an active year in Ghana beginning with the 4D seismic campaign, which is ongoing. This modern 4D data will be processed with the latest technology giving us a much better understanding of the subsurface, particularly in terms of fluid migration allowing the partnership to choose the best future drilling locations. We continue to believe Jubilee has significant upside and therefore are focused on accessing the best technology to increase the recovery factor of more than two billion barrels of oil in place. We're looking to leverage our position in the Gulf of America, accessing the latest seismic processing techniques and reservoir management tools including AI. We're also planning two new wells in Jubilee this year with a rig that is returning to Ghana and will continue with a four-well program in 2026. In terms of guidance for the year, the operator didn't provide specific guidance for the fields in its recent trading update. We expect gross Jubilee production between 70,000 to 76,000 barrels of oil per day and gross TEN production at between 15,000 to 16,000 barrels of oil per day. We also expect around 6,000 barrels of oil equivalent of gas net to Kosmos Energy Ltd. Turning to slide thirteen, the Gulf of America, we saw a gradual quarterly ramp-up in production from 2Q onwards. As can be seen on the chart, we delivered the first Winterfell wells and the production optimization projects on our Jobo and Kodiak, both of which are performing ahead of expectations. The year-end exit rate is indicative of the production potential of this business unit before taking into account planned maintenance and hurricane downtime. The operator of the Winterfell project is currently performing the remediation work on the Winterfell tree well before the rig moves to drill the Winterfell four well which is expected online early in the second half of the year. On Tiberias, we continue to progress the development with our partner, Oxy, but at a managed pace given our focus on 2025 cash generation. We're aiming to complete the farm-out around the time of project sanction. In addition, we have an attractive portfolio of value-accretive opportunities. The outlook for activity in the Gulf of America has improved under the new administration with the potential for more lease sales giving us more opportunity to continuously high-grade our future activity set. Full year guidance is 17,000 barrels of oil equivalent per day net, an approximate 20% increase year over year. Turning to Slide fourteen. In the Extraprimary area, we finished the infill drilling campaign in late 2024. With both wells now online, collectively producing around 9,000 barrels of oil per day gross. In the fourth quarter, we drilled the King D well, which did encounter oil zones in the Upper Albian section confirming elements of an active petroleum system, but were deemed sub-commercial; the well was plugged and abandoned. The team is now working on analyzing the results to better understand the future potential of the area. For 2025, we're seeing the continuing contribution of the two infill wells and we'll be reprocessing the latest seismic we have over the fields to help plan the next infill drilling campaign which we expect to carry out in 2027. Full year guidance is 9,000 to 11,000 barrels of oil per day net, an approximate 15% increase year over year. Turning to Slide fifteen to conclude today's presentation. As I've communicated in today's material, we did a lot in 2024 to put in place the foundations to deliver value for our shareholders in 2025. Production is rising as new projects come online and ramp up. As we showed in the earlier slides, we have the reserve base to support this production well into the future. We're rigorously managing costs to prioritize free cash flow with material reductions planned in both CapEx and overhead. We plan to use cash generated to reduce our absolute debt and leverage, enhancing the financial resilience of the company. And we maintained our attractive portfolio of growth opportunities which provides differentiated optionality for Kosmos Energy Ltd. into the future. Thank you. I'd now like to turn the call over to the operator to open the session for questions.

Thank you. We'll now be conducting a question and answer session. The confirmation tone will indicate your line is in the question queue. You may press star two if you'd like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star key. One moment please while we pull for questions. Thank you. Our first question is from Neil Mehta with Goldman Sachs. Please proceed with your question.

Thank you. Andy, Neal, and team. We've been getting a couple of questions this morning around startup costs that you highlighted in the deck. So maybe it's a good place to start, which is just talk about the start-up and commissioning costs and these appear to be one-time in nature, but how do you think about framing those out and working through them?

Yeah. Thanks, Neil. Good question. We've talked on prior calls about the key components of the operating costs, namely the FLNG toll, the upstream OpEx and the FPSO financing. In today's update, we've given you a pretty fulsome guidance for the year, which reflects our best view of the production ramp-up, cargo timings and costs. As we said in our prepared remarks, this year is going to be a transition year as we finish up all the commissioning work and see volumes ramp up. Therefore, we would expect to see costs higher this year and then trend lower over time. So what's going to drive that? No more one-off commissioning costs, volume ramp-up to the contracted volume which is an ACQ of 2.45 million tons per annum, testing the facility at nameplate capacity of 2.7 and potentially higher, and then refinancing of the FPSO lease. So Neil, perhaps you could ask Neal to give you a breakdown of those areas and add a little more color around what we're targeting going forward as we remove some of those one-off costs and get to a steady state.

Yep. Thanks, Neil. When you look at it going forward in terms of a normalized day, we talked about the two components which are normal OpEx, which is the FLNG vessel and the operating expense. We'd expect that to normalize in the $4 to $5 per MMBtu equivalent range. Then there's the question of the FPSO financing and how much we can bring that to. Notionally, think about that as a little more than another $1 per MMBtu equivalent in terms of a long-term FPSO cost. But again, you'll get significant reduction on the basis of decreasing the cost and actually increasing the volume as Andy pointed out. At that point, you are producing very cost-competitive LNG.

Okay. Thanks. And a follow-up just around CapEx. The company's guide to a ceiling of $400 million. Is there a scenario where it comes in lower than that? What are some levers you can pull on to maximize capital efficiency? And is this a multiyear harvest mode?

Good question. As I emphasized in the prepared remarks, we are prioritizing free cash flow. That's what our shareholders have been looking for. We're clear about delivering a sustainable free cash flow yield at today's equity price. We've been through a growth phase; now it's about rigorous cost management and rigorous capital allocation. We're tackling overhead with a significant reduction delivered by year-end, which is sustainable. On the capital side, we're targeting $400 million or lower in 2025. Primarily in 2025, that's capital going into sustaining the base—Jubilee, the Winterfell wells. Going forward, it's about getting the right balance between growth and cash flow returns. We believe we have a portfolio where we can do that. Previously we've talked about a capital profile of around $500 million total—$300 to $350 million base and $150 to $200 million growth. In 2025, we're at the low end of that guidance because we've got limited spend on growth. We'll be disciplined around allocation of growth; it's not about decline or harvesting. We can operate the business with $300 to $350 million base and then bring in quality growth options at the right pace to sustain the company. One of the things that differentiates Kosmos Energy Ltd. is the quality of its portfolio. We have over twenty years of 2P reserves and plenty of organic opportunities. Now it's about discipline to get the free cash flow yield into the right place through delivering the cash and managing that growth portfolio. So it's not harvest; it's sustainable free cash flow going forward.

Thank you, Andy.

Our next question is from Charles Meade with Johnson Rice.

Yes. Good morning, Andy and Neal and the rest of the Kosmos Energy Ltd. team. Andy, I want to go back to your prepared comments about GTA. Not the immediate, but your discussions about Phase One Plus. I want to understand what that is in timing. Is Phase One Plus the increment from the contracted 2.45 to the nameplate of 2.7, or does it also include gas that will go into local markets? What is it composed of, and what's the time frame for that?

Good question, Charles. Think of Phase One Plus as fully utilizing all of the infrastructure we have in place for Phase One. The FPSO actually has a debottleneck capacity close to 800 million cubic feet, which is significantly more than it currently produces. That represents relatively low-cost debottlenecking. Phase One Plus is about increasing the capacity of the current vessel, utilizing the rest of the infrastructure we have in place, and likely increasing domestic gas supply as well. These are phenomenally economic because they require very little additional capital. We have great alignment now between the national oil companies, ourselves and BP on doing the technical studies to deliver that. The minister from Mauritania has expressed a goal to accelerate production with targets toward 2030, so that is the objective. It's a capital-efficient brownfield expansion aimed at getting the most out of what we have today.

That makes sense. Thank you. And then back to slide twelve on Jubilee. You guided to 70,000 to 76,000 barrels gross. Can you talk about the assumptions implicit in that number specific to the FPSO, generation and water injection? What assumptions are implicit for performance of the FPSO?

Sure, Charles. The fundamentals of Jubilee are clear: it's a large oilfield with roughly 2.4 billion barrels of oil in place. We're currently carrying a recovery factor in our reserves around the low to mid-thirties percent. To get to the remaining reserves, it's about good reservoir management, fundamentally getting water into the ground in the right places. The operator struggled in 2024 with less than 100% voidage replacement and that impacted the entry rate into 2025. Our assumption is to get to 100% voidage replacement through the year—one of the key assumptions—and we've started the year strongly on that. It's really about power generation reliability and we've worked with the operator to address that. Facility uptime has been strong—around 98-99%—so not a concern. We do have a planned shutdown built into the schedule at the end of the first quarter which impacts 1Q volumes. Finally, the delivery of two additional wells—one producer and one injector—is assumed, with drilling starting in 2Q and delivering in the back end of 3Q. Those are credible assumptions. We also plan to use the 4D seismic we're acquiring to improve well selection for 2026. The issue isn't reserves, it's ensuring proper field management—replacement water in the right place—and selecting high-quality infill wells with good execution.

That's great detail. I'll hop back in the queue.

Our next question is from Matthew Smith with Bank of America. Please proceed with your question.

Hi there. Good morning, Andy and Neal. A couple of questions. On Tortue: it's interesting to see discussion of further phases, including Phase One Plus. Have you detected a clear change in emphasis from the operator or more impetus for those potential development schemes? Also, should we still think about your $400 million CapEx ceiling for future years beyond 2025, or could Tortue CapEx be incremental to that?

Good question, Matthew. There is alignment between BP as operator, ourselves and the national oil companies. BP has always talked about getting the first phase online and then considering next phases with new data. The initial production data from flowing the wells at the start of the year has been positive which underpins confidence in the resource base and future phases. We're being careful and efficient about the next phases—Phase One Plus is very capital efficient with little additional CapEx. Regarding your second question: we've always talked about $300-350 million base and $150-200 million growth in a typical year. In 2025 we're at the low end of that because growth spend is limited and we're prioritizing free cash flow. We're not going to embark on a large new capital program; any growth will be phased and disciplined. Tortue-related CapEx through the end of this decade is expected to be minor and primarily focused on brownfield activities to increase throughput and maximize revenue.

Thanks, Andy. Second quick one on Ghana and Jubilee specifically: you noted the strong voyage replacement early 2025. Can you clarify where production has run so far in January and February—has the reduced run rate been similar to the voidage replacement?

Yes. We're absolutely in the range we forecast. Remember the quarter includes downtime from maintenance, so there will be a little impact in 1Q. Currently we're producing within the range we've forecast and the start of the year performance on voidage replacement has been positive. The planned maintenance causes some 1Q impact but we expect to see benefits later in the year as additional wells come online.

Thank you very much. I'll pass it on.

Our next question is from David Round with Stifel. Please proceed with your question.

Great. Thanks, guys. Follow-up on Jubilee: guidance seemed upbeat given other comments. How much of that optimistic guidance is down to the results you've seen from voidage replacement, and at what point can we be confident those issues are in the past, or is it too early?

Good question, David. If you do the right things the right way, you'll deliver the right result. The focus has been on power generation reliability. We've identified vulnerabilities and taken actions to address them, including a shutdown at one of the generators earlier this year which will be beneficial going forward. I feel comfortable we know what needs to be done and how to deliver it. Variables remain, like the timing and delivery of the two wells, but we have a good track record with those wells and the same rig will be returning. We have a clear set of objectives for the field: get to 100% voidage replacement, execute the shutdown and wells as planned, and use the 4D seismic to inform 2026 drilling. Hold us to account on delivering those items.

Okay. Thanks, Andy. Second question: this is the first time we've heard from you since the terminated discussions with Tullow. Any thoughts there and is that off the table going forward?

I'll step back and talk about M&A generally. We've been through a growth and investment period and that's coming to an end. We've built a strong portfolio with a long reserve life and now it's about balancing free cash flow delivery with growth. When we look at M&A opportunities we view them through two lenses: value accretion and, importantly, free cash flow accretion—the latter being essential given our leverage focus. That's what guided moves like the Oxy deal. With respect to Tullow, we were at a very preliminary stage, and we are not planning to revisit those discussions at current market valuations. We have no intention of using Kosmos Energy Ltd.'s equity at depressed levels, a view shared by our shareholders.

All right. Thanks, Andy.

Our next question is from Mark Wilson with Jefferies. Please proceed with your question.

Thank you. Good morning. Wanted to ask about the timeline to reach the 1.5 times leverage level and remind us of your priorities once you get beyond that point—shareholder returns versus further debt pay down.

Hey Mark. We've been clear: priority is free cash flow generation, which we use to pay down debt in a regular cadence from 2Q forward. In terms of getting to around 1.5 times net leverage, we see that as probably toward the back half of 2026, through a combination of debt pay down and growth in EBITDAX as production increases. That's assuming a normalized oil price. As we approach that point we'll reopen the conversation on the right balance between further debt pay down and shareholder returns and continue to discuss that with our shareholders.

Got it. Thank you. Another on Tortue: given the 22-year 2P reserve life and low incremental CapEx to debottleneck, if you assumed running the facility at 2.45 or 2.7 million tons per annum, how long would it be before you'd have to drill any wells into the Tortue reservoir to sustain that level?

Good question, Mark. The initial production data over the first several weeks has been positive which supports the reserve base. The current facility and well capacity exceed the ~400 million standard cubic feet per day required to deliver the contracted 2.45 mtpa. The timing for additional wells depends on connected volumes per well and observed decline rates, but we are several years away from needing large numbers of new wells. If we drill, the wells would be added in a capital-efficient way with tiebacks to existing infrastructure; the incremental capital is largely the cost of individual wells rather than large new infrastructure. It's early to give an exact well schedule, but the important takeaway is that incremental CapEx to sustain or modestly grow throughput is limited.

Okay. Thanks. Good luck with that.

Our next question is from Charles Meade with Johnson Rice. Please proceed with your question.

Andy, thanks for letting me back in. You touched on the performance of the wells seen in the first seven weeks—can you talk about that? Are you seeing less drawdown and better flowing pressures, or is there something more?

Charles, what we're doing in the early days is understanding the tank size associated with each well. In terms of actual productivity, we had good DSTs with initial tests and then solid flow during extended flowbacks when commissioning each well. So we had a good idea of the initial rate per well. The additional data we've collected over weeks of production is giving more positive indications about the size of the tank per well—not just a few days of data, but weeks—so that supports a better view on durable capacity from each well.

Got it. That's great detail. Thanks, Andy.

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 and thank you for your participation.