Kosmos Energy - Earnings Call - Q4 2024

Executive Summary

• Q4 2024 delivered a small GAAP net loss of $6.6 million (–$0.01 diluted EPS) on $397.7 million of revenue, with an adjusted net loss of $16 million (–$0.03) as higher exploration charges and transition costs weighed on results.
• Operations reached critical milestones at Greater Tortue Ahmeyim (GTA): first gas on Dec 31, 2024, first LNG in February 2025, and first cargo loading in April 2025—setting up revenue recognition commencement in Q1 2025 and a ramp to steady-state from Q2 2025.
• 2025 capital discipline is a central theme: capex guided to “<$400M” versus the prior ~$550M indication, with ~50% year-on-year reduction and targeted ~$25M overhead cuts by year-end 2025; management prioritizes deleveraging to <1.5x leverage by H2 2026.
• Production trends: Q4 net production ~66.8k boe/d (below guidance due to Jubilee reliability/water injection and Winterfell downtime), but remediation actions are in place; 2025 production guided to 70–80k boe/d.
• Estimate comparison: S&P Global Wall Street consensus could not be retrieved (system limit). As such, “vs. estimates” is not included; investors should focus on Q1 ramp and Q2 free cash flow run-rate as the likely near-term stock catalysts.

What Went Well and What Went Wrong

• What Went Well

  • GTA commissioning milestones achieved: “first gas” (Dec 31, 2024), “first LNG” (Feb 2025) and first cargo loading (Apr 17, 2025), setting up revenue recognition and cash flow commencement in Q1 2025 and ramping thereafter.
  • Strategic pivot to free cash flow: capex cut to “<$400M” in 2025 (vs. ~$550M prior), and overhead reduction targeted at ~$25M by year-end 2025, enabling deleveraging and improved financial resilience.
  • Portfolio depth and longevity: 2P reserve life ~22 years and 2P reserves ~530 mmboe; management underscored potential for brownfield expansion at GTA Phase 1+ to increase capacity at low capex.

• What Went Wrong

  • Q4 production below guidance due to Jubilee water injection/power reliability issues and Winterfell-3 downtime; management detailed remediation and planned 1Q maintenance impacting near-term volumes.
  • Cost headwinds from GTA start-up/commissioning elevated Q4 costs and capex slightly above guidance; exploration expense rose on Akeng Deep dry hole ($28M) and Asam write-off ($37.2M).
  • Year-over-year pricing/cost mix headwinds: average total sales price per boe fell to $65.80 (from $75.64), while oil & gas production costs per boe rose to $25.27 (from $15.46), compressing margins.

Transcript

Operator (participant)

Good day, everyone, and welcome to Kosmos Energy'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. Please go ahead.

Jamie Buckland (VP of Investor Relations)

Thank you, Operator, and 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 U.K. and SEC filings. Please refer to our annual reports, stock exchange announcements, and SEC filings for more details. These documents are available on our website. At this time, I will turn the call over to Andy.

Andrew Inglis (Chairman and CEO)

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 what differentiates Kosmos' strategy and the ability of the portfolio to deliver sustainable cash generation. We'll then provide an update on the operational and financial progress we've 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 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 20 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, 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, with Kosmos plotted against our U.S. and international peers, as well as the majors. For Kosmos, given the ongoing ramp-up of GTA and planned maintenance at other fields in the first quarter of the year, we've 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 Tiberius and Yupanqui, alongside a quality hopper of infrastructure-led exploration prospects in the U.S. Gulf of Mexico. Turning to slide four, in the second half of 2022, we set a target to grow production capacity by around 50% 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 a 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 expected to fall significantly from over $800 million on average in 2023 and 2024 to $400 million this year, a reduction of over 50%. 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 to sustain it, and 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 U.S. Gulf of Mexico, 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 paydown until we reach our leverage goal of below 1.5x of mid-cycle oil prices, after which we'll balance cash across further debt paydown 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, broadly 50/50 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, with the upward revisions largely driven by gas as we continue to progress the GTA project. With a project about 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 530 million barrels of oil equivalent represent a reserves-to-production ratio of 22 years, a major differentiator for Kosmos 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 30 years, highlighting the organic running room 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, and we continue to operate safely during the year with zero lost-time injuries or total recordable injuries. This high safety performance, with incident rates well below industry averages, is a trend we've maintained for many years. As previously mentioned, our 2P reserves grew year-on-year to 530 million bbl 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 3 comes back online with a Winterfell 4 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, with first LNG production achieved earlier this month and first cargo lifting expected shortly. Through the year, we raised a total of $900 million in new bonds at competitive rates, and 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 financial results for the quarter and the year.

Neal Shah (CFO)

Thanks, Andy. Turning now to slide seven, production for the fourth quarter was lower than guidance, partly due to lower Jubilee production, which was flagged last month by the operator. Actions have been taken to resolve the water injection and reliability issues at Jubilee, with voidage 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 1 and 2 were down most of the quarter prior to being brought back online late in the year. The fourth quarter 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 a shutdown of the Jubilee FPSO, a one-month turnaround of Devils Tower, 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 cost. 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 with 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 bbl, 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 paydown, initially focusing on the RBL as our highest cost prepayable debt, as well as the outstanding 2026 and 2027 notes, and 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.

Andrew Inglis (Chairman and CEO)

Thanks, Neal. Turning now to slide 10, I want to start with GTA and talk about the journey we've been on to create a new Atlantic-based LNG hub and why we're excited about the future. The timeline on the top of the slide starts in 2015 when Kosmos 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 a total consideration to Kosmos 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 in China 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 the LNG tanker standing by at the hub terminal. This new Atlantic-based LNG hub is ideally located to serve markets in Europe with short sailing distances and low transportation costs. It's also advantageous because the GTA gas contains minimal carbon dioxide or hydrogen sulfide, important for both the environment and ongoing maintenance of the infrastructure. Turning now to slide 11, which looks at the future.

With the first cargo loading shortly, the partners will soon start to receive revenue from the project, another key milestone. Once fully ramped up, expected in the second quarter, producing LNG at the off-taker's contracted volume of 2.45 million tons per annum requires around 400 million standard cubic feet of gas per day. This equates to approximately 30 gross cargoes a year. The project partners will co-lift the cargoes, which should result in a steady revenue stream with a limited underlift or overlift impact quarter on quarter. With GTA phase I starting up, the partnership has been working collaboratively on the expansion of future phases. The operator, national oil companies, and Kosmos 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 markets' gas needs are met.

As the chart on the bottom left shows, there is more than enough recoverable gas in place to build out multiple future phases, each capable of producing for over 20 years. Initial data from the producing GTA wells has been positive, providing confidence in a reserve base for future expansion phases. The partnership is initially focused on phase I plus, a brownfield expansion which leverages the infrastructure we put in place for the first phase. On phase I costs, year one is really a transition year and will see higher operating costs as we complete the commissioning phase and ramp up volumes to full capacity. The unit costs should trend lower over time as the facility ramps up to the facility's limit and the startup costs are behind us.

While we have sold 2.45 million tons per annum under the BP sales contract, the floating LNG vessels 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 I plus expansion and additional uncontracted volumes should continue to drive higher margins. So in summary, it's been a journey to get where we are today, but the project has a lot more running room and we're excited about the future potential. Turning to slide 12, which looks at operations in Ghana.

Net production in 2024 was just over 41,000 barrels of oil equivalent, which was below the operator's target for the year, primarily driven by the J69 well in 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 voidage replacement in excess of 100% is required, 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 2 billion bbl of oil in place. We're looking to leverage our position in the U.S. Gulf of Mexico, 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, but we expect gross Jubilee production of between 70,000 bbl-76,000 bbl of oil per day and gross TEN production of between 15,000 bbl-16,000 bbl of oil per day. We also expect around 6,000 bbl of oil equivalent of gas net to Kosmos. Turning to slide 13, in the U.S. Gulf of Mexico, we saw a gradual quarterly ramp-up in production from 2Q onwards, as can be seen on the chart as we delivered the first Winterfell wells and the production optimization projects on Odd Job 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 3 well before the rig moves to drill the Winterfell 4 well, which is expected online early in the second half of the year. On Tiberius, 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 ILX opportunities. The outlook for activity in the U.S. Gulf of Mexico 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 17-20,000 barrels of oil equivalent per day net and an approximate 20% increase year-over-year.

Turning to slide 14, in Equatorial Guinea, we finished the infill drilling campaign in late 2024 with both wells now online, collectively producing around 9,000 bbl of oil per day gross. In the fourth quarter, we drilled the Akeng Deep ILX well, which did encounter oil zones in the upper Albian section, confirming elements of an active petroleum system, but were deemed sub-commercial, so the well was plugged and abandoned. 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 will 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 bbl-11,000 bbl of oil per day net and an approximate 15% increase year-over-year.

Turning to slide 15 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 into the future. Thank you. I'd now like to turn the call over to the operator to open the session for questions.

Operator (participant)

Thank you. We'll now be conducting a question-and-answer session. If you'd like to ask a question, please press star one on your telephone keypad. A 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 keys. 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.

Neil Mehta (Analyst)

Thank you, Andy, Neal, and team. We've been getting a couple of questions this morning around startup costs that you highlighted in the text, and so maybe it's a good place to start, which is just talk about startup 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?

Andrew Inglis (Chairman and CEO)

Yeah. Hey, thanks, Neal. Yeah, 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, and for costs, as we finish off all of the commissioning work and see the volumes to ramp up, therefore, we would expect to see costs to be higher this year and then trend lower over time, so what's going to drive that? Sort of no more one-off commissioning costs, volume ramp-up to the contracted volume, which is an ACQ of 2.45 million tons per annum.

And then, as I alluded to in the prepared remarks, testing the facility at its nameplate capacity of 2.7 and potentially higher. There is some refinancing of the FPSO lease to do. It would probably be good if Neal can kind of give you a breakdown of those three areas and actually give you a little bit more color around what we are targeting going forward as we remove some of those one-off costs and get to a steady state.

Neal Shah (CFO)

Yep. Andy, so yeah, when you look at it sort of going forward in terms of a normalized state, we've talked about the two components, which are normal OpEx, which is the FLNG vessel, and the operating expense. And we'd expect that to normalize in the $4-$5 per MMBtu range. And then it's a question of the FPSO financing and how much we can bring that to. But I think sort of notionally, if you think about that as a little more than another $1 per MMBtu in terms of a long-term FPSO cost. But again, a significant reduction on the basis of decreasing the costs and actually increasing the volume, as Andy pointed out. And then, like I said, you are producing very cost-competitive LNG at that point.

Neil Mehta (Analyst)

Okay. Thanks, Andy. Thanks, Neal. And the follow-up is just around CapEx. The company's guide to a ceiling of $400 million. Is there a scenario where it could come in lower than that? What are some levers you can pull on to maximize capital efficiency? And that's a 2025. Look, I know it's early to talk about 2026, but for investors who are worried about the sustainability of that capital efficiency, are we entering into a harvest mode that could be multi-year in nature?

Andrew Inglis (Chairman and CEO)

Good question, Neal. I think, as I've sort of appropriately emphasized in the prepared remarks, we are prioritizing free cash flow. I think that's what our shareholders have been looking for. And we're clear about delivering a sustainable free cash flow yield at today's equity price of around 25%. That's what we showed on that opening slide. What's that about? We've been through a growth phase. Now it's about rigorous cost management and rigorous capital allocation. We're tackling the overhead with a significant reduction delivered by the year-end, which obviously is sustainable going forward. And then on the capital side, as you said, we're targeting $400 million or lower. And primarily in 2025, that's capital going into sustaining the base, the wells in Jubilee, the wells in Winterfell. And then going forward, it's about getting that right balance between growth and cash flow returns.

We believe we've got a portfolio where we can do that and create the right balance. Operated projects going forward, some of those are operated. Those projects are operated, so we have a greater degree of control. In prior calls, we've talked about a capital profile of around $500. Sort of we said $300-$350 in the base, $150-$200 growth. In 2025, we're at the low end of that guidance because we've got limited spend on growth. And we are going to be disciplined around the allocation of growth. So it's not about decline. It's not about harvesting. We can absolutely sustain the business at $300-$350. And then it's about bringing in those quality growth options at the right pace to sustain the company. And one of the things that does differentiate Kosmos is the quality of its portfolio.

We've got an R to P on a 2P basis of over 20 years. So we've got plenty of organic material to work on. And now it's about the discipline of getting the free cash flow yield into the right place through delivering the cash and managing that growth portfolio so that we can sustain that free cash flow yield. And that's absolutely what we're engaged in now. And hopefully, by some of the points that we've illustrated in the prepared remarks around the discipline around cost, therefore, should give confidence that we can deliver that forward together with the right pacing of the growth targets. So absolutely, it's not about harvest. It's not about decline. It's about a sustainable free cash flow yield going forward.

Neil Mehta (Analyst)

Thank you, Andy.

Andrew Inglis (Chairman and CEO)

Great. Thanks, Neal.

Operator (participant)

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

Charles Meade (Analyst)

Yes. Good morning, Andy and Neal and the rest of the Kosmos team there. Andy, I want to go back to your prepared comments about GTA, not the immediate, but your discussions about phase I plus, I guess you're calling it. I want to understand what that is and the timing. Is one plus the increment from the contract of 2.45 to the nameplate of 2.7, or does that also include some gas into local markets? Or what is it composed of, and what's the timeframe for that?

Andrew Inglis (Chairman and CEO)

Yeah. No, good question, Charles. I think that the way to think about one plus is fully utilizing all of the infrastructure that we've got in place in terms of phase I. Yeah. So the FPSO actually has a de-bottleneck capacity of close to 800 million standard cubic feet. We sort of double what it produces today. And that is a relatively low-cost, relatively really low-cost de-bottlenecking. Then it's about utilizing the rest of the infrastructure we have in place to best move that gas through the existing plant and beyond. So I think you're going to see a component which is increasing the capacity of the current vessel, the Gimi that's there. And you're going to probably see an increase in the domestic gas take. But equally, those projects are phenomenally economic because it's literally at very low capital cost, and you have the potential to double the throughput.

So that's the journey we're on. And I think in terms of timing, we have great alignment now between the NOCs, ourselves, and BP on getting on with the technical studies to deliver that. And I think as Minister Khaled from Mauritania said, our goal is to accelerate production in the upcoming phase with a target for 2030 or ensuring the local gas market needs are met. So that's the objective, Charles. Yeah. It's about a brownfield expansion. It's getting the most out of what we have today and doing that in a really capital efficient way.

Charles Meade (Analyst)

No, that makes sense, Andy. Thank you for that. And then if I could go back to, I think it's slide where you talked about Jubilee in, I believe it's slide 12. Can you talk about the question is about you got it to 70,000 bbl-76,000 bbl of oil a day gross. Can you talk about what the assumptions are you have, perhaps specific to the FPSO generation and water injection? What assumptions do you have are implicit in that 70,000 bbl-76,000 bbl for the performance of the FPSO?

Andrew Inglis (Chairman and CEO)

Yeah. So look, Charles. Again, it's sort of coming back to what are the fundamentals of Jubilee. Yeah. What I do want to re-emphasize, I think, is that Jubilee is a world-class oil field. It's got 2.4 billion bbl of oil in place. We're currently carrying a recovery factor in our reserves of probably around 33%. You run the math on that, we've just produced maybe 55% of the reserve base. I think the recovery factor will be in the high 30s at the end of the day. So we're probably sort of halfway there. Yeah. Less than halfway there. So to get to the remaining reserves, what you have to do, it's fundamentally about good reservoir management, which is fundamentally about getting water in the ground in the right places. We've struggled. The operator struggled in 2024, as we show on slide 12, with less than 100% voidage replacement.

And that has impacted the entry rate into 2025. And that's sort of that's why the guidance is sort of where it is. Our objective is to get to 100% voidage replacement through the year. So that's one of the key assumptions. And we've started the year strongly on that. And it's really about power generation reliability. And we've worked with the operator to address that. Clearly, there's a piece around facilities uptime. Facilities uptime has been strong, 98%-99%. So not worried about that. We do have a planned shutdown built in, which is taking place at the end of the first quarter, which is sort of impacting Q1 volumes. So those are key assumptions. And then the final assumption is the delivery of two additional wells, one producer and one injector. The objective starting 2Q with the wells delivering the back end of 3Q.

I think we've got a good set of credible assumptions there. The objective clearly is then to utilize the 4D that we're shooting this year. We started already. Then there's the objective to use the information from that 4D to impact the well selection for 2026 when we have a full well program. The combination of then of sort of building forward with a higher exit rate of 2025, the additional drilling in 2026, higher quality data from the 4D, that enables you then to sustain the profile going forward. We're not short of reserves here. The issue is making sure we get the proper field management, which is fundamentally about voidage replacement, water going in the right place, and then selection of high-quality infill wells and the delivery of them.

Charles Meade (Analyst)

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

Andrew Inglis (Chairman and CEO)

Great. Thank you.

Operator (participant)

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

Matthew Smith (Analyst)

Hi there. Good morning, Andy. Good morning, Neal. Just a couple of questions. If I start with one on Tortue again, if I could. I guess firstly, it would be interesting to see you talking about three phases or further phases on Tortue again, including the phase I plus. So I guess the first question was really whether you've detected a clear change in emphasis from the operator or at least a more impetus, perhaps I should say, with those potential development schemes. And then equally, could I just link it back to if phase Ia looks as though it's potentially progressing, should we still think about your CapEx go forward run rate? And should we keep that $400 million in mind in terms of the ceiling for future years beyond 2025, or could the Tortue CapEx be incremental to that?

Andrew Inglis (Chairman and CEO)

Okay. Yeah. So to unpack those questions, sort of the first question is sort of, is there alignment, as it were, between the operator, ourselves, and the NOCs on the way forward? And I think yes, there is. I think BP has always talked about getting the first phase on and getting results from the wells, enabling them then to sort of start to think about the next phases with new data. What I would add is that the initial data from actually flowing the wells from the beginning of the year is actually positive. So that sort of underpins the resource base that enables you therefore to have confidence in the future phases. So I think that is an important piece of data, as it were, six weeks into the flowback or seven weeks into the flowback.

I think we're also clear about being really carefully efficient about the next phases, so as I said to Neal and Charles, what we're aiming to do is expand phase I plus in a really carefully efficient way. It's got very little additional CapEx associated with it, and therefore, we're getting an incremental sort of value add from that brownfield development, so if you then go to your sort of follow-on question, which is, okay, well, fine, how does that work within the capital allocation? I'll sort of just do a rinse repeat of the prior answer, which is to say that we've always talked about $300-$350 in the base, $150-$200 in growth. The $300-$350 in the base sustains the base. That's the focus of the capital spend today, so we're not in harvest mode. It's not declining.

And then it's about phasing those growth projects. So in the free cash flow yield that we've forecast in terms of our current equity price, that takes account of probably a little more growth CapEx, but certainly within that frame that we've talked about in the past. So if the underlying question is sort of, are you off to the races again with a massive capital spend, the answer is absolutely not. Yeah. We're going to prioritize the free cash flow. And the capital spend on Tortue really through the end of this decade is going to be minor. It's going to be about sustaining the current well count and doing a little bit of brownfield mods, which allows us to get more volume and maximize the revenue.

Matthew Smith (Analyst)

All right. Well, thank you very much for that, Andy. And then if I could ask a quick question, just a quick one. Apologies if I missed this earlier, but just around Ghana and Jubilee specifically, if I could. So it seems like a pleasing performance in terms of the voidage replacement on the water side of things early 2025. I just wondered if you could clarify, and like I say, apologies if I missed it, where the production has run so far in January, February. Has the production run rate been similar to the voidage replacement?

Andrew Inglis (Chairman and CEO)

Yeah. So we're absolutely in the range that we forecast. And of course, the only thing that if you look at the quarter, you need to remember we have the downtime from the maintenance. So we're absolutely producing within the range that we're forecasting currently, but we'll have a little impact in 1Q because of the unplanned maintenance. And then we get the benefit of the additional wells starting up in 3Q. So everything going to plan in terms of the forecast range that we've guided to.

Matthew Smith (Analyst)

Thank you very much. Happy to end it on.

Andrew Inglis (Chairman and CEO)

Great. Thanks, Matt.

Operator (participant)

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

David Round (Analyst)

Great. Thanks, guys. Just to follow up, please, on Jubilee, which actually I thought guidance was pretty upbeat given some of the other comments out there. How much of that guidance and let's say your feels like a more optimistic view on Jubilee is down to the results you've seen from voidage replacement? And at what point can we be confident that those issues are in the past, or is it too early to get carried away there?

Andrew Inglis (Chairman and CEO)

Yeah. It's a good question, David. I don't want to be over simplistic about it, but if you do the right things in the right way, you'll deliver the right results. So we know what it is we need to focus on. I would say that's the focus for the operator. And as it were, so far, we've started the year positively. I think the fundamental issue is just about power generation reliability. And we've done a lot of work to identify the vulnerabilities and address those. We actually did a shutdown of one of the generators earlier this year, and that's actually going to be beneficial going forward. So I think I feel comfortable that we know what needs to be done, how it needs to be delivered, and we're therefore focused on delivering the forecast that we've put in place. What are the variables?

The additional variable will be the addition of the two wells. But I think we've demonstrated in the past a good track record of delivery of those wells. The rig that's coming back to drill is the same rig that we used in the prior campaign. So that sort of de-risks that to some degree. But I think we've got a very clear set of objectives for the field. We know what it is we're managing. And therefore, what you should do is hold us to account for delivering the things that we've said we do in terms of voidage replacement, timing of the wells, timing of the shutdown, etc.

David Round (Analyst)

Okay. Thanks, Andy. Second one then, just I think this is the first time we've heard from you since the terminated discussions with Tullow. Can I just get your thoughts there, please, and whether that's off the table from now on?

Andrew Inglis (Chairman and CEO)

I sort of step back a little from the question and maybe sort of talk about M&A in general. I think we've been through a period of growth for the company and a period of investment. It's now coming to an end. We've built a very strong portfolio, I believe, with a strong and long R/P, and with it a deep hopper of growth projects. Actually, as we've discussed on the call, the challenge is actually making sure that we have the right balance between the free cash flow delivery and the growth. As you can see in 2025, we're focused absolutely on that free cash flow generation. I think if you then sort of turn to M&A, I think we've constantly looked at opportunities through sort of two lenses. There needs to be clear value accretion for our shareholders.

And most importantly, free cash flow accretion, which given our focus on leverage reduction, it absolutely has to be part of any transaction. So that's what we did on the Oxy deal, for instance. So if you sort of come back to Tullow, I think the short answer to you is, are we planning to look at it again? And the answer is no. You sort of know the background, David. We were at a very, very preliminary stage before we were forced to put out a press release to end the talks. We obviously had no intention of using Kosmos's equity at the current depressed levels, which was a view shared by our shareholders.

David Round (Analyst)

Great. Thanks, Andy.

Andrew Inglis (Chairman and CEO)

Great. Thanks, David.

Operator (participant)

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

Mark Wilson (Analyst)

Thank you. Good morning, gents. I'd just like to ask on the timeline you expect to that 1.5x leverage level, and then, yeah, just remind us of your priorities once you get beyond that point, possibly for shareholder returns versus further debt and leverage pay down.

Andrew Inglis (Chairman and CEO)

Yeah. Thanks. Well, why don't I let Neal take that?

Neal Shah (CFO)

Yeah. Hey, Mark. Yeah. So again, we've been clear sort of the priority is generation of free cash flow. That free cash flow, we use to pay down debt in sort of a regular cadence, 2Q forward. In terms of getting to around 1.5x, we see that that's probably towards the back half of 2026 in terms of where we are. And that was through a combination of debt pay down and growth in the EBITDAX as sort of production continues to increase. Yeah. And that's all assuming sort of a normalized oil price. And so as we get to that point, then again, I think then the conversation reopens around where's the right priority in terms of further debt pay down and shareholder returns.

That's, in my mind, we'll revisit that conversation and continue to have it with our shareholders as we approach that in the back half of 2026.

Matthew Smith (Analyst)

Got it. Okay. That's great. Thank you. And then another one moving over to Tortue, and this speaks to your overall 22-year 2P reserve life. You spoke clearly to very little additional CapEx required to de-bottleneck and otherwise the capacity in the vessel. Could you also speak to if we assumed running this facility at 2.45 or even the 2.7 million tonnes per annum, how long would it be before you'd have to drill any wells at all into the Tortue reservoir to extend at that level? Thank you.

Andrew Inglis (Chairman and CEO)

Yeah. Thanks. Thanks, Mark. Yeah. As always, good questions. I go back to what I said earlier, which is the initial sort of whatever it is, so seven or eight weeks into the production data we're getting back from the reservoir is sort of positive. Obviously, we need to assimilate all of that and build it into therefore the timing of the next well. So currently, well capacity well exceeds the 400 million standard cubic feet that we would need to deliver the current ACQ of around of 2.45. Yeah. Therefore, the timing of the current of the next set of wells is dependent on the, obviously, the connected volume to each well and therefore the decline rate that we'd see. But we are several years away from needing that well capacity.

And then if you were to drill, you would probably add sufficient wells then to increase the capacity overall above the 800 million standard cubic feet that will be driving the profile sort of in that sort of 2030 timeframe. Yeah. So I'm not going to give you exact guidance of how many wells in each year, because I think it's slightly early on that. But I think where you can take from that is it's not a significant draw on capital. The infrastructure is in place in terms of tiebacks to the existing manifold. So literally, it is the cost of those individual wells.

Matthew Smith (Analyst)

Okay. Thank you. I'll hand it over and good luck with that ramp-up. Thank you.

Andrew Inglis (Chairman and CEO)

Great. Thanks, Mark.

Operator (participant)

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

Charles Meade (Analyst)

Andy, thanks for letting me back in the queue here. You touched on this twice, maybe three times, the performance of the wells, which you've seen in the first seven weeks. Can you talk about that? Is that just you're seeing less drawdown and better flowing pressures, or is there something more that you guys have seen in these early days?

Andrew Inglis (Chairman and CEO)

No, what you're doing in the early days, Charles, is basically to understand what you think the size of the tank is associated with each of the wells. Yeah. So in terms of actual productivity, we did pretty good DSTs. We did initial DST, and then we did pretty good flowbacks, extended flowbacks of the wells when we commissioned each of the wells. So we had a pretty good idea of the rate of each of the wells. So if you like, the next piece of data we needed was just actually what do we think the size of the tank is. Yeah. And I would say we're seeing more positive indications of the size of the tank, because clearly we've got sort of weeks of production from one of the wells as opposed to just a few days.

Charles Meade (Analyst)

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

Andrew Inglis (Chairman and CEO)

Great. Thanks.