Yahoo Finance

Nealesh Shah

Thanks, Andy. Turning now to slide 7. 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 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 o -quarter. Detailed guidance is provided as an appendix to the slides. The 1Q planned maintenance program includes the 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 are 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 start-up costs.
Turning to slide 8. 2024 was an important year in enhancing the financial resilience of the company. As Andy mentioned, we issued $900 million of new bonds to refinance and increase 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 derisking 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 9, 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 the 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.

Andrew Inglis

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 base in LNG hub and why we're excited about the future. The timeline on the top of the slide starts in 2015 when Kosmos as an operator have 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 in 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 damage 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 in served markets in Europe with short sailing distances and low transportation costs. It's also advantaged 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 offtake as contracted volume of 2.45 million tonnes 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 coalesce the cargoes, which should result in a steady revenue stream with a limited under-lift or over-lift impact quarter on quarter.
With GTA Phase 1 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.
So 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 the reserve base for future expansion phases. The partnership is initially focused on Phase 1+, a brownfield expansion, which leverages the infrastructure we've put in place for the first phase. On Phase 1 costs, year 1 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. The unit cost should trend lower over time as the facility ramps up to the facility's limit and the start-up costs are behind us.
While we have sold 2.45 million tonnes per annum under the BP sales contract, the floating LNG vessels should be able to achieve a nameplate production of around 2.7 million tonnes 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 1+ expansion and additional uncontracted volumes should continue to drive higher margins. So in summary, it has 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 J-69 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. To moderate decline ahead of the upcoming drilling campaign, improve power reliability, delivering bodies 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 40 seismic campaign, which is ongoing. This modern 40 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 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 also planned two new wells in Jubilee this year with a rig that is returning to Ghana, and we'll continue with a full 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 to 76,000 barrels of oil per day and gross 10 production of 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.
Turning to slide 13. In the Gulf of America, 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 our 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 Gulf of America has improved under the new administration with the potential for more lead sales giving us more opportunity to continuously high-grade our future activity set. Full-year guidance is 17,000 to 20,000 barrels of oil equivalent per day net, 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 barrels 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 subcommercial, and 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 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 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.

Question and Answer Session

Operator

(Operator Instructions) Neil Mehta, Goldman Sachs.

Neil Mehta

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

Andrew Inglis

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 the costs as we finish up all 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 tonnes per annum. And then as I alluded to in the prepared remarks, assessing the facility at its nameplate capacity of 2.7 and potentially higher. And then there's some refinancing of the FPSO lease to do.
So yeah, probably good. Then 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're targeting going forward as we remove some of those one-off costs and get to a steady state.

Nealesh Shah

Yeah. So yeah, when you look at it sort of going forward in terms of a normalized state, we 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 to $5 per million type range. And then this 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 in terms of a long-term FPSO cost.
But again, a significant reduction on the basis of decreasing the cost and actually increasing the volume, as Andy pointed out. And then like I said, you are are producing very cost-competitive LNG at that point.

Neil Mehta

And the follow-up is just around CapEx. The company has guided 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 '25 look. I know it's early to talk about '26, but for investors who are worried about the sustainability of that capital efficiency, are we entering into a harvest mode that could be multiyear in nature?

Andrew Inglis

Good question, Neil. I think as I 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 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 '25, 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. And we believe we've got a portfolio where we can do that and create the right balance. Operated projects go going forward. Some of those are operated, those growth projects are operated. So we have a greater degree of control.
In prior calls, we've talked about a capital profile of around $500 million. So we said $300 million to $350 million in the base $150 million to $200 million growth. In '25, 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 million to $350 million million. 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 RTP on a 2P basis of over 20. 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 be confident that we can deliver that forward together with the right pacing of the growth target. So absolutely, it's not about harvest. It's not about the decline. It's about a sustainable free cash flow yield going forward.

Operator

Charles Meade, Johnson Rice.

Charles Meade

Andy, I want to go back to your prepared comments about about GTA, not the immediate, but your discussion is about Phase 1+, I guess, you're calling it. I want to understand what that is and the timing. Is 1+ the increment from the contract of 2.45 to the nameplate of 2.7? Or does that also include some gas in the local markets? Or what is it composed of it? And what's the timeframe for that?

Andrew Inglis

Yeah, no. Good question, Charles. I think that the way to think about 1+ is fully utilizing all of the infrastructure that we've got in place in terms of Phase 1, yeah? So the FPSO actually has a debottleneck capacity of close to 800 million standard cubic feet, sort of double what it produces today, and that is a relatively low cost, relatively really low-cost debottlenecking.
Then it's about utilizing the rest of the infrastructure we have in place to best move that gas through the existing plan 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 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 the target for 2030, while 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

No, that makes sense, Andy. 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 guided to 70,000 to 76,000 barrels 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, 76,000 for the performance of the FPSO?

Andrew Inglis

Yeah. So look, Charles, again, it's sort of coming back to what are the fundamentals of Jubilee, yeah? What I do want to reemphasize, I think, is that Jubilee is a world-class oil field. It has got 2.4 billion barrels of oil in place. We're currently carrying recovery factor in our reserves are probably around 33%.
If 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, yes. 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 struggled -- the operator struggled in '24 as we show on slide 12 with less than 100% voidage replacement, and that has impacted the entry rate into '25. 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 our 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 1Q 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 started in 2Q with the wells delivering at the back end of 3Q. So I think we've got a good set of credible assumptions there. And 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 '26 when we have a four-well program. So the combination then of sort of building forward with a higher exit rate of '25, the additional drilling in '26, higher quality data from the 4D, that enables you then to sustain the profile going forward. So 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.

Operator

Matthew Smith, Bank of America.

Matthew Smith

A couple of questions. If I start with one on Tortue again, if I could. I guess, firstly, it would be, it's interesting to see you talking about three phases or further phases on Tortue again, including the Phase 1+. So I guess the first question was really whether you've detected a clear change in emphasis from the operator or at least more impetus, perhaps I should say, with those potential development schemes.
And then equally, could I just link it back to Phase 1A 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 mind in terms of the ceiling for future years beyond 2025, or could the Tortue CapEx be incremental to that?

Andrew Inglis

Okay. Yeah, Matt. So to unpack question sort of -- the third 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 always talked about getting the first phase on, 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 of seven weeks into the flow back.
I think we're also clear about being really capital efficient about the next phases. So as I said, to to Neil and Charles, what we're aiming to do is expand Phase 1+ in a really capital efficient way. It has got very little additional CapEx associated with it. And therefore, we're getting an incremental sort of value add from the 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 million to $350 million in the base, $150 million to $200 million in growth. The $300 million and $350 million 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 we're -- and the free cash flow yield that we 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 the underlying question is sort of, are you off to the races again with a massive capital spend? The answer is absolutely no, 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 mode, which allows us to get more volume and maximize the revenue.

Matthew Smith

And if I could ask a second 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 voidage replacement on the water side of things early 2025. I just wondered if you could clarify, 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

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 that we have a downtime from the maintenance. So we're absolutely producing within the range that we're forecasting currently but will 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.

Operator

David Round, Stifel.

David Round

Just a 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

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 the focus for the operator. And as it was so far, we've started the year positively.
I think the -- 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 at 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 derisks that to some degree.
So I think we've got a very clear set of objectives for the field what it is we're managing. And therefore, what you should do is hold us to account for delivering the things that we said we'd do in terms of voyages placement, timing of the well, timing of the shutdown, et cetera.

David Round

Okay. 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

Sort of I sort of stepped back a little from the question and sort of maybe sort of talk about M&A in general. I think the -- we've been through a period of growth for the company in a period of investment is now coming to an end. We've built a very strong portfolio, I believe, with a strong and long RTP and there with -- a deep hopper of growth projects. And actually, as we've discussed on the call, yes, the challenge is actually making sure that we get the right balance between the free cash flow delivery and the growth. And as you can see in '25, we're focused absolutely on free cash flow generation.
I think if you then sort of turn to M&A, I think we've constantly always 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 as 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 at end the talks. We obviously have no intention of using cost the current depressed levels, which was a view shared by our shareholders.

Operator

Mark Wilson, Jefferies.

Mark Wilson

I'd just like to ask on the time line you expect to that leverage level? And then, yes, 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

Yes. Thanks. Mark, why don't I let Neal take that?

Nealesh Shah

Yes, Mark, yes. So again, we've been clear sort of the priority is generation of free cash flow, that free cash flow, we just pay down debt and sort of a regular cadence 2Q forward. In terms of getting to around 1.5 times, I see that as probably towards the back half of '26 in terms of where we are. And that was through a combination of debt paydown and growth in the EBITDAX as sort of production continues to increase. 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 is the right priority in terms of further debt paydown and shareholder returns. So that's, in my mind, we'll revisit that conversation and continue to happen with our shareholders as we approach that in the back half of '26.

Mark Wilson

Got it. Okay. That's great. 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 debottleneck and otherwise the capacity in the vessel.
Could you also speak to the -- if we assumed running this facility at 2.45 million tonne per annum or even the 2.7 million tonne 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?

Andrew Inglis

Thanks, Mark. Yes, as always, good questions. I go back to what I said earlier, which is the initial sort of whatever it is, sort of seven or eight weeks into the production data we're getting back from the reservoir is sort of positive Obviously, we need to simulate all of that and build it into that or 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 of 2.45. Yes.
Therefore, the timing of the current -- the next set of wells is dependent on the -- obviously, the connected volume to each well, and therefore, the decline rate that we see we are several years away from needing that well capacity. And then if you were to drill, you would probably add sufficient wells and to increase the capacity overall above the 800 million standard cubic fees that will be driving the profile sort of in that sort of 2030 timeframe, yes? 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 the way 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.

Operator

Charles Meade, Johnson Rice.

Charles Meade

You touched on this twice, maybe 3 times the performance of the wells, which you've seen in the first seven weeks. Can you talk about that? Is that just 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

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 yes. So in terms of actual productivity, we did pretty good BST's with initial BST and then we did pretty good flowbacks, extended flow backs 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, in the next piece of data we needed was just actually what do we think the size of the tank is yes? 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.

Operator

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.