Good day, everyone. Welcome to Kosmos Energy's Third Quarter 2020 Conference Call. Just a reminder, today's call is being recorded. At this time, let me turn the call over to Jamie Buckland, Vice President of Investor Relations at Kosmos Energy.
Thank you, operator. Thanks to everyone for joining us today. This morning, we issued our Third -Quarter Earnings Release. This release and the slide presentation to accompany today's call are available on the investors page of our website. Joining me on the call today to go through the material are Andy Inglis, Chairman and CEO, and Neal Shah, CFO. During today's presentation, we will make forward-looking statements that refer to our estimates, plans, and expectations. Actual results and outcomes could differ materially due to factors we note in this presentation and in our U.K. and SEC filings. Please refer to our annual report, stock exchange announcement, and SEC filings for more details. These documents are available on our website. At this time, I will turn the call over to Andy.
Thanks, Jamie, good morning and afternoon to everyone. I'll start today's presentation with the highlights for the quarter before passing you over to Neal to talk through the financials. I then want to spend the bulk of the call talking about the Tortue project and the significant progress we've made this year and our plans for this quality asset going forward. Neal will then cover the balance sheet, and I'll conclude the presentation before opening up to Q&A. Turning to slide two, the key messages for the quarter. Kosmos delivered a robust operational performance in the quarter, with production of around 57,000 barrels of oil equivalent per day. This was slightly below our prior guidance, largely due to the elevated storm activity in the Gulf of Mexico. However, production in Ghana and Equatorial Guinea was steady, with both assets performing in line with expectations.
This should allow us to deliver annual production in the range of 61,000-62,000 barrels of oil equivalent per day, near our initial guidance at the start of the year. In Mauritania and Senegal, we've been working closely with BP and the NOCs to optimize the Tortue project. I'll talk more about the project later in the presentation. It's a world-class development that's progressing well in an environment where many projects are getting deferred. Phase 1 remains on track for first gas in the first half of 2023, coinciding with the time the LNG market is expected to tighten. The optimization of Phase 2, targeting an expansion to 5 million tons per annum, simplifies the project by leveraging existing infrastructure from Phase 1, significantly reduces costs, and boosts the overall project return.
With the prospect of enhanced future returns, now is not the optimal time to reduce our interest in the project, and we've established a financing path which funds our capital obligations to first gas. Finally, we continue to strengthen the balance sheet. In September, we monetized our frontier exploration portfolio to Shell for around $100 million in upfront cash consideration. We expect to receive the proceeds shortly. We've also put in place a five-year Gulf of Mexico facility, which provides the company with additional liquidity and replaces our Gulf of Mexico prepayment facility. With the actions we've taken this year, we expect the base business to generate free cash flow at current oil prices going forward. Turning to slide three. As I mentioned on the previous slide, Kosmos delivered solid operational performance in 3Q.
In Ghana, net production of around 28,000 barrels of oil per day was in line with guidance. Jubilee continues to perform well with high reliability, delivering gross production of around 88,000 barrels of oil per day within the quarter. Uptime on the facility was over 98% for 3Q and now over 95% for the year so far. At TEN, gross production around 50,000 barrels of oil per day was in line with guidance. Facility uptime at TEN was 98% in 3Q and 99% for the year so far. For the full year, we still expect 10 cargoes to be delivered from Ghana. In Equatorial Guinea, net production of around 11,000 barrels of oil per day was in line with guidance and is expected to stay flat until drilling begins next year. We still expect four and a half cargoes to be delivered from EG.
In the Gulf of Mexico, net production was around 18,000 barrels of oil equivalent per day in the quarter, around 10% lower than guidance, reflecting the elevated hurricane activity. As a result, 2020 has seen one of the most active storm seasons in history, our fields had 17 days of downtime during the quarter, which is significantly higher than the six days of total downtime we typically forecast for a storm season. That said, the base production from our Gulf of Mexico assets is encouraging. The Tornado 4 injection well came online in late September. Initial results have been positive. We also expect to begin the Kodiak completion this month. Bring the well online early in 2021. In our ILX portfolio, we expect to spud the Winterfell exploration well, previously named Monarch, this quarter, with the results expected early next year.
Stepping back, it's been a tough year operationally due to COVID, the Gulf of Mexico shutdowns in May, and the increased level of hurricane activity. That said, with all of these challenges, full-year production is still expected to come in at 61,000 to 62,000 barrels of oil equivalent per day, near our initial guidance at the start of the year. This highlights the quality and diversity of the asset base, which enables Kosmos to be resilient in a low-price environment. With that, I'll hand over to Neal, who will take you through the financials for the quarter.
Thanks, Andy. Turning to slide four, the key financial items for the quarter. I'm not going to touch on every line item, as most are consistent with our annual guidance. Focusing on the key areas, as Andy mentioned, production of 57,000 barrels of oil equivalent per day was slightly below guidance due to the increased storm activity in the quarter. Excluding the impact of this elevated hurricane activity, the company would have been cash flow positive in the quarter. Realizations improved significantly, around twice as high in Q3 as compared with Q2. This was due to a combination of higher oil prices, but also the normalization of the wide differentials we saw in Q2. At present, we are currently selling oil across all three hubs at prices in line with the benchmarks. Total OpEx is continuing to trend lower, although not as low as we would like.
Q3 was higher on a per-barrel basis than guided, impacted by the lower production and higher ongoing operating costs related to COVID, such as mandatory two-week quarantine periods for workers going offshore. Looking at the year, total OpEx is expected to be around 20% lower than 2019, which reflects the continuing progress we are making. Our base business CapEx came in at $53 million in Q3, in line with expectations. In addition, there was $47 million of accrued CapEx in Mauritania and Senegal. This is non-cash, and we expect the carry of our capital obligations to extend to around the end of the year, with a small payment expected in the fourth quarter as a result of the progress achieved on Tortue Phase I. I'll now hand it back to Andy to give an update on activities in Mauritania and Senegal.
Thanks, Neal. Turning to slide five. I'd like to start with the progress made on the Tortue project this year. Over the past six months, the partnership of BP, Kosmos, and the NOCs of Senegal and Mauritania has worked hard to transform the project, reducing the capital cost and boosting the overall project returns. In that time period, the outlook for LNG has continued to improve, and the project looks set to deliver first gas at a time when LNG pricing is expected to strengthen, a direct result of the many project deferrals in the U.S. and internationally. In its recent Annual Energy Forum, Wood Mackenzie presented the two charts on this slide. From the trough in 2020, Woodmac expects a much tighter LNG market over the coming years, driven by growing global demand and the deferral cancellation of higher-cost LNG projects.
2020 has seen the lowest LNG supply growth since 2014, with only five million tons per annum of new liquefaction added this year. As 2020 demand has been roughly flat with 2019, even with the impact of COVID, spot LNG prices have already almost tripled from the lows in the second quarter. In addition, there have been no new LNG project FIDed in 2020. The first time in almost 20 years that has happened. As a result, Woodmac expects the supply-demand gap to open up around 2023, just as the Tortue project plans to deliver first gas and creating a positive backdrop for marketing the volumes associated with phase II. With a significantly enhanced project, an improving LNG backdrop, and a financing path established, we're more excited than ever about the project.
Turning to slide six, which shows the continuous progress we've made on phase I of the project over the quarter. As BP flagged in its Q3 results call two weeks ago, the partnership is working very hard and very well on Tortue Phase I. With activity on all four key work streams now increasing after periods of lockdown during Q2 and Q3. At the end of the year, phase I of the project is expected to be around 50% complete, with first gas on track for the first half of 2023. Turning to slide seven, which shows the optimization of the phase II project. This slide, which also uses Woodmac data, compares the break-even cost of Tortue Phase II delivered into Asia alongside other LNG projects.
Using our latest cost estimate, which incorporates a significant reduction in CapEx of the project, Tortue Phase II sits at the far left of the chart with a delivered cost into Asia of just over $4 per MMBtu, competing very favorably with other expansion projects in Wood Mackenzie's analysis. Shipping into Europe has an even lower delivered cost, further demonstrating the competitiveness of the project. The optimization of Phase II is targeting an expansion of the scale of the overall development to 5 million tons per annum, the sweet spot for leveraging all the major infrastructure from Phase I. For example, Phase II will utilize spare capacity in the subsea infrastructure in Phase I. The processing capacity of the FPSO will be expanded without requiring a second facility.
There's no need for a second gas export line from the FPSO to the hub terminal. As a result, we believe phase II will be the most competitive brownfield LNG expansion project globally. With the limited upstream capital requirements expected to be less than $1 billion gross to first gas, we expect to be able to finance our net share of the phase II development largely out of phase I cash flows. Turning now to slide eight. As I mentioned, we've established a financing path for a self-funded project that allows Kosmos to retain its current share of the project which, when built out, can deliver an expected return on remaining investment of approximately 7x . Kosmos' net capital to first gas from 2021 through 2023 is forecast to be around $725 million, which can be seen on the chart on the upper right of slide eight.
We're engaged with BP to sell the FPSO to an off-balance sheet special purpose vehicle for the back cost paid so far, or around $160 million net to Kosmos. BP and Kosmos are in negotiations with the anticipated purchaser of the FPSO, and we plan to close in the first quarter of next year. The SPV will take on the future capital obligations of the FPSO, which means another $160 million of Kosmos' future capital obligations will be transferred to and funded by the SPV. Kosmos also intends to refinance our national oil company loan with commercial banks in 2021, which is expected to see around $100 million returned to Kosmos. The combination of these two activities is expected to fund Kosmos' obligations in 2021. The outstanding CapEx balance of approximately $300 million due in 2022 and 2023 is expected to be funded by direct investment in Mauritania and Senegal.
Kosmos is currently in discussions to secure this financing by mid-2021. Today, Kosmos's development CapEx on the project is being funded by the BP development carry, and we expect the forward investment, post FPSO financing, to be around $400 million net to Kosmos. With phases I and II of Tortue expected to generate $150 million-$200 million per year net to Kosmos at a 5.50 gas price, the optimized project is expected to deliver a return on investment of approximately 7x , which is why we're excited about moving the optimized project forward. With that, I'll now hand back to Neal to run through the balance sheet and liquidity.
Turning now to slide nine. At the end of Q3, we announced total liquidity of around $650 million. Since then, we have successfully completed our RBL redetermination, where we agreed to a total borrowing base of $1.32 billion, which reduced liquidity to just under $500 million. This reduction was largely due to the banks adjusting their forward price decks. This quarter, we expect to receive around $100 million of proceeds from the Shell transaction, with key approvals already granted. We therefore expect the business to generate significant free cash flow in the fourth quarter. Including the impact of the Shell transaction, today, we revised our base business CapEx guidance to $140 million-$150 million in 2020. This also reflects the acceleration of the Kodiak completion and the start of the drilling of the Winterfell ILX prospect in Q4.
We expect Q4 Mauritania and Senegal accrued CapEx to be flat with the third quarter. We have also closed the Gulf of Mexico facility in the third quarter, which refinanced the previous prepayment facility. This facility has a $100 million accordion feature, providing potentially additional liquidity if required, ensuring that we have a solid financial position as we close out the year. With that, I'll hand it back to Andy to wrap up.
Thanks, Neal. The final slide 10. It has been and continues to be a challenging year for the sector, but it's important to step back and look at how our company competes today. Kosmos has a high-quality portfolio of world-class conventional oil and gas assets with strong ESG credentials. Our focus on offshore exploration, development, production along the Atlantic margin has not changed. We have three production hubs in Ghana, the Gulf of Mexico, and Equatorial Guinea, as well as a world-scale LNG development, with the first phase expected to be over 50% complete by year-end, which now has a clear financing path. In addition, the optimization of the second phase leverages existing infrastructure and delivers enhanced return. These advantage assets have low decline rates, Brent or HLS price benchmarks, and an overall carbon intensity that is significantly lower than the industry average.
As our recent TCFD report shows, we're making business decisions and capital choices to deliver shareholder value consistent with a lower carbon world. Given the low-cost nature of the assets and low decline rates, these assets produce significant free cash flow, even at low oil prices. We have a corporate free cash flow break-even of approximately $35 per barrel Brent. We expect to generate free cash flow going forward at current oil prices into 2021. On the gas side, the phase development of Tortue with first gas planned in the first half of 2023 is expected to generate a self-funded, long-term free cash flow stream to complement the cash generative oil assets in the portfolio today. On exploration, we continue to high-grade the exploration portfolio with a focus on returns.
Our acquisitions in Equatorial Guinea and the Gulf of Mexico targeted opportunities that created value through optimizing the existing production base and through infrastructure-led exploration. We now have built a hopper of ILX opportunities across Kosmos that we continue to high-grade. Success in exploration comes from having quality through choice. This means prioritizing proven basins where we have a deep technical understanding, a large resource portfolio, and can leverage infrastructure. Finally, we have a solid balance sheet to execute our plan. As Neal just outlined, we have ample liquidity, no near-term debt maturities, and a business that is expected to generate cash and reduce leverage. Thank you. I'd now like to turn the call over to the operator to open the session for questions. Operator?
At this time, we will be conducting a question and answer session. If you would 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 would 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 poll for a question. Our first question is from Charles Meade with Johnson Rice. Please proceed with your question.
Good morning, Andy, or afternoon as it may be, and to Neal as well. Andy, I wanted to ask a question. I recognize that you guys haven't You're likely still working on the details of this sale leaseback, but I just wanted to explore a little bit more what you are comfortable talking about and what you're not. As I was looking from the outside in, it seemed like one of the challenges you guys had to address is that, obviously, a project finance would make sense for you, but it's not as clear that it would make sense for your partner, BP. I'm curious, should we be thinking about this as that BP is also going to contribute their interest into this SPV or perhaps alternatively, is BP going to sponsor this SPV, and it's going to be leveraging off their balance sheet?
Neal, why don't you pick that up?
Yes. Charles, we're still working through the process, but I think there's optionality for BP to do it in several different ways, to where they could participate in both sides of the transaction to where they benefit from the transaction as well. I'd say there's a couple of different ways that we could end up in terms of BP's participation.
Okay. All right. We'll stay tuned on that. One other question on just to interpret your slide on the upper right on page eight. It makes sense that you're doing this financing for the FPSO, because that's where you can put the ring fence around the tolling operation with production. Is the right way to interpret this is that remaining $300 million, that's all the other pieces like the subsea FLNG and Winterfell?
I think the way to think about it, Charles, is to think about is that we're working and engaged with BP on the FPSO sale and leaseback. As Neal said, they can choose how they participate in it. Clearly, we're sitting alongside them at the moment in the negotiations with the preferred buyer of the FPSO. When it comes to the other final $300 million, we have choices in which the ways in which we would actually secure that. It will be through some direct investment. We're looking at various options today as to how we do that. Clearly, what we're looking to do is find the most competitive way to secure that financing.
Got it. Thanks for that added detail.
Great. Thanks, Charles.
Our next question is from David Round with BMO Capital Markets. Please proceed with your question.
Hi, guys. I've just got a couple both on phase II and similar theme. First on phase II, can I just clarify, you talked about a CapEx number there which was potentially quite a bit lower than some of the numbers out in the market. I just really wanted to understand how locked down and when you considered it sort of a final estimate, or was there a bit of movement still to be expected in that number? Just on the direct investment for the balance of phase I funding. It sounds like you're leaving the door open for potentially a smaller farm out to potentially cover the balance of the CapEx. Do you get the sense that there might be more appetite for a smaller stake in the project?
Right. Thanks, David. Yeah. I'll take the phase II one first on the capital. Yeah. If you sort of talk through the capital estimates. As you look to the first Tortue phase I and capital to first gas, we forecast that at slightly over $4 billion. If you take out the FPSO, it gets round to around $3 billion to first gas, which is sort of consistent with the numbers we've talked through. What's interesting about phase II, though, is that it leverages all the pre-investment that's gone into phase I. As I noted in my remarks, we're leveraging the available capacity in the subsea infrastructure. Rather than put a new facility in for expanding the gas throughput, you can do it off the back of the FPSO. There's no need for another gas export line from the FPSO to the initial processing.
Actually, we picked a sweet spot of 5 million tons per annum, because it optimizes the use of that infrastructure. I think that's been the big breakthrough, working alongside BP, was to reimagine how you get the most out of the next phase, by fully utilizing the infrastructure and therefore the minimum amount of CapEx. That's why the CapEx is so low. The CapEx to add that additional sort of 2.5 million tons for the upstream piece of it is, as I said in my remarks, slightly less than $1 billion, and that's our current view. As I move on to the next question of sort of the current environment, I would say that from a sales perspective, yeah, the current environment's been tough. There aren't many companies that have got the balance sheet today to be able to participate.
By the way, the current environment has allowed us to really sharpen the pencil with BP to come up with the right next phase. I'm genuinely excited about the way in which we've managed to create the right project now. As we sort of say on the slide, it's the right project at the right time. It's incredibly efficient the next phase, because of the pre-investment. When you look at where we are, we clearly were faced with a choice almost. Do you sell a piece of the infrastructure for $320 million, or do you sell a piece of the project? Clearly for our shareholders today, the right decision is not to sell the project, but to sell the infrastructure, yeah.
Going forward, there could be an opportune time in the future to crystallize the right value and then, a sell-down is something we would consider. I think as you rightly say, with FPSO financing in place, a smaller piece of the project will be attractive. What we're focused on at the moment is ensuring that the financing path is delivered on time, and we're well-engaged in that today. I'm clear now with BP, we've got the right size of project, 5 million tons per annum. Expanding to that level is the right project, and it's incredibly efficient because you're leveraging all of the pre-investment. We've got a good project now.
Okay. That's very clear. Can I just ask a really quick follow-up?
Yeah.
Presumably this potentially really compresses the build timetable as well for phase II, does it?
No, it doesn't actually. You've still got some stuff to do, right? There will be a brownfield project to put the additional gas processing on. It doesn't all sort of time-wise shrink. It does make it a simpler project. I'd say the execution risk has gone down. The timeline is probably typical of what you'd expect, yeah. We've got work to do with BP to get all of that sequencing done and so on. It's a much simpler project to execute, so therefore it has lower execution risk.
That's great. Thanks a lot.
Great. Thanks, David.
Our next question is from Neil Mehta with Goldman Sachs. Please proceed with your question.
Thanks guys for all the incremental color this morning. The first question is on the U.S. elections and what impact does that have on the way you think about your Gulf of Mexico business? As we size up the value of that business, how are you thinking about the moving pieces, particularly around federal leases?
Yeah, thanks, Neal. Look, elections and political transitions are not something new for Kosmos or for our industry. We lived through that process in all the countries that we operate in. What I'd say is that there's a couple of truisms, I think. One is, if the quality of your assets is good, you can continue to compete irrespective of the government in power. I think the second truism is, it's important to have an aligned agenda with the country and not actually being focused on the individual party in power. What does that mean for the Gulf of Mexico? I think the first thing I would say is that, well, it's about a third of our current production. It has actually the lowest cost and lowest carbon intensity in our portfolio.
The carbon intensity is around eight kilograms per barrel, which is significantly lower than the global averages and actually significantly lower than alternative oil production in the U.S. I think the second thing is that we've clearly made a strong commitment to the energy transition and we're targeting carbon neutrality in our Scope 1 and Scope 2 by 2030. That will involve mitigation measures. We've got some really interesting projects on the Gulf Coast. These are blue carbon projects focused on wetland restoration. Actually, they have carbon sinks which store around 10 x the carbon of a terrestrial tropical forest. I think the point there is to say that we believe we can be a solution to a problem rather than be an impediment. These are low-cost projects.
I believe we have both the portfolio and the approach now where we can continue to be very competitive because we've got low-cost, low-carbon assets, and we have some innovative low-cost mitigation measures that will allow us to deliver on our commitments. Actually, sort of nothing changes from our commitment on that side. When you look at it from a leasing perspective, I think that there's been a lot of rhetoric before, and I'm sure there'll be a lot of rhetoric after the election. Yes. Is there a risk that there's no new leasing on federal lands or waters? I think that remains an issue. The important thing for us is we've got a hopper of more than five years of future drilling opportunities in the Gulf, so there's no immediate concern, yeah?
I believe we've got a business which is competitive today, and actually in a sense, we'll be even more competitive going forward because of the nature of the assets and the way in which we're conducting our business.
Just to clarify, you guys still have five years of drilling opportunity without requiring incremental federal lease, right? Is that what you're saying?
Correct. Yeah. That's actually drilling four prospects a year, yeah? Which is sort of probably more than we would anticipate, actually.
Okay, great. The follow-up question is just on your Brent breakevens. You talk about $35 a barrel. That's before growth CapEx. How do you think about, let's call it over the next three years, the level at which you cover your free cash flow, sustaining plus growth CapEx, and how that evolves over time? This might be a question for Neal. Just can you remind us what the sensitivity is to every dollar change in oil price so we can sort of frame out what the free cash flow profile looks like at our oil deck?
Good question, Neil. I think it's incredibly important the free cash flow above $35 first target to paying down debt. Neal will give you the numbers on the sensitivity in a moment. That's the first call on capital. First call on cash flow. In terms of the growth opportunities, we'll be focused on limited ILX projects. We have the first one of those in the Winterfell opportunity, and that's sort of less than $10 million net to us. The most I could see, and we would need to see quite a sort of positive oil price, is sort of up to $50 million in growth projects. We've got plenty of competing projects for that at the moment. You're going to see us really driving that capital allocation decision. Phenomenal focus on the free cash flow generated paying down debt.
Then it's going to be very limited ILX opportunities. I think it's sort of 0-50 would be the number that we'd be looking at there.
To add on that, Neil, around sort of $50 million would probably be the upper limit, at least in the short term on the ILX portfolio. As you can imagine, given our exposure to oil prices, we're pretty levered. The general rule of thumb that we use is about around $100 million of free cash flow impact for every sort of $5 move in oil prices. There's some sort of offset to hedging, et cetera, we can generate a significant amount of free cash flow from the base business in a $45-ish dollar world.
Okay. Cool. Thanks, guys.
Right. Thanks.
Our next question is from Bob Brackett with Bernstein Research. Please proceed with your question.
Thank you. I had a clarification question on phase II. If I understood correctly, phase I was about $4 billion, of which maybe $1 billion was the FPSO. You're saying phase II at slightly less than $1 billion. Is that net to Kosmos, or is that gross for the whole expansion?
That's gross. Let me just sort of talk you through the numbers, Bob. Just slightly over $4 billion, of which the FPSO is slightly over $1 billion. The rest of it, the breakwater, which is a significant cost. Which clearly you're not doing on phase II. The breakwater, the pipeline from the FPSO to the breakwater for the inshore processing, which you're not doing on phase II. Phase II is ultimately, the CapEx spend is for the expansion of the gas processing, which is a brownfield project on the FPSO. There's limited build-out of the subsea because that's got capacity, and then you're drilling some incremental wells. If you think about it, there is a significant capital efficiency by utilizing all of that infrastructure that you put into phase I.
To be clear, that makes a lot of sense. This expansion takes you from, say, 2.5 million tons per annum phase I, adds another 2.5 million tons to get to the 5. It wasn't the 4 million ton per annum expansion that might have been.
Exactly, Bob. Yeah.
thought about.
Exactly, Bob. Yeah. What you've done is, in essence the work that we've done over the last six months is to say, look, how do you get the best project for the expansion? Yeah. The obvious way to do that is to find the sweet spot that enables you to sort of utilize all of that infrastructure you've laid in. When you do all of the concept work to optimize it between what have you got in the subsea, what have you got in the FPSO in terms of a deck you can add gas processing to? What's the limit on the gas export pipeline? You take all of that and optimize it. This is what you get.
Yeah, thanks for that. How should we think about FID for phase II, timing-wise?
Yeah. Again, we're working with BP on that at the moment, but I would anticipate FID to be 2023. Yeah.
Around the time of first gas.
Around the time of first gas of phase I.
Well, thanks for that.
Great. Thanks, Bob.
Our next question is from Nick Stefanou with RenCap. Please proceed with your question.
Hi, guys. It's Nick here. Thank you for taking my questions. I've got a couple on Tortue, if I may, and then a follow-up one on TEN. You've been talking about that free cash flow number of $150 million-$200 million per annum for Tortue phase I and II for a while. I was under the impression that that was under the old sort of design of the project, which was, I think like 6 million-7 million tons per annum. How can you make the same amount of cash at 5 million tons per annum? That's my first question. Second one is, could you maybe talk a bit about how that looks like the CapEx for the project was $650 million. Now it looks a bit higher, around $700 million. Could you maybe talk a bit around that and if there's any potential, maybe some cost overruns? Thank you.
No, thanks, Nick. I'll take the second question, then Neal can take the questions around the cash flows. Look, we were thinking around sort of 650-ish, something like that for the capital phase I. Clearly, the year has cost us some additional capital. There's no other way of describing that. You've clearly got an additional year of project execution. Whilst we've optimized the project to reduce the impact of that, there is a cost from the delay. I think we're clear about that, obviously the numbers we've represented today are our best estimate of that as we speak. With the project 50% complete. The risk of execution has gone down now, I think we've got a very credible timeline as well, to be able to deliver the project.
I don't feel that the schedule is under pressure, and therefore you've got the pressure on that capital number, Neal.
Yeah. Just on the free cash flow bit, the $150 million-$200 million free cash flow bit is for sort of our current working interest. In the past, I think maybe this is where you might be sort of mixing. We talked about $150 million from 10% of the project of the expanded 10 million ton scheme.
The numbers are similar, but we were talking about half the scope of the project at our current working interest versus a larger project at a lower working interest, and the numbers happen to be around the same.
Okay. I see. Just a quick follow-up. For TEN, I noticed that production was sequentially a bit low, not by much, but just a bit over 50,000 barrels per day. I was wondering, with Ntomme 9 coming on stream, what's the reason for that decline? I think it was on stream in August, right?
Yeah. No, look, the decline is ultimately around, we obviously had no drilling on the other reservoirs. Yeah. Enyenra being a big contributor to the overall TEN production level. We saw an uptick, then you're going to get some natural decline associated with Enyenra. Actually, reliability has been good, so the other fields continue to perform. Yeah, clearly Ntomme 9 offsets some of that. There will be ongoing declines because of the fact we've had no activity this year. We're obviously back to drilling next year, but no activity this year.
Okay. Thank you.
Great. Thanks.
Our next question is from James Hosie with Barclays. Please proceed with your question.
Hello there. Hi. Just two questions from me on the Tortue funding plan. First off, is the $100 million you're trying to get from the NOC refinancing, does that also transfer the risk associated with that money, or does the risk remain with Kosmos? Just on the $300 million gap, is one option for that refinancing your RBL to incorporate Tortue into it, or are you thinking of other routes for getting that cash?
Neal, why don't you take those two?
On the NOC financing, we've talked with the banks about a number of different structures, in terms of where does that risk ultimately sit. We haven't finalized that. Whether they need some backstop at the end of the day, we will finalize through the negotiations with the banks. What's clear is there's an appetite from the banks to support government projects in developing Africa. There's a good appetite in terms of pursuing that. On the M&S, the $300 million, we've left it open for a number of reasons, because there are a couple of different options that we have. I do think there are other options that may be more attractive as we go down that route, and have had discussions with a number of other interested parties.
T hat is an option, but it's one of a few that we're looking at.
Okay. Thank you.
Again, as a reminder, if anyone has any questions, you may press star one on your telephone keypad. Our next question is from Richard Tullis with Capital One. Please proceed with your question.
Hey, thanks. Good morning, Andy and Neal. Staying with the same theme on the remaining $300 million investment for 2021 through 2023 for Tortue Phase I, roughly what realized oil price could allow Kosmos to simply fund that development from cash flows? Is that still an option on the table, even at, say, a $45 oil price?
Richard, I'd say at $45, I think we could internally fund it out of cash flow. That said, I think we've been pretty clear, and as Andy just mentioned, our priority in terms of the free cash flow is to use it to repay the debt. We've said for a while, it's our plan and expectation to deliver a self-funded project. The FPSO sale- leaseback is step one of that. Like I said, there's a number of ongoing discussions to secure the last bit. While it's certainly possible to fund it out of free cash flow, even in a $45 world, not our intention at the moment.
Okay. Understood. Looking back at the planned refinancing with the National Oil Company loans, provide a quick overview of the mechanics there. What do you expect? Is the total balance going to increase by the roughly $100 million, and what would be the expected new term?
Basically, today we have a loan with both the governments of Mauritania, as does BP, to cover their share of the capital cost. The goal or the objective of financing would be transfer that interest and the liability to the banks, and sort of get Kosmos out of the middle. It's attractive competitive rates, I would say. The goal wouldn't be to make up a profit or any P&L on it. It would just be a pure sort of transfer of the economic interest, both on the interest side and the risk side.
Yeah. Very good. Thank you.
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