Kosmos Energy Ltd.

Good day, everyone. Welcome to Cosmos 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 Rutland, Vice President of Investment Relations at Cosmos Energy.

Thank you, Operator, and 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 Ingalls, Chairman and CEO, and Neil Shah, CFO. During today's presentation, we will make forward-looking statements that refer to our estimates, plans, and expectations. Actual results and outcomes could differ materially due to factors we note in this presentation and in our UK and SEC filings. Please refer to our annual report stock exchange announcement, and SEC filings for more details. These documents are available on our website. And at this time, I will turn the call over to Andy.

Thanks, Jamie, and good morning and afternoon to everyone. I'll start today's presentation with the highlights for the quarter before passing you over to Neil 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. Neil 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. Cosmos 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 actual 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 to 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 optimise the Tall Tube 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 optimisation of Phase 2, targeting an expansion to 5 million tonnes 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. And 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 3. As I mentioned on the previous slide, Cosmos 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 10, gross production of around 50,000 barrels of oil per day was in line with guidance. Facility uptime at 10 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 4.5 cargoes to be delivered from Egypt. 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. 2020 has seen one of the most active storm seasons in history, and as a result, 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 and initial results have been positive. We also expect to begin the Kodiak completion this month and 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 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 Cosmos to be resilient in a low-price environment. With that, I'll hand over to Neil 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. So 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 3Q as compared with 2Q. This was due to a combination of higher oil prices, but also the normalization of the wide differentials we saw in 2Q. 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. 3Q was 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 3Q, 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 Tour 2 Phase 1. I'll now hand it back to Andy to give an update on activities in Mauritania and Senegal.

Thanks, Neil. Turning to slide 5. I'd like to start with the progress made on the Tortue project this year. Over the past six months, the partnership of BP Cosmos 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 US and internationally. In its recent annual Energy Forum, Wood Mackenzie presented the two charts on this slide. From the trough in 2020, Wood Mack 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 5 million tonnes 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 FIDs 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 2. With a significantly enhanced project, an improving LNG backdrop and a financing path established, were more excited than ever about the project. Turn to slide six, which shows the continuous progress we've made on phase one of the project over the quarter. As BP flagged in its 3Q results call two weeks ago, the partnership is working very, very hard and very well on 2Q phase one. With activity on all four key work screens now increasing, after periods of lockdown during 2Q and 3Q. At the end of the year, phase one of the project is expected to be around 50% complete, with first gas on track for the first half of 2023. Turn to slide seven, which shows the optimisation of the phase two project. This slide, which also uses wood mag data, compares the breakeven cost of Torchy phase two delivered into Asia alongside other LNG projects. Using our latest cost estimate, which incorporates a significant reduction in capital of the project, Torchy Phase 2 sits at the far left of the chart, with a delivered cost into Asia of just over $4 per MM BTU, competing very favourably with other expansion projects in Woodmax analysis. Shipping into Europe has an even lower delivered cost, further demonstrating the competitiveness of the project. The optimization of Phase 2 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 1. For example, Phase 2 will utilize spare capacity in the subsea infrastructure in Phase 1. The processing capacity of the FPSO will be expanded without acquiring 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 2 will be the most competitive brownfield LNG expansion project globally, with a limited upstream capital requirement expected to be less than $1 billion gross to first gas. we expect to be able to finance our net share of the Phase 2 development largely out of Phase 1 cash flows. Turning now to Slide 8. As I mentioned, we've established a financing path for a self-funded project that allows Cosmos to retain its current share of the project, which, when built out, can deliver an expected return on remaining investment of approximately seven times. Cosmos' 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 8. 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 Cosmos. BP and Cosmos 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 Cosmos' future capital obligations will be transferred to and funded by the SPV. Cosmos also intends to refinance our national oil company loan with commercial banks in 2021, which is expected to see around $100 million return to Cosmos. The combination of these two activities is expected to fund Cosmos' 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 Senacol. Cosmos is currently in discussions to secure this financing by mid-2021. Today, Cosmos' development capex on the project has been funded by the BP Development Carry, and we expect the forward investment post-FPSO financing to be around $400 million net to Cosmos. We've faced one and two torches expected to generate $150 to $200 million per year net to Cosmos at a $5.50 gas price. The optimized project is expected to deliver a return on investment of approximately seven times, which is why we're excited about moving the optimized project forward. With that, I'll now hand back to Neil to run through the balance sheet and liquidity.

Turning now to slide nine, At the end of 3Q, 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 to $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 4Q. We expect 4Q 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, Neil, and 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. Cosmos 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 Exxon Guinea, as well as a world-scale LMG 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 returns. 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 showed, 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 Torchy 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 generated oil assets in the portfolio today. On exploration, we continue to hydrate the exploration portfolio with a focus on returns. Our acquisitions in actual 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 Cosmos that we continue to high-grade. Success in exploration comes from having quality through choice. This means prioritizing proven bases, where we have a deep technical understanding, a large resource portfolio, and can leverage infrastructure. And finally, we have a solid balance sheet to execute our plan. As Neil 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, and 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'd like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star 2 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 start key. One moment, please, while we poll for questions. Our first question is from Charles Meade with Johnson Wright. Please proceed with your question.

Good morning, Andy, or afternoon as it may be, and to Neil 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 advance would make sense for you, but it's not as clear that it would make sense for your partner, BP. So I'm curious, should we be thinking about this, is 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?

Neil, why don't you pick that up?

Yes, I think Charles is right. I think that 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. And so 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. And then... And then one other question just to interpret your slide on the upper right on page 8. If you're putting this – 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. But is the right way to interpret this? Is that remaining $300 million, that's all the other pieces like the subsea, FLNG, and breakwater?

Now, I think the way to think about it, Charles, is to think about it that we're working and engaged with Biddy Piddy on the FPSO sale and lease back. And as Neil said, you know, they can choose how they participate in it, yeah? But, you know, clearly we're sitting alongside them at the moment in the negotiations with the preferred buyer of the FPSO. When it comes to the final $300 million, we have choices in which the ways in which we would actually secure that. It will be through some direct investment, and we're looking at various options today as to how we do that, and clearly what we're looking to do is to find the most competitive way to secure that financing. Got it. Thanks for that added detail. Great. Thanks, Charles.

And our next question is from David Round with BMO Capital Markets. Please proceed with your question.

I've just got a couple, both on talk two and similar themes. First on phase two, can I just clarify, you know, 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 lockdown and lockdown and you considered it sort of a final estimate or was there a bit of movement still to be expected in that number? And then just on the direct investment for the balance of phase one funding, it sounds like you're leaving the door open for potentially a smaller farmhouse to potentially cover the balance of the capital. Do you get the sense that there might be more appetite for a smaller stake in the project?

All right. Thanks, David. Yeah. Let me just sort of... I'll take the Phase 2 one first on the capital, yeah. So if you sort of talk through, you know, the capital estimates, yeah? You know, if you look to the first tortuous Phase 1 and capital to first gas, you know, we forecast that at, you know, slightly over $4 billion, yeah? So if you... If you take out the FPSO, it gets around to around $3 billion to the first gap, which is sort of consistent with the numbers we've talked through. What's interesting about phase two, though, is that it leverages all the pre-investment that's gone into phase one. And 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 nearshore processing. And actually we picked a sweet spot of 5 million tonnes per annum because it optimises the use of that infrastructure. And 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 utilising the infrastructure and therefore the minimum amount of capex. So that's why the capex is so low. The capex, to add that additional 2.5 million tonnes for the upstream piece of it is, as I said in my remarks, slightly less than a billion dollars and that's our current view. As I move on to the next question of the current environment, I would say that from a sales perspective, the current environment has been tough. There aren't many companies that have got the balance sheet today to be able to participate. But by the way, the current environment has allowed us to really sharpen the pencil with BP to come up with the right next phase. And I'm genuinely excited about the way in which we've managed to create the right project now. And as we sort of say on the slide, it's the right project at the right time. And 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. You sell a piece of the infrastructure for $320 million or 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. Now, 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. And I think as you rightly say, with FBSO financing in place, a smaller piece of the project will be attractive. But 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. And, you know, 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. So, you know, we've got a good project now.

Okay, that's very clear. Can I just ask a really quick follow-up? Presumably this potentially really compresses the build timetable as well for Phase 2, does it?

No, it doesn't actually because, you know, you've still got some stuff to do, right? You know, there will be, you know, a brownfield project to put the additional gas processing on. So it doesn't all sort of, you know, time-wise shrink. But it does make it a simpler project. So I'd say the execution risk has gone down. The timeline is probably typical of what you'd expect. So we've got work to do with BP to get all of that sequencing done and so on. But it's a much simpler project to execute. So therefore, it has lower execution risk.

That's great. Thanks a lot.

All right.

Thanks, David. And our next question is from Neil Metro 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? And as we size up the value of that business, how are you thinking about the moving pieces, particularly around federal leases?

Yeah, thanks, Neil. Look, you know, Elections and political transitions are not something new for Cosmos or for our industry. We live 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. And 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. So if you sort of, 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 US. I think the same thing is that we've clearly made a strong commitment to the energy transition and we're targeting carbon neutrality in our scope one and scope two by 2030. That will involve mitigation measures. And we've got some really interesting projects on the Gulf Coast. These are blue carbon projects focused on wetland restoration. And actually they have carbon sinks which store around 10 times the carbon of a terrestrial tropical forest. So I think the point there is to say that we believe we can be a solution to a problem rather than be an impediment. And 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. So actually, 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. So yes, is there a risk that there's no new leasing on federal lands or waters? I think that that remains an issue. The problem thing for us is we've built a hopper of more than five years of future drilling opportunities in the GOMs. So there's no immediate concern. So, you know, I believe we've got a business which is competitive today and actually, in a sense, will be even more competitive going forward because of the nature of the assets and the way in which we're conducting our business.

And just to clarify, you guys still have five years of drilling opportunity without requiring incremental federal lease, right?

Correct, yeah. And that's actually drilling, you know, four prospects a year, yeah, which is sort of more, you know, probably more than we would anticipate, actually.

Okay, great. And the follow-up question is just on your Brent break-evens. You talk about $35 a barrel. That's before growth capex. So how do you think about, let's call it over the next three years, you know, the level at which you cover your free cash flow sustaining plus growth capex and how that evolves over time? And then this might be a question for Neil. 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 that the free cash flow above $35 first targets are paying down debt. Neil will give you the numbers on 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 windfell opportunity, and that's sort of near less than $10 million net to us. The most I could see, and we would need to see quite a 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, and you're going to see us really driving that capital allocation decision. Phenomenal focus on the free cash flow, generate pain down there, and then it's going to be very limited ILX opportunities. And I think it's sort of zero to 50 would be the number that we'd be looking at there.

Yeah. Yeah. So to add on that, Neil, yeah. So around sort of 50 million would probably be the upper limit, at least in the short term on the ILX portfolio. Yeah. as you can imagine, given our exposure to oil prices, we're pretty levered. And 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. Now, there's some sort of offset to hedging, et cetera, but we can generate a significant amount of free cash flow from the base business in a $45-ish world.

Okay. Cool. Thanks, guys.

Right.

Thanks.

And our next question is from Bob Brackett with Bernstein Research. Please proceed with your question.

Thank you. I had a clarification question on Phase 2. So if I understood correctly, Phase 1 was about $4 billion, of which maybe $1 billion was the FPSO And you're saying phase two at slightly less than $1 billion. Is that net to Cosmos or is that gross for the whole expansion?

That's gross. So, you know, let me just sort of talk you through the numbers, Bob. So, you know, just slightly over $4 billion. So, you know, of which the FBSO is slightly over $1 billion. So the rest of it, the breakwater, which is a significant cost, which clearly you're not doing on phase two. The pipeline from the FPSO to the breakwater, to the inshore processing, which you're not doing on phase two. So phase two is ultimately, the capex spend is for The expansion of the gas processing, which is a brownfield project on the FESO. There's limited build-out of the subsea because that's got capacity. And then you're drilling some incremental wells. So if you think about it, there is a significant capital efficiency by utilizing all of that infrastructure that you put into phase one.

And to be clear, that makes a lot of sense. And this expansion takes you from, say, two and a half million tons per annum phase one, adds another two and a half million tons to get to the five. So it wasn't the four million ton per annum expansion that might have been thought about.

Yeah, exactly, Bob. Yeah. So what you've done is, you know, in essence, the work that we've done over the last six months is to say, look, you know, how did you get the best project? for the expansion. And the obvious way to do that is to find the sweet spot that enables you to sort of utilize all of that infrastructure you laid in. And when you do all of the concept work to optimize it between what have you got in the subsidy, 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.

Thanks for that. And how should we think about FID for Phase 2, timing-wise?

Yeah, you know, and again, you know, we're working with BP on that at the moment. But I would anticipate, you know, FID to be 2023, yeah? So around the time of first gas. Around the time of first gas of Phase 1, yeah. Well, thanks for that. Great. Thanks, Paul.

And our next question is from Nick Stefano 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 TOR2. So you've been talking about the pre-cash flow number of 150 to 200 million per round for TOR2. is one and two for a while. But I was under the impression that that was under the old design of the project, which was, I think, like six, seven million per annum. How can you make the same amount of cash at five million per annum? That's my first question. Second one is, could you maybe talk a bit about how that looks like the carpet 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 you see any potential, maybe some like cost overruns? Thank you.

Yeah, thanks, Nir. I'll take the second question and then Nir can take the question around the cash flows. Yeah, look, we were thinking around sort of 650 or something like that for the phase one of the capital phase one. 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. So I think we're clear about that, and obviously the numbers we've represented today are our best estimate of that as we speak. But with the project 50% complete, yeah? So the risk of execution has gone down now, and I think we've got a very credible timeline as well to be able to deliver the project. So I don't feel that the schedule is under pressure. and therefore you've got the pressure on that capital number. Neil?

Yeah, and then just on the free cash flow bit, the $150 to $200 million free cash flow bit is for sort of our current working interest. In the past, and 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. And so the numbers are similar, but you've reduced, you know, we're 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. And just a quick follow-up. For 10, I noticed that production was sequentially a bit low, not by much, but... just a bit over 50,000 bars per day. And I was wondering, is it, you know, with the Tommy 9 coming on stream, what's the reason of that decline? You know, I think the world was on stream in August, right?

Yeah, no, look, you know, the decline is ultimately around, you know, no, we've obviously had no drilling on the other reservoirs yet, so any error being a big contributor to the to, you know, the overall 10 production level. So you are seeing some, you know, we saw an uptick and then you're going to get some natural decline associated with the, with any Enro. And then, you know, but, you know, and actually reliability has been good. So, you know, the fields continue to perform. So, yeah, clearly Antomi 9 offset some of that, but there will be ongoing decline because of the fact we've had no activity this year. We're obviously about to join next year, but no activity this year.

Okay. Thank you.

Great. Thanks.

And our next question is from James Posey with Barclays. Please proceed with your question.

Hello there. Hi. Just a couple of questions from me on the Torturi funding plan. First off, is the $100 million you're trying to get from the NLC refinancing, does that also transfer the risk associated with that money, or does the risk remain with Cosmos? And then just on the $300 million gap, is one option for that refinancing your RBL to incorporate Torturi into it, or are you thinking of other routes to getting that cash?

Yeah, Neil, why don't you take those two?

Yeah, so on the NOC financing, we talked with the banks about a number of different structures in terms of where does that risk ultimately sit. And so we haven't finalized that, whether they need some backstop at the end of the day. We will finalize through sort of the negotiations with the banks. But what's clear is sort of there's an appetite from the banks to support government projects in developing Africa. So there's good appetite in terms of pursuing that. And then on the MS, the $300 million, we've left it sort of open for a number of reasons because there are a couple of different options that we have. We do have the ability to put it within the RBL today. 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. And so, yeah, that is an option, but it's one of the few that we're looking at.

Okay. Thank you.

And again, as a reminder, if anyone has any questions, you may press star one on your telephone keypad. Our next question is from Richard Tulis with Capital One. Please proceed with your question. Hey, thanks.

Good morning, Andy and Neil. You know, you stand with the same theme on the remaining $300 million investment for 2021 through 23 for phase one. Roughly, what oil price realized oil price could allow Cosmos to simply fund that development from cash flows, and is that still an option on the table, even at, say, a $45 oil price?

Yes, Richard, I'd say at $45, I think we could internally fund it out of cash flow. But 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. And 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, and like I said, there's a number of ongoing discussions to secure the last bit. And so while it's certainly possible to fund it out of free cash flow, even in a $45 world, it's not our intention at the moment.

Okay, understood. Okay. Looking back at the refinancing, 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 roughly $100 million, and what would be the expected new term?

Today we have a loan with both the governments of Mauritania, as does BP, to cover their share of the capital costs. The goal, the objective of financing would be transfer that interest and the liability to the banks and sort of get Cosmos out of the middle. And so it's attractive, you know, competitive rates, I would say. And so we do – but the goal wouldn't be to make a profit or any P&L on it. It would just be a pure sort of transfer of the economic – both on the interest side and the risk side.

Very good. Thank you.

And since there are no further questions at this time, I would like to bring the call to a close. Thanks to everyone joining today. You may disconnect your lines at this time, and thank you for your participation.