Kosmos Energy Ltd. Q3 FY2020 Earnings Call

Good day, everyone. Welcome to Kosmos Energy 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, 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 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 announcements, and SEC filings for more details. These documents are available on our website. At this time, I will turn the call over to Andy.

Thanks, Jamie, and good morning and afternoon to everyone. I'll start today's presentation with the highlights for the quarter before passing it 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 plan for this quality asset going forward. Neal will then cover the balance sheet. I'll conclude the presentation before opening up to Q&A. Turning to Slide 2; 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 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 NOC 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 one remains on track for first gas in the first half of 2023, coinciding with the time the LNG market is expected to time. The optimization of phase two, targeting an expansion to 5 million tons per annum, simplifies the project by leveraging existing infrastructure from phase one, 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. 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, Kosmos delivered solid operational performance in Q3. In Ghana, net production 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 facility was over 98% for Q3, and now over 95% for the year so far. At TEN, gross production of around 50,000 barrels of oil per day was in line with guidance. Facility uptime at TEN was 98% in Q3 and 99% for the year so far. For the full year, we still expect 10 cargoes to be delivered from Ghana. At 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 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. 2020 has seen one of the most active storm seasons in history, and as a result, our field experienced 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 four 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, where the results are 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'll take you through the financials for the quarter.

Thanks, Andy. Turning to Slide 4, 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 one. I'll now hand it back to Andy to give an update on activities in Mauritania and Senegal.

Thanks, Neal. 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, Kosmos, and 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 his recent annual energy forum, Wood Mackenzie presented two charts on the slide. From the trough in 2020, Wood Mackenzie expects a much tighter LNG market over the coming years, driven by growing global demand and the deferral or cancellation of higher-cost LNG projects. 2020 is seeing the lowest LNG supply growth since 2014, with only 5 million tons per annum and 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 FID in 2020, the first time in almost 20 years that has happened. As a result, Wood Mackenzie expects the supply-demand gap to open up around 2023, just as the Tortue project plans to lead the first gas and creating a positive backdrop for marketing the volumes associated with phase two. With a significantly enhanced project and improving LNG backdrop and a financing path established, we're more excited than ever about the project. Turning to Slide 6, which shows the continuous progress we've made on Phase one of the project over the quarter. As BP planned in its 3Q results call two weeks ago, the partnership is working very hard and very well on Tortue phase one, with activity and all four key workstreams now increasing after periods of lockdown during Q2 and Q3. 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. Turning to Slide 7 which shows the optimization of the phase two project. This slide, which also uses Wood Mackenzie's data, compares the breakeven cost of Tortue phase two delivered into Asia, alongside other LNG projects. Using our latest cost estimate, which incorporates a significant reduction in capital of the project, Tortue phase two sits to the far left of the chart, where the delivered cost into Asia is 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 two is targeting an expansion of the scale of the overall development to 5 million tons per annum, leveraging all major infrastructure from phase one. For example, phase two will utilize spare capacity in the subsea infrastructure in phase one. 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 two will be the most competitive Brownfield LNG expansion project globally. With the limited upstream capital requirements expected to be less than $1 billion gross, we expect to be able to finance our net share of the phase two development with phase one cash flows. Turning now to Slide 8. 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 seven times. Kosmos's net capital for the 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 that the back costs 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 next year. The SPV will take on the future capital obligations of the FPSO, which means another $160 million of Kosmos's 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's 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 turning discussions to secure this financing by mid-2021. Today, Kosmos's 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 Kosmos. With phases one and two of Tortue expected to generate $150 million to $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 seven times, which is why we're excited about moving the optimized project forward.

Turning now to Slide 9. At the end of Q3, we announced total liquidity of around $650 million. Since then, we've 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 bank suggesting their forward price deck. 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 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 Q4. We expect Q4 Mauritania and Senegal accrued CapEx to be flat with the third quarter. We've also closed the Gulf of Mexico facility in the third quarter, which refinanced the previous prepayments 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. 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. Kosmos has a high-quality portfolio of world-class conventional oil and gas assets, with strong ESG credentials. Our focus on offshore exploration, development, and production along the Atlantic margin has not changed. We have three production hubs in Ghana, in the Gulf of Mexico, and Equatorial Guinea, as well as the 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, brands 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 the 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 breakeven 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 phased 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 enhance the exploration portfolio with a focus on return. 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 build a hopper of IOX opportunities across Kosmos that we continue to enhance. 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 Neal just outlined, we have ample liquidity, no near-term debt maturities, and a business that is expected to generate cash and to reduce leverage. Thank you. And I'd now like to turn the call over to the operator to open the session for questions.

Our first question is from Charles Meade with Johnson Rice. Please go ahead 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'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, it seemed like one of the challenges you had to address is that, obviously, project finance would make sense for you. But it's not as clear that 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 the 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, 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 if they'd 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.

All right, we'll stay tuned on that. And then, one of the questions just to interpret your slot on the upper right on page eight. If you're putting this, it makes sense that you 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?

The way to think about this, Charles, is that we are actively engaged with BP regarding the FPSO sale and leaseback. As Neal mentioned, they will decide how they want to be involved. Currently, we are sitting with them in negotiations with the preferred buyer of the FPSO. For the final $300 million, we have several strategies to secure that, which will involve some direct investment. We are currently exploring various options to accomplish this, aiming to find the most competitive way to secure that financing.

Thanks for that added detail.

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

I have a couple of questions to discuss. First, regarding phasing, you mentioned a CapEx figure that seems to be significantly lower than some market estimates. I wanted to clarify whether this is your final estimate or if there might still be some adjustments to that figure. Additionally, about the direct investment for the remaining phase one funding, it seems like you might be considering a smaller farm-out to help cover the remaining CapEx. Do you sense that there could be more interest in acquiring a smaller stake in the program?

Thanks, David. I'd like to address phase two regarding capital. We've discussed the capital estimates and forecasted that Tortue phase one and capital first gas will be slightly over $4 billion. Without the FPSO, it falls to about $3 billion, which aligns with our previous discussions. Phase two is notable because it takes advantage of the pre-investment from phase one. We're utilizing the existing capacity in the subsea infrastructure instead of adding a new facility to increase gas throughput, which can be achieved with the current FPSO setup. There's no requirement for another gas export line from the FPSO to initial processing. We've chosen a target of 5 million tons per annum to optimize the use of that infrastructure. The collaboration with BP has been key in maximizing the next phase while minimizing capital expenditure. The additional capital needed for the upstream segment to increase by 2.5 million tons is currently estimated at just under a billion dollars. Transitioning to the current environment, sales-wise, it has been challenging as many companies lack the financial capacity to engage. However, this situation has prompted us to refine our approach with BP and develop the project further. It feels like we have the right project at the right time, and the efficiency of the next phase benefits from prior investments. We recently had to decide between selling part of the infrastructure for $320 million or a piece of the project. For our shareholders, the better choice was to sell the infrastructure instead. In the future, we may find opportunities to realize appropriate value through a sell-down, particularly if without FPSO financing, a smaller segment of the project becomes appealing. Currently, our focus is on ensuring timely financing, and I am confident in BP and the project's proper scale of 5 million tons per annum. We're well-positioned with an efficient project that leverages earlier investments.

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

No, it doesn't actually because you've still got some stuff to do; there will be an extra Brownfield project to put the additional gas processing on. So it doesn't all timewise 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 know, we've got work to do with BP to get all that sequencing done, and so on. But it's a much simpler project to execute, so that's why it has lower execution risk.

That's great. Thanks a lot.

And our next question is from Neil Mehta with Goldman Sachs. Please proceed with your question.

Thanks for all the incremental color this morning. The first question is on the US 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?

Thanks, Neil. 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, and 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 what does that mean for the Gulf of Mexico? I think the first thing I would say is that while 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 pound, 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 are carbon sinks, which store around 10 times the carbon of 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. So, I believe that 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, 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 that rhetoric after the election. Is there a risk that there's no new leasing on federal lands or waters? I think that remains an issue, but we've got more than five years of future drilling opportunities, and they're gone. So there's no immediate concern. So, I believe we've got a business that is competitive today and actually, in a sense, we'll be 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?

So, it's correct. And that's actually drilling, you know four prospects here, which is sort of probably more than we would anticipate actually.

Okay, great. And the follow-up question is just on your Brent breakevens; you talked about $35 a barrel? That's before growth CapEx. So 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 and then 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 outline what the free cash flow profile looks like at our oil deck?

Yes, good question. Look, I think it's incredibly important, the free cash flow above $35, for first target of paying down debt. And Neal will give you the numbers on sensitivity in a moment; the first call on capital but first call on cash flow. In terms of the growth opportunities, it will be focused on limited iOS projects; we have the first one of those in the Winterfell opportunity and that sort of near less than $10 million net to us. The most I could see it, and we would need to see quite a sort of positive oil price is sort of up to $50 million in gross projects. We've got plenty of competing projects for that at the moment. And, you've got to see really driving that capital allocation decision. So, phenomenal focus on the free cash flow generated paying down debt, and then it's going to be very limited, highlights opportunities; and I think it's sort of zero to $50 million would be the number that we'll be looking at there.

So to add on that, it's Neal. So around sort of $50 million will probably be the upper limit, at least in the short term on the iOS portfolio. But 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 into hedging etcetera, but we can generate a significant free cash flow from the base business in a $45-ish world.

Cool. Thanks, guys.

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 two. So if I understood correctly, phase one was about $4 billion, of which maybe a $1 billion must be FPSO. And you're saying phase two at slightly less than $1 billion? Is that net to Kosmos? Or is that gross for the whole expansion?

That's gross. So, let me just sort of talk you through the numbers Bob. So just slightly over $4 billion of which the FPSO is slightly over a $1 billion; so the rest of it the breakwater, which is a significant cost, right, which clearly, you're not billing on phase two, yes, the breakwater, the pipeline from the FPSO to the breakwater to the inshore processing, which we're not doing on phase two. So, phase two is ultimately, you know, the capital expand 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. So, if you think about it there is 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, 2.5 million tons per annum phase one adds another 2.5 million tons to get to the five. So it wasn't the 4 million ton per annum expansion that might have thought about?

Yes, exactly Bob. So what you've done is, and in essence, the work that we've done over the last six months is to say look, 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 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.

Thanks for that. How should we think about FID for phase two timing wise?

Yes, we're working with BP on that at the moment, but I would anticipate FID to be 2023.

So around the time of first gas?

Around the time of first gas of phase one.

Thanks for that.

And our next question is from Nikolas Stefanou with Renaissance Capital. Please proceed with your question.

Hi everyone, it's Nick here. I appreciate the opportunity to ask my questions. I have a couple regarding Tortue, and then a follow-up on TEN. You've mentioned that the free cash flow estimate of $150 million to $200 million per ton per year for Tortue is difficult to comprehend. My understanding was that this estimate was based on the previous project design, which I thought was around $6 million to $7 million tons per year. How is it feasible to generate the same level of cash flow at $5 million tons per year? That's my first question. For my second question, could you elaborate on how it might look at $700 million? Also, do you foresee any potential cost overruns? Thank you.

Yes, thanks I'll take the second question and then Neal will continue the questions around the cash flows. We were thinking around in sort of $630 or something like that for phase one of the capital phase one. Clearly the year has cost us some additional capital. You know, there's no other way of describing that. So you clearly got an additional year of project execution. And 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, as we speak, but with the project 50% complete, 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. I don't feel that the schedule is under pressure, and therefore you've got the pressure on that capital number. Neal?

Then just on the free cash flow bit, the $150 million 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 tonnes scheme. The numbers are similar, but you've reduced. 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. Just a quick follow-up. For TEN, that production was sequentially a bit low, and not by much, but in just a bit over 50,000 barrels per day. I was wondering, is it within 29 coming on stream, what's the reason about the decline? It's nothing that was on stream in August, right?

The decline is largely due to the absence of drilling on other reservoirs, which significantly impacts overall production levels. We observed a brief increase, but we will also experience natural declines related to NRA. On a positive note, the performance of the fields has been generally good. While nine offsets some of the decline, we will see ongoing reductions due to the lack of activity this year. We'll reassess for next year, but this year remains unchanged.

Thank you.

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

Hello, there. Hi. Just a couple of questions from me on the structure funding plan. First off is $100 million you're trying to get from the NSC financing because I also transfer and the rest of that money for the rest remain with Kosmos? Then just on the $300 million gap, is one option for that refinancing your RBL to incorporate for two years or are you thinking of other ways for getting that cash?

Neal, why don't you take those two?

Yes, sir. Regarding the NSC financing, we've discussed various structures with the banks concerning where the risk ultimately lies, but we haven't finalized whether they will require a backstop. We will determine that through negotiations with the banks. It's clear that the banks have a strong interest in supporting government projects in developing Africa, which is promising. As for the $300 million, we have kept it flexible for several reasons since we have multiple options available. We can integrate it into the RBL today, but I believe there may be more attractive alternatives as we explore this further. We've also engaged in discussions with other interested parties. That’s just one of the few options we are considering.

Okay, thank you.

Our next question is from Richard Tullis with Capital One. Please proceed with your question.

Thank you. Good morning, Andy and Neil. Standing with the same theme on the remaining $300 million investments for 2021 to 2023 for Phase 1, what will price realize the price could allow Kosmos to simply fund that development from cash flows? And is that still an option on the table, even at a $45 oil price?

Yes, Richard, I believe that at $45 we could potentially fund it through cash flow. However, as Andy mentioned, our priority with free cash flow is to use it to pay down debt. We have consistently stated that our goal is to deliver a self-funded project. The FPSO sale-leaseback is the first step in that process, and we are currently engaged in several discussions to secure the final pieces. While it's certainly feasible to fund it through free cash flow, even with a $45 oil price, that is not our current intention.

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 increased by roughly $100 million and what would be the expected new term?

Basically, today we have a loan with both the governments of Mauritania as well as BP to cover their share of the capital. The goal or the objective of financing would be to 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, 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 the economic interest both on the interest side and our self.

Very good, thank you.

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.