Kosmos Energy Ltd. (NYSE:KOS) Q2 2024 Earnings Call Transcript

Kosmos Energy Ltd. (NYSE:KOS) Q2 2024 Earnings Call Transcript August 5, 2024

Kosmos Energy Ltd. misses on earnings expectations. Reported EPS is $0.1245 EPS, expectations were $0.16.

Operator: Good day, everyone. Welcome to the Kosmos Energy’s Second Quarter 2024 Conference Call. As a reminder, today’s call is being recorded. At this time, let me turn the call over to Jamie Buckland, Vice President, Investor Relations at Kosmos Energy.

Jamie Buckland: Thank you, operator, and thanks to everyone for joining us today. This morning, we issued our second quarter 2024 earnings release. This release and the slide presentation to accompany today’s call are available on the investors page of our website. Joining me on the call today to go through the materials are Andy Inglis, Chairman and CEO; and Neal Shah, CFO. During today’s presentation, we will make forward-looking statements that refer to our estimates, plans and expectations. Actual results and outcomes could differ materially due to factors we note in this presentation and in our 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’ll turn the call over to Andy.

Andy Inglis: Thanks, Jamie, and good morning and afternoon to everyone. Thank you for joining us today for our second quarter results call. I’ll start today’s call by looking at the operational momentum we’re seeing across all our business units and the solid progress we’re making towards achieving our year-end goals. Neal will then walk you through the quarter’s financial results before I look ahead to the multiple catalysts we expect to deliver over the second half of the year. We’ll then open the call for Q&A. Starting on Slide 3. Two years ago, we announced a target to grow production by around 50%, driven largely by the delivery of three important projects, Jubilee Southeast in Ghana, Winterfell in the Gulf of Mexico, and GTA in Mauritania and Senegal.

We’re around halfway to achieving that target with the successful startup of Jubilee Southeast and Winterfell alongside production enhancement projects in the Gulf of Mexico, which I’ll talk about in more detail shortly. Through the end of the year, we expect the startup of the first phase of the GTA project and the infill drilling campaign in Equatorial Guinea to contribute towards our year-end production goal of around 90,000 barrels of oil equivalent per day. But we’re not growing production for growth’s sake. The growth is coming from high quality material projects with long reserve lives across both oil and gas. This rising production follows a multiyear investment cycle, with CapEx now expected to fall sharply as these projects are completed.

The increased production and lower capital should drive a meaningful free cash flow inflection in the business with free cash flow of around $100 million to $150 million per quarter once everything is fully up and running. That cash flow will be used initially to pay down debt to further strengthen the financial resilience of the company. We will also selectively invest in future growth, but this will be focused on high-graded projects developed at a cadence to fit within our targeted capital budget. Once the debt level approaches our near-term leverage target of sub 1.5 times, we’ll then look at shareholder returns alongside further debt paydown to achieve our longer-term target of closer to 1 times. It’s an exciting time for Kosmos as we continue to deliver the strategy our shareholders have invested in over the last few years.

Q&A Session

Turning to Slide 4, which looks at the quarter in more detail. In Ghana, the three-year drilling campaign came to an end during the second quarter with the final producer well and water injection well online at Jubilee. Gross Jubilee production in the quarter was around 87,000 barrels of oil per day. We have sustained high facility uptime with the Jubilee FPSO operating at around 99% during the quarter. However, production was lower quarter-on-quarter as one of the previously drilled producer wells J-69 underperformed expectations. When drilled, it encountered what we expected, but since coming online we have not seen the pressures required to maintain production levels from this individual well. In addition, in the second quarter, we also had some water injection issues with voidage replacement around 80% compared to the 100% target.

As I said in May, to achieve the planned levels of output from the field, we need high infrastructure reliability which we’ve achieved. We also need high levels of water injection, and we need the new wells to perform. Gross oil production is currently around 90,000 barrels of oil per day, with scope to increase as we address the water injection reliability. Given the underperformance of J-69, full year gross Jubilee production is now expected to be around 90,000 barrels of oil per day. With the current program now complete, the partnership will take a time-out to conduct a new 4D seismic survey starting in early 2025 after a gap of almost eight years since our previous 4D survey. This will help high-grade the well locations for the 2025/2026 drilling campaign.

I’ll talk more about the impact of new seismic technology and processing on the following slide, but its capabilities extend well beyond exploration with significant benefits of midlife assets like Jubilee, where we can enhance our understanding of the subsurface over time. We’ve only produced a little over half of the 2P reserves in Jubilee over the last 14 years, so our focus along with the operator is on maximizing recovery and ensuring we drill the best wells first. As we’ve said in the past, we believe the ultimate recovery from Jubilee will be around one billion barrels of oil equivalent and the new 4D survey will be important to deliver that goal and maximize our capital efficiency. On TEN, the field is performing slightly ahead of expectations with gross oil production of around 19,300 barrels of oil per day in the quarter, with the FPSO uptime of around 99%.

In Equatorial Guinea, gross production averaged around 24,000 barrels of oil per day, in line with expectations. Last month, a rig arrived in country to commence the drilling campaign. The partnership plans to drill and complete two infill wells with production expected early in the fourth quarter before the rig moves to the Akeng Deep ILX well with the result expected by year end. The first infill well has just been drilled with positive initial results, providing confidence in our ability to add around 3,000 barrels a day, net of additional oil in EG by year-end. In the US Gulf of Mexico, it’s been a busy period with the startup of multiple projects in the last two months. Winterfell was brought online in July, which I’ll talk about shortly.

We also successfully completed the Kodiak-3 well workover, which is performing ahead of expectations. The Odd Job subsea pump came online in late July with a meaningful increase in production from the field. Together, these projects have grown our current Gulf of Mexico production to a level of 20,000 barrels of oil equivalent. On Tiberius, our next ILX development where Kosmos is operator, we have ordered the long lead items and secured a rig with the project sanction expected later this year. We continue to make good progress and anticipate first oil around 18 months to 24 months after FID. Turning now to Slide 5, where I’ll spend some time talking about Winterfell and the impact modern seismic is having on growing the resource upside. As I mentioned on the previous side, the first two wells came online in early July, with the third expected online by the end of this quarter.

We’re ramping up those two wells and expect gross production from the first three wells to be around 20,000 barrels of oil equivalent per day. Two additional wells are planned in the first phase with drilling expected next year. We’re targeting around 100 million barrels of resource from these five wells, with further upside potential from adjacent prospectivity. The partnership has licensed a new ocean bottom node seismic data over the Winterfell area, which generates significantly enhanced imaging compared with conventional streamer technology. Placing nodes on the ocean floor results in much higher resolution images. On Winterfell, where it’s now calibrated with the development wells, the OBN is already helping the partnership plan the future well locations and gives us greater confidence on the resource potential of the area.

We use the same state-of-the-art seismic to deliver exploration success at Tiberius and believe wide application of this seismic technology with updated processing techniques can enhance the capital efficiency of our future drilling activities across the portfolio. We see similar opportunities to use OBN in a 4D application for mid-life fields like Jubilee. Winterfell is a prime example of why we acquired the Gulf of Mexico business back in 2018, a material exploration prospect near existing infrastructure with low F&D costs, which leads to a quick payback and attractive economics. Turning now to Slide 6. As the operator noted on its earnings call last week, the GTA project continues to make good progress with all the key pieces of infrastructure in place, with gas expected to flow soon.

As the slide shows, the FLNG vessel arrived earlier in the year has been moored to the hub terminal. The FPSO arrived on location in the second quarter and has now been moored to the ocean floor and the risers installed. On the Subsea workstream, mechanical completion for first gas is expected later this month. On the FLNG vessel, the operator plans to bring an LNG cargo to cool the vessel this month, which helps to accelerate the commissioning activities and ramp up to full rate. The FPSO is expected to be handed over to operations in September, with first gas expected shortly thereafter. First LNG production and cargo sales are expected in the fourth quarter. We look forward to updating the market with our progress over the coming weeks and months as we deliver this major milestone for the company.

Turning now to Slide 7, which looks at the portfolio choices beyond this year. Kosmos is differentiated as we have a deep portfolio comprised of high quality, [advantage] (ph) oil opportunities in Ghana, EG and the Gulf of Mexico, coupled with world scale gas opportunities across Senegal and Mauritania. This deep portfolio enables us to enhance quality through choice, high grading the activity set to pursue the highest value opportunities for our stakeholders. As we look at the hopper, there are a number of attractive investment opportunities for growth. We have a balance of oil and gas projects and a growing number of operated projects. Operatorship allows us to manage the pace of development and therefore spend, meaning we have greater ability to control our growth within the future capital framework we’ve laid out for the company.

We have large interest in two key projects, Tiberius and the Yakaar-Teranga. As we previously said, bringing in the right partners is critical to progress the projects and also manage our capital exposure as we look to de-lever the balance sheet. On both projects, we’ve had strong industry interest as we look to farm down our interest by project sanction. As we come to the end of this capital intensive phase of the company’s evolution with our key projects nearing completion, I want to reinforce an important message I made earlier in the year. We will selectively pursue the best growth opportunities within a disciplined capital framework, which will result in a more modest growth rate than we’ve seen over the past two years. I’ll now turn it over to Neal to take you through the financials.

Neal Shah: Thanks Andy. Turning to Slide 8, which looks at the second quarter in detail. Production for the quarter of 62,000 barrels of oil equivalent was up 7% year-on-year, but towards the bottom end of our guidance range, reflecting the lower Jubilee production and the Winterfell startup delay. Costs were largely in line with guidance, with operating costs for the producing assets coming in below guidance. DD&A, G&A and exploration expense all came in at the low end of guidance, helping the earnings beat versus consensus with the slightly higher tax expense reflecting higher realized prices. CapEx was lower than anticipated in the second quarter, largely due to the timing of accrued CapEx related to the GTA project. That lower CapEx combined with positive working capital led to a minor free cash flow outflow in the second quarter.

We expect that GTA CapEx to be recognize in the second quarter and the positive working capital to reverse later this year as well. Looking at 3Q and the full year more broadly, which can be seen in the guidance slide in the appendix, we have lowered our full year production guidance to 67,000 to 71,000 barrels of oil equivalent, reflecting the impacts of J-69 on Jubilee and the delay in Winterfell, as previously mentioned. With the reduction in Jubilee production guidance to approximately 90,000 barrels of oil per day gross, we expect to lift two fewer Ghana cargoes this year. This should be partially offset by an additional half cargo we now expect in Equatorial Guinea, as new production is added in the fourth quarter. We expect CapEx for the year to be around $750 million, which is in line with the guidance that we gave back in February and includes the restart of the EG drilling campaign which began in July.

On costs, we expect to come in at the lower end of the full year guidance range for DD&A, G&A and exploration expense with higher OpEx per barrel mainly a function of the lower production. With that, I’ll hand back to Andy to conclude today’s presentation.

Andy Inglis: Thanks, Neal. Turning now to Slide 9. It’s been a busy first half of the year and we’ve made a lot of progress. That operational momentum continues in the second half and we remain on track to exit the year at our targeted production rate of 90,000 barrels of oil equivalent per day. As the projects contributing to that year-end production target come online, we expect capital to fall sharply, leading to the free cash flow inflection point that enables the company to pay down debt and drive down leverage ahead of shareholder returns. Looking further out, we have a deep portfolio of high quality opportunities and we plan to pursue only the best projects with the right level of working interest at the right pace that allows us to operate within our capital framework. Thank you, and I’d now like to turn the call over to the operator to open the session for questions

Operator: [Operator Instructions] Our first questions come from the line of David Round with Stifel. Please proceed with your questions.

David Round: Great. Thanks for the presentation, guys. A couple on Jubilee please. Firstly, the J-69 well, does that result impact the long-term outlook for the field at all? And how can you ensure that this, I suppose, becomes an isolated well? Secondly, on voidage, you talked about it in the last set of results and identified it as the key point. Can you just elaborate, please, on the issues you face there? And again, any steps that you can take to improve the water injection going forward, please?

Andy Inglis: Yeah. Thanks, David. I think we’ll start off with the development well program. And I think it’s important to sort of step back. We’re at the end of a three-year program. We’ve drilled 18 wells actually in that three years. And we’ve drilled them safely, which is the most important thing and efficiently and ended the program slightly earlier than we’d anticipated. Clearly, with a program of that scale, you are going to learn as you go along and not every well will match expectations and J-69 has certainly had an impact on this year’s production level. But I think, again, as a piece of context as I said in my remarks, that three-year program was drilled on 4D seismic data that is essentially almost eight years old now.

And clearly, as we go through the process now of moving forward, technology has moved on massively with seismic both in terms of acquisition and processing. And we’ve just contracted actually to do a new 4D seismic, which will start at the beginning of the year. And then we’ll use that data to identify the candidates for the next set of wells. So, I’m confident that there will be a significant uplift in the data which will allow us to drill another high-quality set of development wells when we restart the program in ‘25. So I think we’re clear about what it is we need to do. And I think the sequencing now, bringing the current program to an end and shoot the seismic, have the data available, and then have the ability to leverage the very best wells first.

We’ll maintain our view of the future potential of the field. And again, as I said in my remarks, we’re just over half of the 2P in the first 14 years of production. There’s a huge amount of opportunity to play for. And ultimately, it is about doing it in a really capital-efficient way best wells first. And to do that, you need data which is current. And I think the new 4D will allow us to do that. And then there were three things we need to get right. Reliability needs to be high, which is great. It was 99% uptime in the second quarter. Voidage was a little lower than we’d anticipated. It’s just about the reliability of the gas turbines. The water injection system is going well. The gas injection and export is going well, and it’s about maintaining the uptime on the gas turbines.

So we had some — a little bit of unplanned maintenance on the gas turbines, everything’s now back in order, and we’re back at high levels of voidage replacement as we speak. And I think an opportunity to sort of catch up as we go through the year. So, I think that’s a little bit of background, David, I think, for you, hopefully, it will help on both of those issues.

David Round: Thanks, Andy. Very clear.

Andy Inglis: Great, thanks.

Operator: Thank you. Our next questions come from the line of Charles Meade with Johnson Rice. Please proceed with your questions.

Charles Meade: Good day, Andy, Neal and the rest of the Kosmos team. I want to pick up that Jubilee question, but maybe come at it from a different angle. The operator in mid-May said, hey we’re having some problems with this J-69, but there’s no change to our cargo forecast. So, I’m curious, what explains the delta? Is it your view versus theirs, or is it the benefit of another 2.5 months of production? Or what else might it — explain that delta?

Andy Inglis: Yeah, good question, Charles. So sort of step back, obviously, May versus August, we’ve got a couple of pieces of data. I think we’ve obviously got the actual production we’ve achieved in the second quarter, which, as I just said in a response to David’s question, there’s a little bit of impact to the — of the downtime on the voidage replacement. So, impact there. And then clearly, we’ve now been able to fully evaluate J-69 and its impact on the whole year. So we do have some new data. So we’ve incorporated that into our production forecast, which was obviously part of the commentary today. And then you’ve got to go and do the cargo math, which is all about the production allocation between cargo liftings for GNPC, Tullow and then ourselves.

When you run through all of that, our best view today is that there was a cargo right at the end of the year which moves out from December to January. In addition, another cargo has been lost. So our view today is, with that additional knowledge and then the sequencing of all the cargoes, one cargo definitely, a second cargo slipped from December into January, and then we’ve had an offset of an additional cargo coming from Equatorial Guinea. So sort of net-net, the real impact is sort of one lost cargo, one deferred from the end of December to the beginning of January, offset by half a cargo in EG.

Charles Meade: Got it. That’s helpful detail. And then a follow up on GTA. It’s exciting as these big pieces come together. Can you explain to us on the line, what is the significance of the cooldown cargo? I understand what purpose it serves, but can you explain where that will come in the process and if it’s going to be significantly the penultimate step or just how does that interact with the overall project startup?

Andy Inglis: Again, good question, Charles. Typically, as you’re well aware, you commission a gas facility with buyback of gas. It’s the safest way to do it because you’re using a sort of known source of gas. There’s no production upsets as you start the commissioning process. So, it allows us to have a much smoother start to that initial step to cool down the FLNG vessel before introducing sort of the high pressure gas that would come from the field. So, from an efficiency point of view and a safety point of view, it’s the right thing to do, but clearly, what it allows us to do is accelerate that pre commissioning process. So our objective is to have that cargo connected up this month — later this month, and then we can start that cooldown process.

So, as you sort of go through the steps as I talked about in my remarks, the first thing is to sort of the subsea mechanical completion to enable the gas to flow from the well through to the FPSO. We are on track to do that this quarter. The next step is clearly the finishing of all of the TEN, all the work by technique, to pre-commission, hand over to BP so they can take operational control of the FPSO. That, again, is targeted in September with first gas shortly thereafter. And in advance of that, you’ve enabled the cooldown of the LNG tanks to have occurred, which means, in essence as that gas is introduced from the FPSO, you’re into the process of making LNG, which clearly leads to the cargos in the fourth quarter. So that’s sort of how it all fits together.

And I think the cooldown cargo is an important step just to accelerate the process and allow us to do things in parallel rather than purely in sequence.

Charles Meade: That’s helpful detail. Appreciate it.

Andy Inglis: Great. Thanks, Charles.

Operator: Thank you. Our next questions come from the line of Bob Brackett with Bernstein Research. Please proceed with your questions.

Bob Brackett: Good morning. I’d like to talk about Tiberius a little bit. In the context of the right level of working interest, you currently have 50% of it. The discovery well, in theory, could be a future oil producer. It’s a six kilometer tieback to a host, and it’s, I would argue, strongly undervalued in terms of people looking at Kosmos. How do you balance the fact that the value that’s there against the desire to make sure you have the right capital program? And is it selling down, getting back from 50% to a third or less than that? And what happens if the market isn’t as good as the underlying asset value?

Andy Inglis: Great questions, Bob. So I think the first point is to make is, yeah, I think Tiberius is a really quality development. We’re pleased with the progress we’ve made in the quarter. We’ve got the long leads procured. We got the rig under contract working well with Oxy targeting sanction by the end of the year. So, I think that’s really positive steps forward. In terms of the working interests, we did take the opportunity, both ourselves and Oxy, actually to build up to 50%. We’re now going to sort of test the market. We think we’ve added value to it in the interim. The Gulf of Mexico, it’s a good market at the moment for quality projects. So we’re looking forward to getting some positive read-through of value from that process.

And then ultimately, we’ll make a decision on the level of farm-down that we do. It will be a proportion of the additional interest we picked up, Bob. And as you say, ultimately that process will be one where we’re looking to demonstrate value accretion from the original deal that we did. We want to ensure that we have a material stake in the field going forward. And ultimately, we do though want to deliver the free cash flow targets that we’ve made. Part of that is ensuring that we keep the capital budget in the right place. So, we will balance all of those and ultimately, as you say, we don’t want to do a deal where we’re eroding the ultimate value of the company. But I think we’ve got all of those levers to play with now, because ultimately, it’s a really good project and we’ve made progress on it.

And I think creating that alignment through with Oxy when Equinor left has been really good because we’ve managed to move the project forward in the right way. So decisions to be made, but I think we’ve got the right frame against which to make those judgments.

Bob Brackett: And a quick follow up, the concept for Tiberius, I don’t think you’ve discussed it at length, but it’s a subsea tieback to an existing host with one, two or three wells. Is that the way to think about it?

Neal Shah: Yeah. I mean, Bob, there’ll be multiple wells, at least initially. But the concept initially, we put the infrastructure in. Like you said, the original exploration well will become the first development well and then we’ll add incremental wells in the region over time. So yeah, it could grow up to four to five wells eventually, but we’ll get the infrastructure online and build it as a phased development as we’ve done in other projects as well.

Andy Inglis: Yes, it will be similar to the way we approach Winterfell, where again we’ve benefited from the development wells and the [calibration and the seismic development wells to be able] (ph) to pick the right next follow-on well. So it will be a progressive build of the production. And I think that’s a difference in the Gulf of Mexico today is that we have these hubs now where you’ve got the ability to invest for the future and grow and sustain the production. So, we have a discovered resource called Logan to the south of Tiberius, which can be part of that future development once we’ve got the infrastructure in place.

Bob Brackett: Very clear. Thank you.

Andy Inglis: Great. Thanks, Bob.

Operator: Thank you. Our next questions come from the line of Neil Mehta with Goldman Sachs. Please proceed with your questions.

Neil Mehta: Yeah, good morning, Andy and team. Just had a couple questions here on Tortue. What are the gating items between now and first LNG, and are there any critical path items, or you feel like it’s been largely de-risked? I recognize that BP gave us a little bit of color on this last week, but love it from your perspective too, Andy.

Andy Inglis: Yeah. Look, Neil, I think hopefully the answer I gave Charles was around showing how we’re integrating now and with a clear path to that first LNG. With a big project of this, there are key — there are four key work streams — the subsurface, the subsea, the FPSO, the FLNG. Hopefully from the remarks that both Murray made and that I’ve added to, you can see how those integrate together. So, there is a critical path. The subsea, we’re probably not on the critical path today. We have the ability to produce later this month, beginning the next month from the subsea, you have the FPSO then, gas through the FPSO, clear plan for the handover to BP operations. And then we’re accelerating, if you like, in parallel the ability then to directly start to produce LNG through the FLNG with the cooldown cargo that we’re bringing in.

So I think, I hope with additional commentary, you can see how that there’s a very clear integrated program now. And then clearly, each of the steps needs to be managed carefully and done in a very methodical way. But again, each day we’re progressing. There’s been a significant amount of work done on the FPSO since it was moored, and risers have been connected, the gas turbines have been run, see what electric are running, et cetera. So, all of the steps are being conducted in a very methodical way. But I think one of the real messages I wanted to talk about today was how it’s all integrated now with a very clear plan going forward.

Neil Mehta: Thank you, Andy. Yeah, definitely, next couple months will be important for that project and that kind of pivots to 2025. Assuming Tortue’s ramping and generating a lot of free cash flow, can you just talk about uses of cash in 2025? I think there’s a lot of investor focus on generating the cash and deleveraging. But what’s your perspective on ‘25?

Andy Inglis: Yeah, so, look, I’ll let Neal pick that up. And again, we’ve been clear on our capital guidance and the demand that’s required to invest in the base to sustain the production that we enter the year with. We’re clear about the growth projects and the allocation of capital to that. So within that frame of capital allocation, which enables us to proceed with a rate — the company will continue to grow, but obviously at a much more modest rate, how do we ensure that we deliver that free cash flow we’ve talked about and then what’s — how we’re going to use it. Yeah.

Neal Shah: Yeah, and so, Neil, the only piece I’d add on is, yeah, to Andy’s point, we’ve been clear about the capital inputs as we go production towards the end of this year, to exit around 90, it’ll be about sort of maintaining the base and then focusing selectively on those projects like Tiberius that we want to grow over time. And the rest of the free cash flow, we’ve been very clear with our investor base, will be focused on debt reduction. So from a free cash flow perspective, I see ‘25, the 100 to 150, depending on commodity prices will focus — will go to debt paydown.

Neil Mehta: Thank you, Neal.

Operator: [Operator Instructions] Our next questions come from the line of Mark Wilson with Jefferies. Please proceed with your questions.

Mark Wilson: Yeah, thank you. Clearly, the farm downs are part of your second half catalysts. Certainly, at Tiberius, it appears if that’s before FID. Could you talk, Andy, about the — how the — what the market looks like for farm downs now versus say, at the start of the year, certainly for gas at Yakaar-Teranga, but also for Tiberius? Thank you.

Andy Inglis: Yeah, good question Mark. I’d say still hasn’t changed, actually. I think the macro, when I look at the Gulf of Mexico today, the macro is pretty positive. I think people see it as a source of low cost, low carbon oil. Fewer players, fewer operators, actually a lot of non-operated, some private equity money coming in. And so people are looking to find a development like Tiberius. As I said in the answer to Bob’s question, that actually has upside in the long term. So we think it’s an attractive asset as a result. So I think, it’s sort of, you can say, well commodity prices are weaker, et-cetera. But I don’t think it’s ultimately changed people’s view of that. And in some senses, I’d say the macro there is probably stronger than it’s been for some time.

And again on the Yakaar-Teranga, it’s really — it’s about stepping back, I think. What’s interesting for me is actually the macro again is about actually some of our — some of the big NOCs in the world that have heavy oil weighting are the ones that are looking to do deals, to get access to long term gas. So you’re seeing a sequence of those deals and none of that’s going to change. I think that’s a permanent trend. And ultimately it’s a trend against a limited number of opportunities. So I think clearly there’s going to be volatility in prices. But I think the fundamental drivers that people are using to underpin their strategies have not changed. So I think we we’re obviously looking at very different buyer pools [in the government] (ph) towards Yakaar-Teranga.

But I don’t see there being a sort of difference between now versus the beginning of the year.

Mark Wilson: Okay, thank you for that. And then also, we’re getting now towards the — we’ve got visibility on the first gas at GTA Phase 1. Could you speak to what the partner view is on Phase 2, if there’s any — do you think there’s any change to that? Or is it a case of let’s get it on and see where we stand next year?

Andy Inglis: Yeah, again, good question, Mark. I think the — look, we’ve built the infrastructure to enable Phase 1. The Phase 2 expansion as a result is low cost. It is a brownfield modification of the FPSO to enable us to process more gas through the facility. And clearly, we’re not far away from getting the early production results from the initial development wells. So obviously, the conversation is about how do we now progress Phase 2 and do it in the most capital efficient way and in a timely fashion. And that’s also important to the government because — of both countries, both in Mauritania and Senegal, because the economics, clearly, of the next phase are superior to the initial phase. And therefore, for all parties, the expansion of the project is a win-win.

So that’s actually the conversation that’s ongoing at the moment with both of the NOCs and with the government is, how do we progress that project and with a real focus on capital efficiency, because the next phase has to be a rigorous project. The execution has to be in the most capital-efficient way that enables us to take the best advantage of the infrastructure that we built in. So I think it’s a good reminder, actually, Mark, of sort of the next phase. We need to finish Phase 1 and get it on. And we’re not there yet, but we’re very close. And then of course the conversation naturally then is to how do we optimize everything that we put in and get to the next phase, which is clearly a very good project? So, yeah, we’re not waiting, and those conversations are occurring within the partnership.

But first gas is clearly a step on that journey.

Mark Wilson: Okay, good. Thank you very much.

Andy Inglis: Thank you.

Operator: Thank you. 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.