Kosmos Energy - Earnings Call - Q3 2019

Transcript

Speaker 0

Greetings. Welcome to Kosmos Energy Third Quarter twenty nineteen Earnings Conference Call. At this time, all participants are in a listen only mode. A question and answer session will follow the formal presentation. Please note this conference is being recorded.

I will now turn the conference over to your host, Jamie Buckland, Vice President, Investor Relations. Mr. Buckland, you may begin.

Speaker 1

Thank you, operator, and thanks to you all for joining us today. This morning, we issued our third quarter earnings release and a slide presentation to accompany today's call. Both materials are available on the Investors page of the cosmosenergy.com website, and we anticipate filing our 10 Q for the quarter with the SEC later today. Joining me on the call today to go through that material are Andy Ingalls, Chairman and Chief Executive Officer and Tom Chambers, Chief Financial Officer. Before we get started, I'd like to mention that this conference call includes certain forward looking statements based on our current expectations.

The risks associated with forward looking statements have been outlined in the earnings release and in our SEC filings. We may also refer to certain non GAAP financial measures in our discussion. Management believes such measures are important in looking at the company's historical and future performance, and these are commonly referred to industry metrics. These measures are provided in addition to and should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP and included in our SEC filings. At this time, I'll turn the call over to Andy.

Speaker 2

Thanks, Jamie, and good morning, everyone. I'd like to start the call by reinforcing the key characteristics that define Kosmos' distinctive investment proposition. Kosmos generates cash. We have a portfolio rich in value accretive catalysts, and we have a strong balance sheet that underpins our strategy. These themes are consistent with those we set out at our Capital Markets Day in February, and I'd like to go through them in more detail.

First, Kosmos has a portfolio that delivers cash. In the third quarter, we generated approximately $70,000,000 of free cash flow and we remain on track to deliver over $200,000,000 in 2019 at current prices, our third year in a row of positive free cash flow. For context, in 2019, this represents a free cash flow yield around 10, which continues to be very competitive compared with other E and P companies and indeed other sectors. Second, our Infrastructure led Exploration or ILX program is working. Today, we're pleased to announce our first success in Equatorial Guinea alongside the two ILX discoveries in the GOM since Kosmos acquired DGE last year, both on production this year, we have now made three discoveries from four ILX wells in total.

With our results this morning, we announced that the test of the Moneypenny prospect was unsuccessful. The well, which was targeting net resources of around 9,000,000 barrels oil equivalent was designed as an inexpensive exploration tail of the odd job development well and cost around $3,500,000 net to Kosmos. We have two more near term ILX wells in the GOM. We are currently drilling Resolution and Will Spud oilfield in December. These are the largest ILS prospects in the 2019 drilling campaign and both could be transformational for our Gone business in the event of success.

Third, we have demonstrated with the recently announced Orca discovery that Kosmos has a focused high impact exploration program. We believe the Orca field has an estimated 13 Tcf of gas in place and the well has helped to derisk around 50 Tcf in the Boralla area. Orca is the largest deepwater hydrocarbon discovery in the world so far this year. Fourth, with the recent success of Orca plus the significant appraisal success we've had at Yaka and Tortue this year, the total resource estimate for the Mauritania Senegal Basin has increased the top end of the 50 to 100 Tcf gas in place range. As a result of these major resource additions, we have extended the sell down process into 2020 to allow the buyer pool more time to evaluate the new data.

And finally, our conservative approach to managing the balance sheet has not changed. We continue to use free cash flow to fund the company's dividend and pay down debt. We expect to end the year with leverage of around 1.8 times. Turning to Slide three, I'd now like to discuss the third quarter in more detail. As mentioned on the previous slide, Kosmos generated $70,000,000 of free cash in 3Q.

CapEx for the quarter was in line with expectations and full year CapEx remains within the targeted range. With the free cash generated, we paid off our revolving credit facility and we will pay a dividend of $0.45 for the quarter. Production for 3Q was flat versus 2Q taking out the impact of Hurricane Barry, which resulted in around 1,500 barrels oil equivalent per day of lost production for the quarter. It was also slightly negatively impacted by unplanned downtime at Sabre, which is partially offset by the successful ESP program at Okume with five ESPs now completed. We expect 4Q to be flat versus 3Q for the company due to deferral by the operator of the gas enhancement work on Jubilee to the first quarter of twenty twenty.

As a result, for the full year 2019, we expect production to be around 67,000 barrels oil equivalent per day with lower than expected volumes in Ghana, partially offset by outperformance in the Gulf Of Mexico. Our LX assets continue to make strong progress. In Equatorial Guinea, we had success with the S5 well, more on that in a moment. And in the Gulf Of Mexico, we had first oil from Gladden Deep. In Mauritania and Senegal, we continue to make excellent progress.

Last week, we announced the Orca-one discovery and we also announced the Yakaar 2 appraisal well result during the quarter, which proved up the southern extension of the field and supports the Yakaar Teranga LNG hub and a first phase domestic gas project. And finally, at Tortue, we had a successful result with the GTE A1 appraisal well, which expands the Tortue resource potential. The project continues to make good progress with the Phase one development around 15% complete at quarter end, which should rise to around 25% by year end. Turning to Slide four, as I mentioned in my opening remarks, our ILX program is working. On this slide, I'd like to focus on the progress we've made in the Gulf Of Mexico since we acquired DG twelve months ago.

We drilled three exploration wells and had two discoveries with Nearly Headless Nick and Gladden Deep. The Nearly Headless Nick and Gladden Deep discoveries, while small, demonstrate the rapid development timelines for these ILX tiebacks. Glad indeed came online within four months of discovery and nearly headless Nick expected online in December, a fifteen month development. It's these short development times that result in high returns and quick paybacks for these projects. Looking at the right side of the slide, we are currently drilling Resolution and we expect to spud the old field prospect in December.

These prospects are potentially much larger and could be transformational for our Gulf Of Mexico business. To use a baseball analogy and apologies to my fellow Astro fans on the line, our ILX portfolio in the GOM offers low risk singles and doubles, which will replace the reserves that we produced during the year. We complement that with larger prospects that can deliver the home run catalysts if successful. Turning to Slide five, which looks at our ILX program next to Guinea. This morning, we announced success with our initial ILX ILX portfolio well in EG.

This was the first well to be drilled on modern three d seismic, improved our concept around the potential of the underexplored Ria Muni Basin. The seismic for the S5 area was fast tracked and the well targeted the heart of a Santonian channel, whereas previous wells were drilled on what we believe was the edge of the channel. The well encountered approximately 39 meters of net oil pay with better reservoir development than any of the previous wells drilled in the area. From initiating logging data, it looks like the oil is high quality than we have at Sabre and Okume and the well could flow at an initial rate of over 10,000 barrels of oil per day, which would be a material increment to the current Sabre Okume production. The field is within 20 kilometers of the Sabre FPSO, which puts it well within tieback range.

We're now doing the work to establish the scale of the Skibbard resource and evaluate the optimum development solution to tie it back into the existing infrastructure. Work is also now underway to identify additional low risk tieback prospects around the existing infrastructure. Final volumes from the 2018 seismic are expected to be delivered in early twenty twenty, allowing for the maturation of prospects for the next drilling campaign. Slide six shows the considerable progress we made since taking the final investment decision on Tortue less than a year ago. Through the successful GTA one appraisal well, we expanded our resource base at Greater Tortue Ahmim and we expect to use this well as a future producer.

Beyond appraisal drilling, as you can see from the table at the bottom and images on the right, we've made considerable progress on Phase one of the project since FID. Key work streams are progressing well with the FLNG vessel in particular almost 25% done. We expect the overall project to be approximately 25% finished by the end of the year. Our estimate for first gas for Tortue remains the first half of twenty twenty two. Turning to Slide 7, our appraisal well at Yakar-two confirmed the southern extension of the field.

And as you can see on the right, this test demonstrated how laterally extensive the field is. Combined with Taranga, we now have the resource required to underpin an LNG hub in Senegal, which will be developed using a phased approach with a domestic gas leading to an LNG export project. Slide eight shows the technical highlights of the Orca 1 discovery we announced last week. We believe the Orca field has 13 Tcf of gas initially in place in thick, excellent quality Albion reservoirs, as can be seen from the log data on the left of the slide. The discovery continues our 100% track record on the inboard trend and demonstrates the ability of the high quality calibrated ABO tool to identify gas in quality reservoirs.

The well, which was drilled 7.5 kilometers off structure confirmed our predrill expectation that both structural and stratigraphic traps are present and working. Turning to Slide nine, Orca is Kosmos' ninth discovery in the Mauritania Senegal Basin and the largest deepwater hydrocarbon discovery in the world so far in 2019. The well was drilled into a previously untested Albion play and encountered 36 meters of net pay in excellent quality reservoirs. Together with Marsuin, we believe we now have the risk up to 50 Tcf of gas in place in Mauritania alone, more than enough gas to underpin a standalone LNG hub in Mauritania. There is also additional upside potential in an untested Aptian play and we remain very excited about this area.

So turning to the final slide, one that we presented at the Capital Markets Day in February. At the time, we estimated that Mauritania Senegal had around 50 Tcf of gas in place with upside potential to double that in the event of successful exploration and appraisal campaign this year. We have done that with success at GTA 1, Yakar 2 and Orca 1. We've increased the resource base, the top end of the range to around 100 Tcf across the basin, providing sufficient resource to underpin three LNG hubs totaling 30,000,000 tons per annum of capacity. With these significant resource additions through 2019, we've extended the sell down process into 2020 to allow the buyer pool more time to evaluate the new data.

So to summarize today's presentation, Kosmos continues to be highly cash generative. We have an ILX program that delivers high return, short cycle growth that's working in EG and the GUM. We've doubled the size of our resource base in Mauritania and Senegal through successful exploration and appraisal in 2019. And we have a strong balance sheet that underpins the strategy. Thank you.

And I'd now like to turn the call over to the operator to open the session for questions.

Speaker 0

At this time, we will be conducting a question and answer session. Our first question is from Al Stanton, RBC. Please proceed with your question.

Speaker 3

Yes. Good evening, guys. Just I appreciate you don't always give guidance on what's going on in the data rooms and the various discussions you're having with potential buyers. But I think historically, we always assumed there would be one buyer focused on Tortue with additional discoveries being sort of nice to have. But I'm wondering now whether there's any possibility you might be looking for two buyers in terms of one for Mauritania and one for Senegal?

Speaker 2

Yes. Hi, Al. Yes, thanks. I think it's a great question and sort of go back to when we kicked off the process in February. We had a total resource across Senegal and Mauritania of around 50 Tcf with a lot of concentration at the time on Tortue.

Clearly through the year, we've had success with the wells, as I said in my remarks, GTA 1, the Yaka-two and Orca. And we now have a resource, which we believe is at the top end of that 50 to 100 TCF range. So we want to ensure that the potential buyers do have time to analyze the new data and better understand the assets. And I think as you point out, we now have three very distinct assets in Mauritania and Senegal and they all have distinct attributes. Greater Tortue is a project where the first phase is being FID.

We have gas, first gas two, two point five years away. The resource has increased with the GTA one success. So you have something that's well described. Yakaar Teranga in Senegal, we have added resource to it with the Yakaar II success. And I think underpinned a clear plan for the commercialization with a near term domestic project consistent with the country's plan in Mergent Senegal, but followed by an LNG export hub.

So a different level of definition from Tortue, but nevertheless clarity around the next steps to commercialize. And I would say in Boralla and Mauritania, it's all new. We had a successful well from many perspectives. It was about the confidence in the AVO. We drilled it in an area where we could distinguish a weaker Centaminian attribute to a much stronger Albian attribute.

We drilled it off structure, so that we could demonstrate the structural and stratigraphic closures were working. I think as a result, we have a significant resource now in Mauritania. So again, a different attribute. So I think one of the things we're doing is to show that that optionality is built into the sell down process. And there's a lot of new data to look at.

And I think there are different attributes that different buyers will look at as a result.

Speaker 3

Can I just ask a follow on, would we expect another well before the deal is closed or is this it for now?

Speaker 2

Clearly, we've got an ongoing conversation with the operator, but I think that if you look at GTA, I believe we're done. The East or two was an additional piece of resource, more than enough resource. I think we were well described in Yakar. And in Boralla, I think the evidence from the Orca well is quite compelling. So it doesn't need another well today to capture what I would say the core value in each of these assets now.

A lot's happened in the year and I think we're pleased with the precision with which we've done it and I don't think we need anything else.

Speaker 3

Thank you.

Speaker 2

Great. Thanks, Al.

Speaker 0

Our next question is from Bob Brackett, Bernstein Research. Please proceed with your question.

Speaker 4

Good morning. I had a question about resolution. Given that it's the largest of your Gulf Of Mexico ILX wells, what caused the cadence of it being the third to drill this year? Is that because it's higher risk or it needed partner permits? Can you give some color on that and what the risk of that well could be?

Speaker 2

Thanks, Bob. No, this is simply about there was a obviously a farming process with BP. We have to get that done. Then we have to go out and get the rig. As you know, we're not we don't have rigs on long term charters.

So it's a rig of opportunity, requires a certain spec. So that was the timeline behind that. So it is important that we need to keep emphasizing that because we're going out and actually literally using rigs of opportunity, the way the various prospects will line up will not be driven purely by scale or quality. There will be operational aspects that come into play. And that's why resolution was the timing of resolution has been driven by that.

Equally, oilfield has been done on a separate rig and so that's what drives its timing.

Speaker 4

That's very clear. A follow-up would be thinking ahead to 2020, you talked about during the Capital Markets Day, a first well in Santome Principe and then the Walker prospect in Suriname. How do we think about ILX program for 2020?

Speaker 2

Yes, look, we've built a really good portfolio now. And one of the things that I'm really pleased about is the pace at which we've done it in the Gulf Of Mexico, but actually it's the quality of what we've built in a year actually, it's a year actually since we just over a year since we closed. So I think what you can see is probably targeting around three to four ILX wells per year, where we've clearly opened up, I think a real opportunity set in Equatorial Guinea now. And so we're going to see competing prospects. We're going to see the competition between EG and the Gulf Of Mexico.

We've got a deep inventory in The Gulf, more than five years, so twenty five prospects that will be competing to get quality to the top and the same with EG. But I think if you were to sort of see us drilling for high quality material prospects in 2020 and actually each year beyond that, that's the cadence of the program.

Speaker 4

Okay, great. Appreciate it.

Speaker 2

Great. Thanks, Bob.

Speaker 0

Our next question is from Charles Meade, Johnson Rice. Please proceed with your question.

Speaker 5

Yes, good morning or good afternoon as it may be, Andy, to you and your whole team there. I wanted to pick up on your EG comments, and I wondered if you could give us a little more detail around the process forward here for this S-five, this discovery you made at S-five, both with respect to bringing this online and also the follow-up drilling. I know you have the seismic that's coming in early twenty twenty, but do you need that seismic before you can do an appraisal well? Do you need an appraisal well? And when should we be thinking about first volumes from this?

Speaker 2

Yes, great Charles. Look, you sort of go back, one of

Speaker 3

the

Speaker 2

fundamental thesis behind entering Ecuador or Guinea was to get access to Saipan Akume. We've done a great job in stemming the decline and creating value from that purely from the production operations. We capture the three license blocks around first step was go shoot the seismic and then we high graded that seismic program to around the to get the product first from around S-five. The target of the well was a Santonian channel, where we believe that the prior wells have been drilled on the edges of the channel, not in the heart of the channel. And so, the well objective was to establish high quality reservoir in the core of channel.

And we've done that. We've delivered 39 meters of good quality reservoir. We think we've got a lighter fluid than we've got elsewhere in Sabre and Okume. And actually this would be the first production from the Santonian in the area. So the well fully met all the expectations.

The primary target was Vault Block II, which you can see on the chart in the papers that we gave you ahead of the call. Going in the expectation was around 100,000,000 barrels of oil in place. So now it's ultimately about the establishing the connected volume. Now we've got we've literally just getting the well data in now. So the well is still underway, but we've got the initial well data and, tying that to the seismic, understanding the best depletion methodology, waterflood versus natural depletion.

Therefore, what's the optimal infrastructure that drives that? And then what pre investment would you put on the infrastructure? There are other fault blocks in the area. But I think we're genuinely excited about it because the thesis approved out, there is good Santonian Reservoir in the area. We've got a well, which fully met the expectations.

Now we've got to get to an optimized development scheme, which allows us to fully exploit it. So that's the those are the next steps and we're looking forward to do the work. I don't think we'll need another well to appraise it. I think we've got the data we need. Ultimate the test now is to optimize the configuration to ensure that we've got the best value for today and tomorrow.

Speaker 5

Got it. Thank you for that. And then if I could reference Slide eight and you guys put all that interesting seismic on your discovery there at Orca. Can you give us a little bit of a feel, what was the obviously, it's a big thing to find the Albion Reservoir, but how much was that the bigger surprise or was the bigger surprise finding that centimetion down structure like that?

Speaker 2

It looked both, wouldn't say surprise, but I think it was an important well because we wanted to test it to the fullest extent. We could have drilled as you can see, we could have drilled it sort of on structure in a more conservative, I'd say location. The problem with doing that is it would have resulted in another well to be drilled later. So we drilled a well, which we felt was optimally placed to demonstrate the quality of the Albion and to demonstrate both the structural and stratigraphic trap. So we I believe it was an appropriate exploration well, not without risk if you like, but actually with a good result, it's actually de risked both of those elements now.

And of course, there are read across obviously from Marsewin to Walker two other prospects in the area, Dauphin and Vailene. And then those four are Boralla Hub, which ultimately has the potential now with well described calibrated ABO that supports the upper end of the resource we've talked about.

Speaker 5

Thank you.

Speaker 2

Great. Thanks.

Speaker 0

Our next question is from Neil Mehta, Goldman Sachs. Please proceed with your question.

Speaker 6

Hey, thank you for the very thorough update this morning. The first question I have is just around Ghana production. Think year to date, I think you guys would acknowledge it's been more sluggish than what was initially anticipated. To the extent you could talk about it, how do you think we are in terms of course correction? And how should we think about the outlook for Ghana production going into 2020?

Speaker 2

Yes. Thanks, Neil. Yes, look, sort of stand back from it all, we would anticipate 2019 production to be around 90,000 barrels a day gross for Jubilee, which is clearly lower than forecast. And the primary issue is a rising GOR. Gas handling is therefore the constraint.

Clearly, you can handle more gas, you can produce more or it's as simple as that. We had hoped that the gas enhancement project will be done in 4Q. That's now been deferred by the operator to the first quarter of twenty twenty. So once that's carried out, clearly the ability to process more gas should lead to higher oil production in 2020. And directionally, we would see it rising in the sort of 95,000 to 100,000 barrels a day gross without enhanced gas handling.

I think Jubilee 10, I think our view is gross production will be around 62,000 barrels of oil per day. And then for 2030 relatively flat against that. So I think that's the outlook. And I think ultimately it is about a jubilee. It's not a reservoir issue.

It's not wells, got plenty of wells, reservoirs performing. We've just got to make sure that we can manage the GOR, which will ultimately provides plenty of opportunity to improve the oil rate.

Speaker 6

Well, that's great. And the follow-up question, this might be a question for Jamie, but with now your trailing four quarters of earnings, positive, and with the liquidity of the stock having improved, are you guys eligible for index inclusion? Can you just talk a little bit about some of the parameters recognizing that you can necessarily influence the outcome, but just so we can frame that out?

Speaker 2

Yes, Neil, I'll take that. Yes, you rightly say, the primary parameters are domiciled, which we are now. I think another parameter is the liquidity of the stock, which as you rightly point out has reached the thresholds with the sell down of the private equity owners earlier this year. Another key parameter is the in aggregate, your last twelve months of earnings need to be positive and the last quarter positive. So I think those are all the parameters.

And I think we believe we've met those. But as you rightly say, thereafter, it's really a black box in terms of the decisions of how and when the index inclusion would occur. So obviously, can't comment on that and neither can Jamie. But those are the three key parameters and obviously the results today were an important step forward in that.

Speaker 6

That's great. Thanks guys.

Speaker 2

Great. Thanks.

Speaker 0

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

Speaker 7

Thanks. Good morning, Andy. Congratulations on a nice quarter. Going back to the sell down process Mauritania Senegal, could you provide a little more detail on what the go forward plans are with the new data in hand? Will you reopen a data room?

What could be the potential timing? And maybe a few comments if you could on how the process was going leading into the drilling of the well, how many participants and if bids were submitted, etcetera?

Speaker 2

Yes. Thanks, Richard. Yes, it's been an interesting year for us. Think there's been a lot of interest and I think the interest is against sort of mixed background, would say. The positives are around a year where the energy transition and the pressure on companies to be relevant in that process and where gas, I believe will play an important role as a fuel has become more and more important to certain companies.

So of course, that's created genuine interest of how people can fit our resource and our projects in Mauritania and Senegal into their portfolios. And then, if you people have pushed on as a negative being the LNG prices in the year, which was certainly under pressure. I think, it's never good to do it in that environment, but actually this is production that comes on in 2022. Therefore, people are looking beyond that and they see a resource, which is ultimately low cost. It's got a very competitive price into Europe, competes absolutely with U.

S. Gulf Coast gas. And it's importantly got no CO2 in it. And as you think of competing projects around the world, as they meet the criteria set for the energy transition that is a key criteria. And then we've also had all the news as it were on the well results and we opened the data rooms pretty early after February, after the Capital Markets Day.

So a lot has occurred since. So I think the process really is about allowing people to come back in, look at the new data. And actually, I think Al's question at the beginning was important. I think we've got three very distinct assets now, which have different attractions to different buyers, which creates additional optionality in the process. So I think we've been in a very different place if we haven't had the success with the drill bit, but we always felt we would.

But actually getting people acquainted with the assets and now the ability to come back and look at them will be an important part of the process going forward.

Speaker 7

That's helpful, Andy. Thank you. And just lastly, it doesn't sound like there's going to be additional drilling at Mauritania Senegal related to the LNG projects in 2020. But could you talk maybe what the potential additional CapEx could be now that you'll retain 30% of the project into 2020 compared to maybe how you were thinking of it previously?

Speaker 2

Well, I don't think we've ever necessarily retained 30% going in. I think we need to sort of let the process play through 2020. What I think what we should do, we will do is we will come back to you in beginning of the year with our guidance for CapEx in 2020 to cover that. We clearly have the carry from BP, which covers a portion of that through 2020. So if it is an effect on the scenario you have played out, it would be a back end effect.

Speaker 7

Okay. That's all for me. Thanks, Andy.

Speaker 0

Our next question is from David Round at BMO Capital. Please proceed with your question.

Speaker 8

Hi, Andy. I appreciate you might not be in a position to comment on operator's decision to defer the gas enhancement project at Jubilee. But is there any thinking of the future proofing that work by adding even more gas handling capacity now? And then can I just ask on EG, you talk about development concepts post the discovery there? Am I right in assuming those development concepts are all tiebacks?

Or is there any thinking as to standalone given the additional resource that may be around the area?

Speaker 2

Yes, good questions, David. Look, again, the most important thing to emphasize on Jubilee is that it's a world class reservoir. It's a big field that's actually getting bigger. Reserve replacement has been very strong year on year. The fundamental issue is sort of gas management and there are two ways that which you can sort of deal with the problem, actually three ways in which you deal with the problem.

The first is, as you say, is sort of increase the gas handling and what we need to do is absolutely sort of our goal with the operator has been to maximize the increment that we can make now to provide us with the, as you say, the sort of the optimal solution that de risks this issue going forward. So the gas is no longer the constraint. The other ways in which you can help mitigate the issue is clearly water injection, increasing the downhole pressures, reliable water injection will also mitigate the GOR. And then the third thing that is absolutely in the works is to export more gas from Jubilee and to be used in domestic power production. And there is a power plant that has been actually been relocated adjacent to the Atararbo gas plant, which will actually take gas from Jubilee.

So that will enhance the gas offtake. So the combination those are the three parameters that are being juggled to ensure that we've got optimal oil production. So I'm not negative about the future, but we do need to sort of see the gas handling capacity increased. We need to see water injection will not be the improved and we need to see more gas offtake. Those together provide significant upside.

Speaker 0

Okay. And

Speaker 2

then, so I think the answer is there is plenty of opportunities to improve the situation. We just need to sort of quote, get it done. And then on EG, look, the reason we went in was EG was to look at things which we felt could be tiebacks. I would say today on the basis of what we know today that would be the optimal scheme because we have additional capacity at Sabre. Therefore, I think that's the way you should think about it.

The inventory we're building of future prospectivity, could be different. They could be different. But I think the objective for S5 was to demonstrate a resource that has tieback potential, therefore has very positive economics, both in terms of its quality of its returns and the cash accretive nature of the investment where we haven't got a long time to first oil, we've a short time to first oil and therefore very positive cash characteristics.

Speaker 8

Okay. Got it. Thanks,

Speaker 2

Thanks, David.

Speaker 0

Next question is from Pavel Molchanov, Raymond James. Please proceed with your question.

Speaker 9

Thanks for taking the question. Going back to the Sateme and Suriname plans for 2020, can

Speaker 3

you

Speaker 9

just remind, do you have a carry on that acreage as well?

Speaker 2

No. And I agree, there was a question on that, which I didn't answer actually. So let me get back to the timing.

Speaker 5

I think was a let me

Speaker 2

just can I use your answer your question more broadly, Pablo, well, because I think it's important that I come back to that point? The so we 2020, we have planned a well in Suriname targeting Walker, a carbonate opportunity. Collectively as a group, the partners have decided to defer the well to 2021. And the rationale for that is there's a lot going on in the basin at the moment. You all know the key wells that are being drilled.

The new data is going to come from that. And I think it's important that we take the time to fully digest that information and drill the best well at the right time. And I don't think we're in that position. We've got no time clock on the exploration program. So we're not in a rush.

So I think this is one where it is important to be absolutely disciplined about the capital because today we don't want to have any regrets about the well that we drill. We're not not rig driven, we're not time clock driven on the licenses. This is a real opportunity to maximize our knowledge and therefore the deployment of our capital. On EG, the seismic acquisition is obviously completed. The data is coming in and we can see good opportunity there.

So that remains a very valid target for

Speaker 8

2020.

Speaker 1

Okay. That's helpful.

Speaker 9

On Tortue, so you've been in construction now for roughly a year. And I'm curious, given the kind of the looseness across the oilfield service value chain, Are you perhaps seeing cost savings versus what you've originally UNBP had originally budgeted?

Speaker 2

Yes. I actually think that those savings were incorporated when we obviously went out to bid and then put the major contracts in place. There are elements of it, which are fixed costs. You've actually taken that opportunity in the supply chain when we did that. And I think the overall contracting strategy that BP has deployed is being really well done.

So I think those elements have sort of been captured. The issue now is sort of no changes and that's ultimately where projects sort of run into any trouble at this point in that cycle, where the variable costs could increase equally well with no changes, the variable costs could come down. But I think the what I would say is, to me, the most important part about the process is that in terms of execution, given the as you say, the looseness in the sector is you get the A teams from So there's never been better time to actually construct. And then, we clearly have not contracted yet for Phases two and three. And so the savings, I think, what we've learned from Phase one, we can take across to Phases two and three and look to continue to drive down those capital costs.

So the pace of the project has been done in a very thoughtful way where we're capturing the looseness in today's market, ensuring that we're contract well. And actually, the final point is take the learnings from Phase one and then apply them into Phases two and three. Lots to play for.

Speaker 6

Yes. Okay. Appreciate it.

Speaker 2

Great. Thanks, Pavel.

Speaker 0

This concludes the question and answer session. And I will now turn the floor back over to Jamie Buckland for closing remarks.

Speaker 1

Thanks, operator. We appreciate everybody joining us on the call today and your ongoing interest in Kosmos. And if you have any further questions, please don't hesitate to get in contact. Thank you very much.

Speaker 0

This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation.