Kosmos Energy Ltd. (KOS) Q3 2019 Earnings Report, Transcript and Summary

Greetings. Welcome to Kosmos Energy Third Quarter 2019 Earnings Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] 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.

Thank you, operator, and thanks to you all for joining us today. This morning, we issued our third quarter earnings release on a slide presentation to accompany today's call. Both materials are available on the Investors Page of the kosmosenergy.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 materials are Andy Inglis, 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.

(Auidt Start 1:45)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 portfolio rich and 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 million of free cash flow and we remain on track to deliver over $200 million 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&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 million barrels oil equivalent was designed as an inexpensive exploration tail of the Odd Job development well and costs around $3.5 million net to Kosmos. We have two more, near-term ILX wells in the GoM. We're currently drilling resolution and we will spud oilfield in December. These are the largest ILX prospects in the 2019 drilling campaign and both could be transformational for our GoM business in the event of success. Third, we’ve 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 de-risk around 50 TCF in the BirAllah area. Orca is the largest deepwater hydrocarbon discovery in the world so far this year. Fourth, with the recent success of Orca plus a significant appraisal success we've had a Yakaar 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 selldown 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 million 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 $0.045 for the quarter. Production for 3Q was flat versus 2Q taking out the impact of Hurricane Barry, which resulted in around 1,500 barrels of oil equivalent per day of lost production for the quarter. It was also slightly negatively impacted by unplanned downtime at Ceiba, which is partially offset by the successful ESP program at Okume with 5 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 2020. 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 ILX 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-1 discovery and we also announced 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 the first phase domestic gas project. And finally at Tortue, we had a successful result with the GTA-1 appraisal well, which expands the Tortue resource potential. The project continues to make good progress with the Phase 1 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 DGE 12 months ago. We’ve 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. Gladden Deep came online within four months of discovery and Nearly Headless Nick is expected online in December, a 15-month development. It’s these short development times that result in higher 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 oilfield prospect in December. These prospects are potentially much larger and can 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 in Equatorial Guinea. This morning we announced success with our initial ILX well in EG. This was the first well to be drilled on modern 3D seismic improved our concept around the potential of the under explored Rio Muni basin. The seismic for the S-5 areas 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 the [ph] logging data, it looks like the oil is higher quality than we have at Ceiba 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 Ceiba and Okume production. The field is within 20 kilometers of the Ceiba FPSO which puts it well within tieback range we’re now doing the work to establish the scalar of this given 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 2020 align 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-1 appraisal well we expanded our resource base at Greater Tortue Ahmeyim and we expect to use this well as a future producer. Beyond the appraisal drilling as you can see from the table at the bottom and images on the right, we've made considerable progress on Phase 1 of the project since FID. Key workstreams 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 2022. Turning to slide seven, our appraisal well at Yakaar-2 confirm 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 Teranga, 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 Albian 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 AVO tool to identify gas in quality reservoirs. The well which was drilled 7.5 kilometers off structure confirmed our pre-drill expectation of both structural and stratigraphic traps are present and working. Turning to slide nine, Orca is Kosmos is 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 Albian play and encountered 36 meters of net pay in excellent quality reservoirs. Together with Marsouin, we believe we now have the rest of the 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 this year. At the time, we estimated that Mauritania Senegal Diego at around 50 TCF of gas in plays with upside potential to double that in the event of successful exploration and appraisal campaign this year. We've done that with success at GTA-1, Yakaar-2 and Orca-1, n we've increased the resource base at the top end of the range to around 100 TCF across the basin, providing sufficient resource to underpin three LNG hubs, totaling 30 million tons per annum of capacity. With a significant resource additions through 2019. we've extended the selldown 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 the EG and the GoM. 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.

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

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 assume 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.

Yes. Hi, Al. 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 Yakaar-2 and Orca, and we now have a resource which we believe is at the top end of 50 TCF 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 and half years away. The resources increased with the GTA-1 success. So you have something that's well described. Yakaar Teranga and Senegal, we have added resource to it with the Yakaar-2 success and I think underpinned a clear plan for the commercialization with a near-term domestic project consistent with the country's Plan Emergent 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 BirAllah 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 Cenomanian attribute to a much stronger Albian attribute. We drilled it off structure so that we could demonstrate the strstructure on stratigraphic closures where we’re 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 selldown 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.

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

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 Tortue was an additional piece of resource, more than enough resource. I think we’re well described in Yakaar. And in BirAllah, 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 happen in a 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.

Thank you.

Great. Thanks, Al.

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

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?

Yes, thanks, Bob. No, this is simply about -- there was obviously a farm-in 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. It 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 is being driven by that. Equally, oilfield has been done on a separate rig and so that's what drives its timing.

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 Sao Tome and Principe, and then the walker prospect in Suriname, how do we think about ILX program for 2020?

Yes, 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 it’s 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, some 25 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 four high quality material prospects in 2020 and actually each year beyond that, that's the cadence of the program.

Okay, great. Appreciate it.

Great. Thanks, Bob.

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

Yes. Good morning or good afternoon maybe 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-5 this discovery you made at S-5 both with respect to bringing this online. And also the follow up, Joe and I know you have the seismic that's coming in early 2020, 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?

Yes, great Charles. Look, should you go back one of the fundamental thesis behind entering Equatorial Guinea was to get access disciple Ceiba and Okume. We've done a great job in stemming the decline and creating value from -- purely from the production operations. We capture the three license blocks around first step was to go shoot the seismic and then we hydrated that seismic program to around the -- to get the product first from around S-5. The target of the well was a Santonian channel, where we believe the prior wells had 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 the 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 Ceiba 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 [indiscernible] which you can see on the on the chart in the papers that we gave you ahead of the call. Going in the expectation was around 100 million barrels of oil in plays. So now it's ultimately about the establishing the connected volume that we've got, we literally just getting the well data in now. So the well is still underway, but we've got the initial well data in tying that to the seismic understanding the best depletion methodology, water flood versus natural depletion. Therefore, what 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 are genuinely excited about it because the thesis would prove 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 will need another well to appraise it, I think we've got the data we need, the -- ultimately the test now is to optimize the configuration to ensure that we've got the best value for today and tomorrow.

Got it, thank you for that. And then if I could reference up slide eight and you guys put all that interesting seismic on that on your discovery there at Orca. Can you give us a little bit feel what was the -- obviously it's a big thing to find the Albian reservoir. But how much -- was that the bigger surprise, or was the bigger surprise finding that Santonian down structure like that?

Both, I wouldn't say surprised but I think it was a -- 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 Albian and to demonstrate both a 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-risk both of those elements now and of course there are read across obviously from Marsouin to Orca to other two other prospects in the area Dauphin and Baleine. And those four are the BirAllah hub, which ultimately has the potential now with well described calibrated AVO that supports the upper end of the resource we've talked about.

Thank you.

Great, thanks.

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

Hey, thank you for the very thorough update this morning. The first question I have is just around Ghana production, I think year-to-date, I think you guys 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?

Yes. Thanks, Neil. Look it 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 the rising GOR, gas handling is therefore the constraint if you can -- clearly, if you can handle more gas you can produce more oil 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 2020. 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 sort of 95,000 to 100,000 barrels a day gross without enhanced gas handling. I think Jubilee, I think our view was gross production would be around 62,000 barrels of oil per day and then for 2020 turn relatively flat again there. So I think that's the outlook and I think ultimately it is about the Jubilee. It's not a reservoir issue, it's not the well, got plenty of wells, reservoir is performing. We've just got to make sure that we can manage the GOR, which will ultimately provide plenty of opportunity to improve the oil rate.

That's great. And the follow up question and this might be a question for Jamie. But with now you're trailing four quarters of earnings positive and with the liquidity of the stock having improved are you guys eligible for index inclusion? Can you talk a little bit about some of the parameters recognizing that you can't necessarily influence the outcome, but just so we can frame that out?

Yes. Neil, I'll tell you that. Yes, as you rightly say, the primary parameters are U.S. domiciled, which we are now. I think another parameter is the liquidity of the stock, which as you rightly point out has reached the threshold with the selldown of the private equity owners earlier this year. Another key parameter is the -- in aggregate your last 12 months of earnings need to be positive and the last quarter positive. So I think those are all -- those are the parameters. And I think we believe with -- 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, I can't comment on that and neither can Jamie. But the -- those are three key parameters and obviously the results today were an important step forward in that.

That's great. Thanks, guys.

Great. Thanks.

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

Thanks. Good morning, Andy. Congratulations on a nice quarter. Going back to the selldown process Mauritania and 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 time? 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 bids were submitted, et cetera?

Yes. Thanks, Richard. Yes, it's been an interesting year for us. I think there's -- have been a lot of interest. And I think the interest is against sort of mixed background I 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 people have pushed and has 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, compete 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 open 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 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.

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 Cape could be? Now that you'll retain 30% of the project into 2020 compared to maybe how you were thinking of it previously?

Well, I don't think we’ve said necessarily going to retain 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 and the scenario you have played out. It would be a backend effect.

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

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

Hi, Andy. I appreciate you might not be in a position to comment on the operators' decision to defer the gas enhancement project to Jubilee. But is there any thinking as 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?

Good questions, David. Yes. Again, the most important thing to emphasize on Jubilee is 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 sort of the optimal solution that de-risk the decision 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 downhill 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 actually been relocated adjacent to the [indiscernible] gas plant, which will actually take gas from Jubilee. So that will enhance the gas off take. So the combination -- those are the three parameters that are being juggled to ensure that we've got the 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 ought to be improved and we need to see more gas off take those together provide a significant upside.

Okay.

And then, so I think the answer there is plenty of opportunities to improve the situation, we just need to sort of quite get it done. And then on EG, the reason we went in was to -- to 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 Ceiba. And therefore I think that's the way you should think about it. The inventory, we're building of future prospectivity they could be different, but I think the objective for S-5 was to demonstrate a resource that has tieback potential thereby 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 got short down to first oil and therefore very positive cash characteristics.

Okay, got it. Thanks, Andy.

Thanks, David.

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

Thanks for taking the question. Going back to the Sao Tome and Suriname plans for 2020, can you just remind, do you have a carry on that acreage as well?

No. And I agree there was a question on that, which I didn't answer actually. So let me get back to the timing. Let me just answer your question more broadly, Pavel, as well, because I think it's important that I come back to that point. So in 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 2021 and the rationale for that is there's a lot going on in the basin at the moment, you all the key wells that have been drilled, 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 quote, we're not in a rush. So I think this is one way 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 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 2020.

Okay, that's helpful. 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 -- you and BP had originally budgeted?

Yes, no, 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 the 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 cost could come down. But I think what I would say to me the most important part about the process is that in terms of execution, given as you say the looseness in the sector is you get the A teams from the contractors. So there has never been better time to actually construct. And then, we clearly have not contracted yet four Phases 2 and 3. And so you have the savings, I think what we've learned from Phase 1, we can take across Phases 2 and 3 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 contract well, and actually the final part is take the learning's from Phase 1 and then apply them into Phases 2 and 3 lot to play for.

Yes, okay. Appreciate it.

Thanks, Pavel.

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

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.

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