Greetings. Welcome to Kosmos Energy third quarter 2019 earnings conference call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. 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 and the 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 material 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.
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 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 Oddjob development well and cost around $3.5 million net to Kosmos. We have two more near-term ILX wells in the GoM. We are currently drilling Resolution and will spud Oldfield 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.
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 de-risk around 50 Tcf in the Barela area. Orca is the largest deepwater hydrocarbon discovery in the world so far this year. With the recent success of Orca, plus the significant appraisal success we've had at Yakaar and Tortue this year, the total resource estimate for the Mauritania-Senegal Basin has increased the top end of the 50-100 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. 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 like to discuss the third quarter in more detail. As mentioned on the previous slide, Kosmos generated $70 million of free cash in three Q. 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 $4.5 for the quarter. Production for three Q was flat versus two Q, 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 Ceiba, which was 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 S-5 well. More on that in a moment. 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. We also announced the Yakaar-2 appraisal well result during the quarter, which proves up the southern extension of the field and supports a Yakaar-Teranga LNG hub and a first phase domestic gas project. 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 DG 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 tie-backs. 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 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 Oldfield Prospect in December. 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 catalyst 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 underexplored Rio Muni Basin. The seismic for the S-5 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 initial 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 will be a material increment to the current Ceiba-Okume production. The field is within 20 kilometers of the Ceiba FPSO, which puts it well within tie-back range. We're now doing the work to establish the scale of the discovered 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 tie-back prospects around the existing infrastructure. Final volumes from the 2018 seismic are expected to be delivered in early 2020, 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-1 appraisal well, we expanded our resource base at Greater Tortue Ahmeyim, 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 2022. Turning to slide seven, our appraisal well at Yakaar-2 confirmed the southern extension of the field.
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 seven and a half kilometers off-structure, confirmed our pre-drill 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 Albian play and encountered 36 meters of net pay in excellent quality reservoirs. Together with Marsouin, we believe we now have de-risked 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. Turning to the final slide, one that we presented at the Capital Markets Day in February 2019.
At the time, we estimated that Mauritania and 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, Yakaar-2, and Orca-1. 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 these 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. 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. 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. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment please, while we poll for questions. Our first question is from Al Stanton, RBC. Please proceed with your question.
Yes. Good evening, guys. 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. I think historically, we always assumed there would be one buyer focused on Tortue with additional discoveries being sort of nice to have. 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.
Hi, Al. Thanks. To 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. Through the year, we've had success with the wells, as I said in my remarks, GTA-1, Yakaar-2, and Orca. We now have a resource which we believe is at the top end of that 50-100 Tcf range. We want to ensure that the potential buyers do have time to analyze the new data and better understand the assets. 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 first gas, two and a half years away. The resource has increased with the GTA-1 success. You have something that's well-described. Yakaar-Teranga in 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 Sénégal Émergent, but followed by an LNG export hub. A different level of definition from Tortue, but nevertheless, clarity around the next steps to commercialize. I would say in BirAllah in 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 structural and stratigraphic closures were working.
I think as a result, we have a significant resource now in Mauritania. Again, a different attribute. I think one of the things we're doing is to show that that optionality is built into the sell down process. 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's 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's happened 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.
Cool. Thank you.
Great. Thanks, Al.
Our next question is from Bob Brackett, Bernstein. Please proceed with your question.
Yeah, 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?
Thanks, Bob. This is simply about, there was obviously a farming process with BP. We had to get that done, then we had to go out and get the rig. As you know, we don't have rigs on long-term charter, so it's a rig of opportunity. It requires a certain spec. That was the timeline behind that. It is important that I 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. It's been driven by that. Equally, Oldfield 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 São Tomé, Príncipe, and then the Walker prospect in Suriname. How do we think about ILX program for 2020?
Yeah, look, we've built a really good portfolio now. 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, just over a year since we closed. I think what you can see is it's probably targeting around three to four ILX wells per year. We've clearly opened up I think a real opportunity set in Equatorial Guinea now. 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. 25 prospects that'll be competing to get quality to the top, and the same with EG.
I think if you were to sort of see us drilling four high-quality material prospects in 2020, and actually each year beyond 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 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 S5, this discovery you made at S5, both with respect to bringing this online and also the follow-up drilling. I know you have the seismic that's coming in early.
Yeah
2020. Do you need that seismic before you can do an appraisal well? Do you need an appraisal well? When should we be thinking about first volumes from this?
Great, Charles. You sort of go back, one of the fundamental thesis behind entering Equatorial Guinea was to get access to Ceiba and Okume. We've done a great job in stemming the decline and creating value from that, purely from the production operations. We captured the three license blocks around. First step was to go shoot the seismic, we hydrated that seismic program to get the product first from around S5. The target of the well was a Santonian channel, where we believe that the prior wells had been drilled on the edges of the channel, not in the heart of the channel. The well objective was to establish a high-quality reservoir in the core of the channel. 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. Actually, this would be the first production from the Santonian in the area. The well fully met all the expectations. The primary target was fault block 2, 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 million barrels of oil in place. Now it's ultimately about establishing the connected volume. We're literally just getting the well data in now. The well is still underway. We've got the initial well data in. We're tying that to the seismic, understanding the best depletion methodology, water flood versus natural depletion. Therefore, what's the optimal infrastructure that drives that? Then, what pre-investment would you put on the infrastructure? There are other fault blocks in the area.
I think we're genuinely excited about it because the thesis was proved out. There is good Santonian reservoir in the area. We've got a well which fully met the expectations. We've got to get to an optimized development scheme which allows us to fully exploit it. 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. The ultimate 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. 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? Obviously it's a big thing to find the Albian reservoir, but was that the bigger surprise or was the bigger surprise finding that Cenomanian down structure like that?
A little of both. I wouldn't say surprised, 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. We drilled a well which we felt was optimally placed to demonstrate the quality of the Albian and to demonstrate both the structural and stratigraphic trap. I believe it was an appropriate exploration well, not without risk, if you like. Actually with a good result. It's actually de-risked both of those elements now. Of course, there are read across obviously from Marsouin to Orca to other prospects in the area, Dauphin and Baleen.
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.
All right. 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 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?
Thanks, Neil. Look, if 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. The primary issue is a rising GOR. Gas handling is therefore the constraint. 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 would be done in 4Q. That's now been deferred by the operator to the first quarter of 2020. Once that's carried out, clearly the ability to process more gas should lead to higher oil production in 2020. Directionally, we would see it rising in the sort of 95 to 100,000 barrels a day gross, with that enhanced gas handling. I think our view is gross production will be around 62,000 barrels of oil per day.
For 2020, 10 relatively flat against that. I think that's the outlook. I think ultimately it is about the Jubilee. It's not a reservoir issue. It's not wells. We've got plenty of wells, reservoirs 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.
Well, that's great. The follow-up question, 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 just 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.
Yeah, Neil, I'll take that. 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 thresholds with the sell down of the private equity owners earlier this year. Another key parameter is in aggregate, your last 12 months of earnings need to be positive and the last quarter positive. I think those are the parameters. I think we believe we've met those. 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. Obviously I can't comment on that and neither can Jamie. Those are the 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 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? 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, et cetera.
Thanks, Richard. It's been an interesting year for us, I think. There's been a lot of interest. I think the interest is against a 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, where gas, I believe will play an important role as a fuel, has become more and more important to certain companies. Of course, that's created genuine interest of how people can fit our resource and our projects in Mauritania and Senegal into their portfolios. If people have pushed on us, as a negative being the LNG prices in the year, which were certainly under pressure. I think it's never good to do it in that environment. Actually, this is production that comes on in 2022.
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. It's importantly got no CO2 in it. As you think of competing projects around the world, as they meet the criteria set for the energy transition, that is a key criteria. We've also had all the news, as it were, on the well results. We opened the data rooms pretty early after February, after the Capital Markets Day. A lot has occurred since. I think the process really is about allowing people to come back in, look at the new data. 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. I think we'd be in a very different place if we hadn't had the success with the drill bit, but we always felt we would. 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.
Yeah. That's helpful, Andy. Thank you. Just lastly, it doesn't sound like there's going to be additional drilling at Mauritania-Senegal related to the LNG projects in 2020. 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?
I don't think we've said we're 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, what we will do is we will come back to you in the 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. If it is an effect on the scenario you have played out, it would be a back end effect.
Okay. That's all from 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 operator's decision to defer the gas enhancement project at Jubilee, but is there any thinking of future-proofing that work by adding even more gas handling capacity now. 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?
Yeah. Good questions, David. Yeah. 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. 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. 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. The third thing that is absolutely in the works is to export more gas from Jubilee, and to be used in domestic power production. There is a power plant that has been actually being relocated adjacent to the Atuabo gas plant, which will actually take gas from Jubilee. That will enhance the gas offtake. Those are the three parameters that are being juggled to ensure that we've got the optimal oil production. 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 reliability improved, and we need to see more gas offtake. Those together provide significant upside. Okay.
Okay.
I think the answer is there is plenty of opportunities to improve the situation. We just need to sort of, quote, "Get it done." On EG, look, the reason we went in 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. I think that's the way you should think about it. The inventory we're building of future prospectivity, they could be different. I think the objective for S-5 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 got a short time to first oil, and therefore, very positive cash characteristics.
Okay. Got it. Thanks, Andy.
Okay. 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 São Tomé and Suriname plans for 2020. Can you just remind, do you have a carry on that acreage as well?
No. I agree, there was a question on that which I didn't answer, actually. Let me get back to the timing. I'll answer your question more broadly, Pavel, as well, because I think it's important that I come back to that point. 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. 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. 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. I don't think we're in that position.
We've got no time clock on the exploration program, quote, "We're not in a rush." 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 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 E.G., the seismic acquisition is obviously completed. The data is coming in, and we can see good opportunity there. That remains a very valid target for 2020.
Okay. That's helpful. On Tortue, you've been in construction now for roughly a year. I'm curious, given the looseness across the oil field service value chain, are you perhaps seeing cost savings versus what you and BP had originally budgeted?
Yeah, 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. I think the overall contracting strategy that BP has deployed has been really well done. 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 their cycle, where the variable costs could increase equally well with no changes, the variable costs could come down.
I think 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 the contractors. There's never been a better time to actually construct. We clearly have not contracted yet for phases 2 and 3. The savings, I think, what we've learned from phase 1, we can take across to phases 2 and 3 and look to continue to drive down those capital costs. 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. Actually, the final point is take the learnings from phase 1 and then apply them into phases 2 and 3. Lot to play for.
Yep. Okay. Appreciate it.
Great. Thanks, Pavel.
This concludes the question and 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. 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.