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The conversation today is structured around the building blocks of the business, starting with our near-term growth opportunities and progressing through to our basin opening exploration opportunities. Following my introduction, I will first talk you through the high return, production optimization and exploitation opportunities in the GOM, EG and Ghana.

Richard and Tracey will then describe the significant scale of the high value infrastructure-led exploration opportunities or ILX that we have rapidly built in the Gulf of Mexico and Equatorial Guinea. We'll then have a Q&A session and take a short break, before I come back at 3:45 to talk about the world-scale gas resources we're monetizing in Mauritania and Senegal. Tracey will conclude the portfolio review with an update on our basin opening exploration portfolio, which is the strongest it's ever been in the history of Kosmos. Tom will then finish the presentation with a description of the solid financial platform that underpins the business delivery. I'll conclude, and there will be another opportunity to ask questions before we break.

There are six things I want you take away from today's presentation. First, we've built an incredibly resilient business. Kosmos can fund its dividend and the sustaining capital required to keep production flat at $35 per barrel Brent. Second, we've materially reduced our 2019 CapEx, reducing it by around 20%, while maintaining our production CAGR guidance from year-end 2018 through 2021 of 8% to 10%. Third, we've made two great acquisitions. Not only of these acquisitions in EG the GOM already delivered significant return on our investments, they've also created the next chapter of growth for Kosmos with major ILX opportunities in both areas. Fourth, the significant resource we've discovered in Mauritania and Senegal is highly valued. It's reached a value inflection point with the Tortue final investment decision and following several unsolicited approaches by third parties, we expect to sell down our interest to around 10%. This is the right level of interest, given the significant scale of the Mauritania-Senegal business going forward. In just two years, we've gone from a 5 million ton per annum projects to three projects in aggregate with a 30 million ton per annum potential.

Fifth, 2019 is a very active year for exploration in Kosmos. We expect to drill six exploration wells across the portfolio, targeting 500 million barrels oil equivalent net to Kosmos, which would double our current 2P reserves. And finally, our relationship with the super-majors are creating differential value for Kosmos' shareholders. We are leveraging expertise and complementary skill sets across all parts of our portfolio, ILX, development and basin opening exploration.

So what is it that makes Kosmos unique? We have world-class assets with a focus on quality. Over the last two years, we've grown production by 85% annually and built a 2P reserve to production ratio of over 20 years, without diluting shareholders. We have disciplined capital management, focused on value. We have strict rate of return criteria for our investments and a commitment to a strong balance sheet and shareholder returns.

We have demonstrated exploration excellence, executed with a rifle shot approach. A track record of basin opening success of 36% and Gulf of Mexico success of 63%. We have a rapid development cycle with a focus on payback. Jubilee, three and a half years from discovery to first oil. Tortue, seven years from discovery to first gas expected. Gulf of Mexico, a tracked record of discovery to production of less than 18 months. We have active portfolio management with a focus on value creation. Mauritania and Senegal has already delivered 2.5 times investment with further upside anticipated from the sell down to 10%. Equatorial Guinea has already delivered three times our initial investment. The Gulf of Mexico acquisition has delivered 1.5 times on our investment within six months, more on all of these shortly. This is a DNA of Kosmos that makes us the partner of choice for super-majors and governments and underpins our unique delivery of shareholder value.

So in summary, we've built a business that delivers strong free cash flow, returns-driven growth from a deep diverse portfolio with a focus on shareholder returns, supported by strong balance sheet and financial flexibility.

Safety is a fundamental value of our business and underpins our license to operate. As you can see on this slide, in 2018, we operated our largest ever activity set with six wells drilled, 25,000 square kilometer of seismic acquired, which incidentally was 16% of the global proprietary offshore seismic shot by the industry.

Our operating track record is a key enabler for our relationship with the super-majors, having drilled the seventh deepest water depth well in the history of the industry for BP and two wells on behalf of Chevron in Suriname. Whilst our performance is ahead of industry averages, we know we need to keep improving every year.

This is an important slide. the pace of change in Kosmos over the last two years has been significant. We've more than tripled production from around 20,000 barrels oil equivalent per day to approximately 66,000. The same time we've more than tripled our 2P reserves from 145 million barrels equivalent to 513. This transformational growth has been achieved through a combination of organic and inorganic activities. And most importantly, it's been done without any dilution to shareholders. The quantum of shares issued for the DGE acquisition were repurchased within six months at around a 35% discount to the issuing price.

I also want to remind you that creating value from exploration is at the heart of the Kosmos business model. 2019 is no different. We expect to drill six wells that makes it basin opening, infrastructure-led opportunities that target net prospective resource of around 500 million barrels of oil equivalent, roughly equal to our current 2P reserves, around 20 times 2019 forecast production. As Tracey will show you later in the presentation, our basin opening portfolio is as deep it has ever been and ranks with the key players in the Atlantic Margin. In 2018, Kosmos was the third ranked company in the industry globally in terms of acreage acquired, only behind Exxon and Total.

So we built a deep and balanced portfolio that can deliver sustainable growth over the long term. Our goal is to double production from the existing portfolio by 2025 and this assumes no basin opening success or inorganic activity and is post-sell down of Mauritania, Senegal to 10%. As we'll show you through the presentation, this growth is governed by strict internal rate of return criteria and will not be done by chasing volume over value. Furthermore, the growth is not back-end loaded. And over the next three years, we anticipate an 8% to 10% CAGR in production from existing assets in the GOM, EG and Ghana.

In 2019, we expect CapEx of around $425 million to $475 million, down around 20% from our November guidance of $500 million to $600 million, while delivering the same three year production CAGR guidance of 8% to 10%. This has been done by an internal process of challenge across the business units to ensure our capital program is targeting both effectiveness and efficiency with opportunities coming to light as we fully integrated the EG and GOM businesses. Effectiveness is about ensuring every dollars spent is targeting the highest value activity and removing lower value activity. Efficiency means every dollar spent is at the lowest cost without compromising safety and integrity. Over the next three years, we expect an average capital level of around $500 million per year to deliver the production growth we discussed.

This is an other important slide. I want you to understand the balance, diversity and flexibility in our capital program. First, our capital program is balanced across the activities that drive short, medium and long-term growth, governed by strict rate of the return criteria. Second, the diversity we created in our business over the last two years allows competition for capital between our business units, with no single project or geography dominating. And finally, our capital program is flexible. In a low price world, we can turn it down to around 45%, which would sustain current production levels and protect the dividend at $35 per barrel Brent, as we'll show you in a moment.

As I mentioned in my opening remarks, delivering strong free cash flow is a primary objective of the Kosmos business model. Despite the challenging conditions for the oil and gas sector over the last few years, Kosmos has consistently generated strong levels of free cash flow and we've used that cash flow wisely. In 2017, we redeployed the proceeds from the BP farm-out to fund the EG acquisition and generated around $100 million of free cash flow.

In 2018, the free cash flow was returned to shareholders through the buyback of 35 million shares for around $190 million. Looking forward over the next three years, at $60 per barrel Brent, we anticipate generating around $1 billion of free cash flow, which is around 40% of our current market cap. This excludes any proceeds from Mauritania and Senegal sell down and we expect to allocate around 25% of the $1 billion to paying the dividend.

In my opening remarks, I've talked about the transformation that's occurred in the Kosmos business. One thing that hasn't changed is our approach to managing the balance sheet, ensuring it remains strong. As a result, we have the financial flexibility, both offensively to manage the business in a low price environment and offensively to pursue attractive, value-accretive opportunities. We exited 2018 with a net debt to EBITDAX ratio of 2 times, have a target ratio of 1 times to 1.5 times, which gives us the flexibility to act opportunistically on value accretive situations through the cycle, as evidenced by our past M&A track record.

Let me show you how we're going to get that. I'm going to go through this slide slowly, because it's important that you understand the flexibility that we have in the business. At $35 per barrel Brent, we can sustain the business and pay the dividend, which at $0.18 per share currently yields around 3%. In addition, we can grow production at 8% to 10% CAGR with strict rate of return criteria at less than $50 Brent.

At $50 Brent and above, excess cash flow, together with any proceeds generated from the Mauritania, Senegal sell down will be used to, first, strengthen the balance sheet, to bring the net debt to EBITDAX multiple within the target zone of 1 times to 1.5 times. Once we're in that zone, any excess cash flow can be used opportunistically, either toward accretive transactions, where we have a track record of achieving significant returns on investment or additional shareholder returns, such as the opportunistic share buyback we concluded after the DGE transaction. So another key point I want you to take away from today's presentation is the resilience of the business, which enables us to focus on shareholder returns.

In these opening slides I hope I've conveyed my excitement on what Kosmos can deliver and the resources required to do it. I now want to shine a light on the portfolio by looking at the short, medium and long-term growth opportunities and demonstrate we have the right assets and the right capability. Let me start with the production optimization and exploitation activity.

These are the key points that I want you to take away from this section. The growth from the existing reserve base is strong, supported by the organic 1P reserve replacement ratio in 2018 of over 130%. Including the DGE acquisition, the 2018 reserve replacement ratio is over 450%. These are high margin barrels with low lifting costs, typically around $10 to $15 per barrel, resulting in an average operating cash margin of $45 to $50 per barrel at $60 per barrel Brent. And finally, this growth is coming from high rate of return projects, on average around 100% rate of return.

I want to begin with the Gulf of Mexico and why I'm so excited about having Deep Gulf Energy as part of the Kosmos family. This wasn't about buying production, this was about building a platform for future growth with a team that has a long and successful track record in the Gulf of Mexico. Rich and his team have operated in the basin for 25 years and have discovered almost 1 billion barrels of oil equivalent. They started in 1994 and built Mariner, a deep-water operator. Richard left Mariner in 2002 and started DGE in 2004 with former colleagues from Mariner joining in. Over that period, they've developed a deep operating capability and demonstrated expertise in low-risk exploration and subsea tiebacks with a track record of delivering high return quality projects on time and on budget.

This slide shows the recent track record of Deep Gulf Energy, a business that's delivered production and reserve growth rapidly as a result of high exploration success rate, as I said, around 63%, or 10 successful wells drilled out of 16. Together with low F&D of around $15 per barrel, this has generated high margin profitable growth.

So why was now the right time to move into the Deepwater Gulf of Mexico? There are two reasons, attractive economics and low competition. First, the GOM Deepwater generates exceptional returns and fits with the low cost, high return Kosmos model. This slide shows the half-cycle NPV 10 breakeven oil price of GOM Deepwater. With a breakeven of less than $30 per barrel WTI, it's competitive with the high margin assets in the Kosmos portfolio. As context, the slide also shows the half cycle NPV 10 breakevens of the major onshore U.S. plays. As you can see, the GOM Deepwater competes very favorably with the best shale plays.

Second, as Richard will describe, the competitive landscape has never been better. The chart on this slide shows how competition at Deepwater GOM has reduced significantly over the last 10 years. The bar show the number of players, private, independent and super majors. Whilst the number of private companies and super majors has remained broadly constant, I want to draw your eye to the light blue bar in the middle, the number of independents. This has reduced dramatically as these companies have turned their focus to U.S. onshore.

With the combination of expertise from Kosmos and DGE and our relationship with the majors and private equity companies, we have the opportunity to become the leading independent in the Deepwater Gulf of Mexico and take advantage of the significant running room in the basin, a point that Richard will come to later.

Our Gulf of Mexico assets have a strong production base, both in terms of the financial characteristics and the ability to grow. Low lifting costs of around $9 per barrel deliver high margin. Low F&D costs of around $15 per barrel generate higher returns, typically 45% on a project basis. We also have a strong reserve base, which has 2P reserve production ratio of around nine years and a 1P reserve replacement ratio in 2018 of 114%.

The quality of our existing Gulf of Mexico producing of development assets is demonstrated on this slide, where we expect to grow production to 27,000 barrels of oil equivalent per day through 2019 and sustaining that level over the 2019 to 2021 period.

To do this, we expect to bring on to production five wells over the next two years; Tornado, Odd Job and Nearly Headless Nick in 2019 and South Santa Cruz and Kodiak in 2020. As you can see, production this quarter in the GOM will be lower due to the planned dry-dock of the Tornado floating production facility as previously communicated by the operator. The slide also shows the sustaining CapEx that supports this production profile. Together with the growth capital, we plan to invest in the ILX opportunities that will grow the production profile. More on that from Richard in a few minutes.

Turning to the base business in Equatorial Guinea, you'll notice that it has similar characteristics to our Gulf of Mexico business. The net lifting costs are higher due to the PSC terms, and a more extensive well work program which is expensed. We've included these in the lifting cost on this page. A couple of things to note. The low acquisition cost of $5 per barrel and the high reserve replacement ratio of over 200% in 2018.

Production in EG sustained by high rate of return optimization projects, focused principally on the installation of electrical submersible pumps and a well acidization program. This program, in addition to other well optimization, has helped deliver the first increase in oil production from Ceiba and Okume since 2010, with very little capital exposed.

Since acquisition, the business has performed well, with dividends received of $258 million versus a purchase price of $231 million. As of January the, 1st this year, from a reporting perspective, we will account for the EG assets on a fully consolidated basis, giving greater visibility to the underlying performance. Future growth will come from ILX tieback projects, and I'm very excited about the G-13 opportunity, an existing discovery on Block S, one of the exploration blocks that was licensed by Kosmos from the government, at the same time as the Ceiba and Okume fields were acquired from Hess as part of our entry into EG.

Tracey will describe this in more detail in the next section. The production optimization hopper in Equatorial Guinea is large, high quality and uses proven technology. This slide illustrates the performance uplift we can expect from the ESP program. Two conversions have been completed with three more plant in 2019. This initial program is expected to deliver a gross production uplift of around 4,000 barrels of oil per day and adds over 3 million barrels of reserves at a cost of $5 per barrel. The program rate of return is well over 100%. Starting next year, there are nine additional conversions planned with further opportunities from returning previously shut-in wells to production and recompletion candidates.

I'll conclude this section with a brief update on Ghana. As you are aware, these assets are gain characterized by low lifting costs that deliver high margin, low F&D cost, delivering high returns and characterized by big fields that continue to get bigger. 2018 was a six year in a row, where the 1P reserve replacement ratio greater than 100%.

We currently have two rigs drilling in Ghana, taking advantage of low rig rates. In 2019, the operator is expecting to drill seven wells, with the objective to fill the Jubilee and TEN facilities. The continuing growth in the reserve base, as resource matures from 3P to 2P to 1P, is expected to provide substantial running room to maintain the plateau into the 2020s.

The drilling program has been optimized over the next three years, which is reflected in the capital outlook on the slide. Given the established infrastructure, these infill wells are all high rate of return projects and match the 100% rate of return targets we show at Equatorial Guinea. Good progress was made in 2018 on the Jubilee turret remediation projects, with the vessel now at its final heading. We expect the spread mooring will be completed later this year, with a CALM buoy in place in 2020. However process facility uptime on Jubilee in 1Q has not met expectations. As a result, the operator is now forecasting slightly lower production in the first quarter.

I'd like to summarize this section of our Capital Markets presentation by showing the inherent value of our established businesses in the Gulf of Mexico, Equatorial Guinea and Ghana. Based on our 2018 year-end Ryder's Reserve Reports, it's $60 Brent per barrel. The NPV10 of our 2P reserves in Ghana, EG and the GOM fully burdened with the company's net debt and underpins the share price of around $6.50 or inclusive of 3P over $9. This doesn't include the value of our ILX opportunities, the value of our gas resource in Mauritania and Senegal or the value of our basin opening exploration portfolio.

Let's look at the first of those, our ILX opportunity set and before I hand over to Richard and Tracey, I'd like to highlight the key takeaways. These projects leverage existing infrastructure, so generate very attractive returns. Its existing infrastructure also allows rapid development from discovery to production. As Richard and Tracey will show, we have a deep inventory in both the GOM and EG, and enhancements in seismic technology are lowering exploration risks and increasing the hopper of opportunities.

Richard, over to you.

Richard Clark -- Senior Vice President, Gulf of Mexico

Well, good afternoon, everyone. As Andy mentioned, I was the Founder and the President of Deep Gulf Energy, and I now head up the Gulf of Mexico Business Unit. So, Andy has talked about how we can sustain our business at Kosmos through our development activity. And in this section, Tracey and I are going to talk about how we can grow the business through short-cycle, infrastructure-led exploration opportunities both in the Gulf of Mexico and in Equatorial Guinea.

So, my business in the Gulf is pretty much focused around doing subsea tiebacks to existing infrastructure, and then we pay a fee to produce across someone else's platform. Now because we don't have to invest in platforms and vessels upfront, this is a very capital efficient model. It also allows us to get our projects on stream very quickly, normally in less than 18 months. So, this model can drive very strong economics. And later in the presentation, I'm going to show an example, which is our Odd Job field to give you an idea for the scale of the projects that we like to do.

Now, we have a large inventory of exploration prospects in the Gulf of Mexico. It's about five years drilling activity. And these projects are similar to the types of projects that we were doing at DGE, where we had a 62% probability of success in exploration. So, these are low-risk opportunities, and I'm going to show you an example of one of these prospects that we are very much excited to drill in 2019.

Now, key to these success rates, the high success rates in the Gulf of Mexico is the seismic data. And seismic data is continually evolving and it's evolving still today. So, this is a map that shows -- the top right shows the map of the deepwater Gulf of Mexico. And if you look at the white shading, this is where there's a salt canopy present. So, it's over a half of the area in the deepwater, has a canopy presence.

So in the 90s and the 2000s, it was almost impossible to get an image beneath that salt because of the technology that we had. So if you wanted to explore a subsalt, it was a very risky business. So, what else in the seismic was designed or developed to address, specifically address this problem? And it's not a 100% solution. There is still areas out there that we can't imagine, even with the wide-azimuth data, but it's a very big upgrade. And I'm going to show an example of this and the seismic line that's in the inset below the map.

So if you look on the left-hand side, this is a wide-azimuth -- excuse me, this a narrow-azimuth line. And what you're looking at, the blue outline is where assault body has been interpreted on the seismic. And you can see the salt has an overhang, which is a pretty common occurrence in the Gulf of Mexico. If you go outboard of the salt to the left, you can see layers in the seismic data and these represent sand in shale sequences where we would expect to find hydrocarbons if they were in a trapping position. So the way we generate a prospect is we map these around until we find a trap. And then -- then we have a prospect. So as you come in from the basin toward the salt body, you can see that when you go under the overhang, the layers disappear. So there is no data or no image below the salt.

So if you look on the right hand side, this is the same lines, but this is wide-azimuth data and look at the reflector and the seismic data that's been circled and you can see it out in the basin and what this is? This is a known producing horizon in the area, and you can trace it under the salt overhang all the way up to the face of the salt where you would think it was trapped. So this is a lower risk prospect where we had no image before. So this was a big deal for our industry and when, the majors got this technology, they immediately went out to the very deep part of the basin and they started exploring for the deep Miocene and the deep Wilcox because it was such a high potential play. But they pretty much ignored the younger section. So Kosmos and some of the other independents have taken this wide-azimuth data and we've gone back and we are exploring the younger section and we're having good success.

So if you think about it. You look at the area we're talking about in the section available to us and the technology is continuing to change. So this is an area that we're going to be able to exploit for a good while, now the seismic vendors, they're beginning to shoot the next generation of seismic data, which is called nodal data. And this is going to be another upgrade on the subsalt imaging, it's just being just being shot, but it's going to come available over the next few years and this is going to open up more opportunities for us.

Okay. So we're confident that we're going to be able to generate prospects using the technology that we have. This is another map of the Gulf of Mexico. And if you look at the small blue blocks, these are the leases that are currently held by all companies in the deepwater. Now 10 years ago the number of blocks that were held was 4,500. Today, the number of blogs held is around 1,500. So there is two-third less held acreage in the Gulf of Mexico today than there was 10 years ago. And of the 1,500 blocks that are currently held, a third of them are going to expire within the next five years.

So this gives us a lot of running room to go out to lease sales, very little competition lease prospects with low bonuses and I would say, Andy, commented on this. But I think that the competition is less in the deepwater than it's ever been even since I've been out there, which is since the mid '90s. So it's a really good time to be trying to acquire prospects.

Okay. Now I want to talk about the Delta House area. And this is a good example, the hub-and-spoke model that we like to do when we come into a new area. So Delta House itself is a floating production facility. You can see the picture of it here on the slide, and DGE and several other independents collaborated to have this facility built in 2012 and the purpose of it was to develop three discoveries that we had at the time.

Now we had an interest in in two of the three discoveries, so normally we would have used existing infrastructure, but we didn't feel like the existing and infrastructure had enough capacity to service the size of deals that we've found, so we decided to build new. But we did bring in a private equity company to finance and own the structure, so we didn't invest in the infrastructure upfront and we paid a fee to produce across it. So it's consistent with our capital efficient model.

So the vessel came on stream in 2014 and we continue to explore around it and now there are eight fields that are hooked into the Delta House and we own an interest in four of them. So I've listed the fields that we own an interest in on the slide, and you can see the reserves, these are the gross 2 P ultimate reserves and all these fields adds up to 326 million barrels. So it's a very material area to us. And in fact it's one of our favorite areas to explore. So we have very favorable terms for processing across Delta House, because we were an anchored tenant.

The capacity of the vessels, 95,000 barrels a day right now with the eight fields going into it, it's almost full. But several of the fields, especially the big anchor fields that we started with, they're over five years old, and they're starting to decline. And as capacity frees up, what we intend to do is fill that capacity with more production from Odd Job or from other prospects that we've identified in the area.

So this slide's about Odd job, the Odd Job field is located 15 miles to the east and about 6,000 feet of water and we have a high working interest in Odd Job being 55% to 61%. The field size is 76 million barrels. And we drilled our first productive well in 2015. After we had the discovery, we built a subsea system that will service up to four wells. We hooked the first well and brought it on stream in 2016. And then in 2018, we drilled two additional wells, one of which we completed three months after the well was drilled and the other is going to be completed in '19 and Andy mentioned that it's coming on stream in his development section.

So the two wells that we have currently producing at our job, they're producing a constrain rates of about 14,000 barrels a day. Now they're capable of producing 20,000 barrels a day. So that's one of the ways that we're going to be able to keep this capacity full just by opening these wells as capacity becomes available.

The economics at our job are very good. The finding and development cost is around $11 a barrel. The lifting costs this year were about $10 a barrel, but we have a declining PHA fee structure that goes down with the more volume that we produce. So that rate is going to step down again in 2020 and we expect our lifetime lifting costs to be closer to $6. We couple this with the fact that we receive HLS pricing, which is about $3 below Brent and much higher than WTI. This is going to be very high margin production coming from Odd job.

Now outside of the Odd Job field, we've identified and acquired interest or four prospects. And the total potential from those four prospects is 80 million barrels and you can see the polygons on the map that show where those prospects are located. These prospects are amplitudes, they're low risk, and we're going to drill in the next three years. One of them money penny is going to be drilled in 2019.

Now money penny is just a deeper pool test on the Odd Job structure. So if it's successful, it's very close to the infrastructure minimal cost to hook it up and we expect the finding and development cost to be even less than Odd Job and $8 a barrel. And that kind of demonstrates how the hub-and-spoke model becomes more efficient if you have the infrastructure in place and you continue to add wells.

Okay. Beyond Delta House, we hope to employ the hub-and-spoke strategy again in the Garden Banks area. Now the anchor prospect in this new area is called Resolution and this prospect has a reserve potential of 100 million to 200 million barrels, so it's sizable. So let me back up and talk about how we got involved or how this prospect was generated and how we got our interest in it. Garden Banks, this area, this prospect is located in the western part of Garden Banks. In eastern Garden Banks, it's been one of the more prolific areas for production in the Gulf of Mexico. The Auger basin was discovered in the mid '90s and has produced 600 million barrels to date. So it's been a very strong production area. So you would hope that you would have similar potential in Western Garden Banks, but there's a lot of salt there and the salt is very thick and it was one of these areas where even with wide Azimuth data, it was difficult to image.

Now there's been one discovery which is Gunnison, 10 miles south of resolution. And -- but other than that, there's been very little drilling in the area. So the one discovery is positive, because we know there is a working petroleum system in the area. So BP got interested in this area and they figured out through reprocessing how to image below salt. And from this work, they generated resolution and they also generated four other prospects in the area.

And the total potential from these other prospects is 340 million barrels. So in total, you're talking about exploration potential of over 500 million barrels in the basin. So Kosmos and BP have agreed to a 50/50 partnership to exploit this area, and Kosmos is going to be the operator of the project. So this collaboration between us takes advantage of BP's knowledge of sub-salt, imaging and seismic reprocessing and it also takes advantage of our expertise in doing subsea tiebacks quickly, safely and cheaply.

Okay, so I want to talk a little bit more about how BP was able to image resolution. A lot of companies had worked in this area, but no one else could figure it out. So what did they do different? There are three existing wide-azimuth datasets that have been shot over this area. And what the other companies were doing is they would take one of these sets and they would try to reprocess it to improve the images and they just couldn't get there.

So BP took all three of the data sets, even though they were shot but different seismic companies and they merge them and then they reprocess the merge product. And in doing this, they were using a new algorithm for reprocessing called full waveform inversion, and what this does is it -- it's a new way or an innovative way of building a velocity model that improves the sub-salt image, but it also cuts way down on the computing time that's required to do these big processing projects.

So what used to take a month, they can do just in a matter of days now. So we were very impressed with the results that BP got from the reprocessing at resolution, obviously, that's why we got in the deal. But this is not the only place that they've used this technology, they recently announced that they added significant reserves at the Atlantis and Thunder Horse fields and these were fields that have been producing for 10 years, very large fields and they went in and they were salt present, they processed the day they may found large areas within the field that hadn't been exploited.

So they are getting -- they are having a lot of success using this technology in the Gulf. And we are very fortunate because Kosmos had this pre-existing relationship with BP that we were able to tap into this world-class expertise. So this shows the subsurface of resolution, and what you're looking at there the blue again is the salt body, you see it's a very thick salt section which was part of the processing problem. There are amplitudes underneath the salt and the amplitudes do conform to structure, which is a good thing that you like to see a good characteristic that you like to see from an exploration standpoint, because that tells you there is a higher chance that its hydrocarbons and it raises your probability of success.

So there are four objectives that we're looking at developing here in this prospect. And the first well is going to target the orange and the green, the shallower horizons, and we think this is a one in three chance of finding a 108 million barrels. So if we're successful there, we're going to sidetrack that well down dip and we'll test the blue and the red horizons, which are going to raise the prospect potential to 200 million barrels.

So the other prospects that BP has in the area, there also amplitude supported prospects. So we can take the results from resolution and we can calibrate the geophysics over there and we can lower the risk on these other prospects and if we're successful here, we would expect to drill them in the 2020 to 2021 time frame. So we're really excited about that prospect.

So outside of resolution, we have an interest in 20 prospects. And we added 15 of these prospects in the last six months, since we became part of Kosmos. And that's more prospects than we ever added in a shorter period of time when we were Deep Gulf Energy and we did not compromise on the quality of the prospects, these are good prospects. So what happened that enabled us to do that. Well, we were talking about it today and I just want to summarize: Number one, the seismic technology is getting better, so it's easier to generate prospects; Number two, the half of the people that were here 10 years ago are gone, so there's less competition and it's easier to acquire prospects; And then third, we're taking advantage of these pre-existing relationships that Kosmos had with the Supermajors, and this is opening up new technologies and prospects for us that we just didn't have as a stand-alone private equity entity. So, this is a great opportunity for the Gulf of Mexico business unit.

So going forward, we expect to do four prospects here, and we'll average around a 30% working interest. And in 2019, we are going to target from the four wells we're going to drill in the Gulf of Mexico, 100 million barrels net of exploration potential. So that's significant when you consider that the total reserves we have in the Gulf of Mexico 2P Reserves right now is 80 million barrels. So this just shows that through the exploration program that we come up with, we have the opportunity for step function growth if we have success in the program.

Okay, this slide looks at where we are six months after closing the DGE acquisition. And the red and blue line, what -- the blue line is the purchase price and then the red line is the current 2P PV10 at $60 Brent. So on that basis, we delivered a 1.5 ROI to-day. But I think the real value of the acquisition was the platform that we created that can deliver growth for many years to come through our exploration program, and this was what Andy and I talked about the first time we met over a year ago, when we first started talking about the combination. And we were wondering how can we make one plus one equals three or can we? And can we make this investment in the Gulf of Mexico, not a 1.5, but well over a two, which was what we both wanted to do.

And it's early now, but it's very satisfying to see our vision start to unfold, and maybe it's sooner and better than either Andy or I had anticipated when we first met.

So now, I'd like to hand it over to Tracey to talk about some equally attractive opportunities in Equatorial Guinea.

Tracey Henderson -- Senior Vice President, Exploration

All right. Thanks, Richard. So I'd like to begin with a little bit of my history with these assets and why for me Equatorial Guinea is unfinished business. So I was part of the team at Triton Energy, that unlock this basin with the Ceiba Field Discovery in 1999. And it was a really exciting time. The discovery actually opened up the Cretaceous Play in West Africa, and that's something that we've continued, those learnings continue to leverage around the Atlantic Margin ever since.

So Ceiba was followed by several additional discoveries, now known as the Okume Complex. And this was before Triton was acquired by Hess in 2001. In addition to myself, there is a number of Kosmos -- the Kosmos team today, that we're involved in developing and operating these fields post discovery. So there is a high level of institutional knowledge at Kosmos for these assets. So through the opening of the basin and the subsequent follow-on exploration success. The key geologic play elements in the Rio Muni Basin were de-risks, and this included the presence of the source -- an oil prone source rock, robust traps and commercial slope and channel fairway reservoirs.

So when the idea was raised to reenter the basin, I thought really interesting. So let me show you why. One of the tools that we use to understand a basin's exploration history is a creaming curve, and this is plotted on the slide that you're looking at on the lower left. And a creaming curve is a diagram that we used to represent the relationship between cumulative resource growth from discoveries and exploration wells drilled through time. When a well approves a resource discovery, the volume is plotted as a value on the Y-Axis, overtime, which is plotted on the X-axis.

Now, there is two data sets posted on each of these graphs on the lower portion of the slide, the Equatorial Guinea history in light blue and its southern neighbor, Gabon, in grey. And I've chosen Gabon because the northern half of Gabon is actually part of the same basin as Equatorial Guinea with the Rio Muni, and because it's a really good example of the base, the way a basin typically evolves over time once commercial volumes of hydrocarbons are discovered.

So, let's focus on Gabon for just a moment. You can see, if you look at the curve, the initial discoveries made in the 1950s and then steady increases over time as new resources are discovered. If you compare that to the drilling activity on the right part of the lower slide, you actually see what was drilling -- what was driving this and that's drilling, many wells drilled through time. And one interesting thing to note, if you look at that grey curve, is that there are plateaus in it that actually represent a play that's being matured and drilled out. And then if you look at the vertical ramps, those are where new place have been opened.

Now, if you compare that to Equatorial Guinea, the creaming curve shows the discoveries in the 1990s and early 2000s and then it effectively goes flat. So, this means one of two things, either we were so smart, we found everything that there was to find before we left or exploration effectively ceased. Now if you look at the drilling curve again to the right, you see why no new discoveries were made and no new play concepts opened. Very few exploration wells were drilled post 2001 and no new discoveries were made as a result.

These low activity levels and the slope of the creaming curve are not typical in the way a basin evolves over time and therein lies the opportunity. The basin has effectively been frozen in time from an exploration perspective. And while the original exploration campaign conducted by Triton, opened the basin and it delivered world-class discoveries, it was limited in scale and scope. Drilling was confined to less than 1,500 meters water depth and constrained by 1990s vintage technology.

The program didn't have the benefit of modern day exploration technology tools or thinking. So today, I'm excited to tell you about the potential we see, and our plans to explore the basin with new ideas and new tools. So, following on from that previous slide to positively change the slope of that creaming curve in Equatorial Guinea, we have to first to drill more wells and second, discover new fields.

We've identified a number of prospects and new concepts to enable us to do this, including an ILX opportunity in legacy discovery called G-13. In terms of geology, G-13 is a proven play, consisting of three anticlines with Upper Cretaceous reservoirs and a large undrilled -- and a large undrilled stratigraphic component, which provides material upside. The G-13 field includes four previously drilled wells, two successful and one unsuccessful by Hess and Triton in 2002-2003, followed by one by CNOOC in 2014.

These wells have actually today proven up around -- to around 25 million barrels of oil equivalent with a 500 meter oil column. So, I was still working the basin with Hess, when we discovered this field and I do remember the challenges. The imaging was more complex than what we experienced in Ceiba and Okume, and we were focused on testing the structural trap. At the time of the discoveries, the size of the resource and the distance -- a relative distance from Ceiba and Okume, meant that these could not compete for facilities and capital, and processing capacity on the facilities at the time of discovery.

Today, we have a calibrated well database and in 2018, we acquired a brand-new 3D seismic survey. This data has given us a much clearer image of the depositional system that delivers reservoir sands from the outboard across the field. And it's enhanced our understanding of the trap model. It's this new information that has actually allowed us to identify that the previous wells were drilled and what we now believe is the edge of the reservoir Fairway. And because of this, we see considerable upside to the discovery.

This, together with the stratigraphic element, increases the resource potential to around 200 million barrels. And in addition to G-13, there are several other prospects on the same geologic trend that we expect to mature in 2019. So, as Andy said, G-13 is an existing discovery on Block S, and this is one of the exploration blocks that we picked, that we licensed from the government at the same time as the Ceiba and Okume fields were acquired. And today, we have the facility capacity to tie this resource back to the Ceiba FPSO. We expect to spud this well G-13-4 in the second half of 2019. And upon success, we plan to conduct an accelerated phased tieback development to the Ceiba FPSO and would target first oil in 2021. So with an F&D cost of approximately $15 per barrel oil equivalent, G-13 is a prime example of the near field infrastructure led opportunities that we highlighted, when we announced the acquisition.

So this slide, looks at the returns we've generated from the EG acquisition, 15 months after closing. We've already $258 million in cash dividend since the acquisition, which is a return of 1.1 times our purchase price. When adding the remaining 2P reserves at $60 Brent, our return increases to around three times. And G-30 alone could increase this to over 3.5 times with further upside to come.

So with that, I will hand it back to Andy.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Well, thank you, Tracey. I'd like to begin our first Q&A session by handing over to Jamie, our head of IR, who will facilitate the session. He is going to take questions from the room. Michelle and Meg have got microphones on other side to help and from those watching on the web.

So, Jamie over to you.

Questions and Answers:

Jamie Buckland -- Investor Relations

Great. Thanks, Andy. So, we'll take a few in the room. We've got a couple on the phone, I think so. If you could just raise your hand and let everyone know where you're from and what your name is, that would be great. So, who's got some questions?

So, Meg or Michelle? Who's down there at the front?

Mark Wilson -- Jefferies -- Analyst

Hi. Thanks for that. It's Mark Wilson from Jefferies. Thanks for the details on the Gulf of Mexico program. I was just just checking on the Garden Banks area. Is the infrastructure in and around the existing discoveries of

Gunnison and Dawson?

Richard Clark -- Senior Vice President, Gulf of Mexico

The Gunnison field is late life and it's -- there is a spar there at Gunnison and the scale, that might be a good option or we could also do a Delta House type facility where we would build the new facility, depending on what level of success we got, how many of these projects are going to work. So, I think it's a good situation since we've got multiple options out there.

Mark Wilson -- Jefferies -- Analyst

Okay. And the same question you show in the latest slide 41, old field?

Richard Clark -- Senior Vice President, Gulf of Mexico

Yes.

Mark Wilson -- Jefferies -- Analyst

Potential hub in the (inaudible).

Richard Clark -- Senior Vice President, Gulf of Mexico

Old field is actually very close to Devils Tower. So it's within six miles of a host platform that we're using for Kodiak. So this would be -- it's kind of another hub type opportunity for us.

Mark Wilson -- Jefferies -- Analyst

Okay. Thank you.

Jamie Buckland -- Investor Relations

Other questions in the room? So, Thomas?

Thomas Martin -- Numis Securities Limited -- Analyst

Hi. Thomas Martin from Numis. I was wondering -- on the slide, we spoke about the ESP typical economics for the Gulf of Mexico. Is that presumably sort of success case economics, and do you have an idea of the associated success rates? Are we thinking near 100%, or is there a material failure rate with those work programs that we should think about? And then I have another one? The 62% chance of success that you mentioned, just to clarify, is that a geological or a commercial chance of success? Is there any material difference between those two terms?

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

In this case, it's -- the fields that were -- all of the fields that were evolved in that track record were commercial. They made money.

So, 63% is the commercial success rate, yeah?

Thomas Martin -- Numis Securities Limited -- Analyst

10 out of 16 wells developed?

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Yeah.

And on the ESPs, this is the outlook from 100% success. I think from that sort of proven technology perspective now, the ESPs are much more liable. So you've got confidence in the targeting in terms of the opportunities set. I think we will see variability on the amount of uplift that we get from some are going to do better, some are going to do not so well. But I actually think on average the programs we talk about the five targets we've got for this year, that's the average that we would expect from them. And then we've got another sort of nine that we would go to.

The other thing that we didn't mention on the ESPs is that because you're not using the gas lift to that point, there is an additional uplift you get from being able to use the existing gas lift across the other opportunities. So this is kind of a win-win, it generates much greater uplift capacity in the field. And that was one of the big things when we came through, added in the purchase from Hess is that it was gas lift limited has decided not to move on and invest anything in it, and therefore, the ESP program was sort of follow the objectives we just decided not to invest.

So I look at it in my history, it's -- what Apache did when they picked up Forties from BP, they did a stunning job at holding production flat at very low cost because BP had decided, that wasn't going to go after the ESP project. So it's pretty similar to that, someone is going to do better, someone's going to get the worst, but on an average, I think we're going to do pretty well.

Jamie Buckland -- Investor Relations

Okay. One more in the room or in the middle, and then we'll take a couple on the phone and then we can mix it up. In the middle.

Alwyn Thomas -- Exane BNP Paribas -- Analyst

Hi, Alwyn Thomas here from Exane. Just couple of quick questions for me. It's certainly on the slide on Equatorial Guinea sort of lack of drilling, I just want to ask if there's anything given the fiscal terms that whether they've improved materially? Since you entered the long core recently and whether that's a part of the reason that hasn't been not much drilling there, how they look now? And on the ILX side in the Gulf of Mexico, if you do make discoveries -- if you got enough CapEx flexibility baked into the budget to be able to follow-up on those potential prospects or leads quicker? Thanks.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

If you look at the Gulf of Mexico. First, we've been modelled going forward in the the capital outlay 50% success rate. So that's sort of slightly less than we've averaged to-date 63%, but the capital lay on that basis is built-in, so we put the capital in. I think the only caveat around that was if we had big success at resolution, where you ultimately create opened up that new hub, we would see that as being one of the things that would differentially out, but that would be beyond the sort of two-year time window that we've looked at. So, I see we put in the capital for the predictable success, if we have the upside from it. I think it'd be a great problem to have.

On Equatorial Guinea, I think it's just -- it's one of those sort of curiosities of history really of why things didn't get done. Post the acquisition from HAAS of trying there were things that were there Tracey, but actually went into their developments unit and they got developed and actually has did a great job with the development of it. They did a very, very efficient development say with Okume, but they just didn't explore because they didn't regarded as being an exploration opportunity, and literally it sort of sat in the freezer for 14 year.

Tracey Henderson -- Senior Vice President, Exploration

Right, they went straight into the development department it has, and they really didn't focus on the further exploration at all.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

So no new seismic shots from --

Tracey Henderson -- Senior Vice President, Exploration

97 --

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

97 -- yeah, so almost 20 year-old seismic. So that in itself creates a massive opportunity because of the uplift. And actually, you've got a fresh set of eyes coming to look at it and actually the set of eyes that own the initial exploration play.

Tracey Henderson -- Senior Vice President, Exploration

Correct.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

So it's -- not to do with fiscal terms and actually sort of, that was good as have been, a good fiscal terms actually, the good fiscal terms. So it's just about something that was existing but hidden and then G-13 is a great example of something of a 500 meter oil column, it didn't get developed, because of the time it didn't compete with the near field drilling in cyber and Okume and actually it's a great opportunity for us.

Jamie Buckland -- Investor Relations

Right. So I think we're going to go to the phones. So if we can get that (inaudible) we got two calls, one from Capital One and one from Raymond James. So we'll take those if we can.

Operator

The first telephone question is from the line of Richard Tullis of Capital One Securities. Please go ahead.

Richard Tullis -- Capital One Securities -- Analyst

Hey, thanks. Good afternoon to everyone on location. For Andy first. Andy what do you envision the higher risk ranked wildcat exploration effort kind of fitting into the overall company strategy over the next couple of years.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

It's interesting, it's core to what we do is the first thing. So our most strategic perspective is core to what we do. We've actually drilled 14 basin opening wells in the history of Kosmos, which is actually 14 years that's sort of one per year. As Tracey talked about the -- we built the prospect inventory over the last couple of years with real vigor, we shot 15%, 16% of the industry's proprietary seismic. After Total and Exxon, we acquired more acreage than anyone else in 2018. And so we've now got to the point where 2020 on, we've gone two high-quality tests per year and it's quality through choice. We build the portfolio now we're genuinely we can pick the very best and drill them.

So if you look at the basin opening and we've actually sort of never had a better portfolio. And actually, we've now got the cash flow coming for the company to sort of to deal with success, as well. And I think that's a very important point, the trading the resources, one thing as shareholders you want to see is being able to monetize. We've now got the balance sheet and the cash flow to actually continue with success. So I think we sort of never been better is what I would say from a strategic perspective and we've now got a portfolio that we can really leverage.

Richard Tullis -- Capital One Securities -- Analyst

Thank you, Andy. And then just lastly, perhaps for Richard or Tracey. For the subsea prospects that were mentioned in the Gulf of Mexico, if possible, could you please provide rough volumes of the oil produced from the shallower zones historically?

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Richard?

Richard Clark -- Senior Vice President, Gulf of Mexico

Are you talking about -- I'm sorry, I don't understand the question.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Shallower (inaudible) Richard, what do you mean by that?

Richard Tullis -- Capital One Securities -- Analyst

I guess you know since you've gone below the salt, I imagine it was oil probably produced above the salt over time. I was just wondering in those same prospect areas, what was the volumes above salt?

Richard Clark -- Senior Vice President, Gulf of Mexico

Well in Mississippi Canyon where we were looking at like odd jobs, there's been tremendous production above salt, that was one of the early areas where the majors got involved, there has been. I don't know billions -- a couple of billions a barrels over there. If you go over into Mississippi -- over into Green Canyon, if you go to the North, a lot of the production near the Flex trend was above salt. And then as you come out to Southern Green Canyon, most of that was below salt and that's one of the areas that we're interested in exploring beneath salt.

And then in Garden Banks, the auger Basin was -- I mean there's solid there, but it's not really a couple of the fields are sub-salt, but the biggest field is not really sub-salt. So it's been a mix, it's hard for me to generalize, but you --

Tracey Henderson -- Senior Vice President, Exploration

It's still 1 billion barrels.

Richard Clark -- Senior Vice President, Gulf of Mexico

Yeah, it's a lot, billions of barrels.

Richard Tullis -- Capital One Securities -- Analyst

Thank you. That's helpful. Just trying to size up the potential prospect there. And that's all for me. Thank you.

Richard Clark -- Senior Vice President, Gulf of Mexico

Great. Thanks, Richard.

Jamie Buckland -- Investor Relations

Maybe we'll take the one from Raymond James on the phone as well, please.

Operator

The next question is from the line of Muhammed Ghulam of Raymond James. Please go ahead.

Jamie Buckland -- Investor Relations

We can come back to that one. So we've got a few more minutes before the operator will take another couple in the room. So we'll go with Dave and then Mark, you can have a second go in a minute.

David Graham -- BMO -- Analyst

Hi, it's David Graham from BMO. One for Andy and it's on your statement this morning and again that you've covered it again in the presentation, but around the sell down in Mauritania and Senegal, it's a very optimistic and positive message. So, can I assume that initial interest there has suggested a price that you'd be very happy with them, so perhaps you can comment on that. And then also just give us an idea of timing there.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

We're going to talk about Mauritania and Senegal after the break, but I'll give you a little preview, if you like. I think one other things that's most important is to sort of understand the scale of the resource that we've developed and why now. I think when we first talked to you about LNG Mauritania and Senegal, it was around 5 million ton per annum project, so yeah, relatively small, but still big from a Kosmos perspective. We're n ow through appraisal success, ongoing exploration. We've got a resource there that BP describes as 50 to 100 Tcf gas in place. So this is a huge base and we'll show you some slides, I'm showing you flick through the pack, you've seen how it benchmarks against other basins. There is a 10 million ton per annum project threefold. So 30 million tons per annum. So what is the right scale of exposure for Kosmos to this from a country perspective and from an investment perspective.

So at around 10% is 3 million tons per annum, that's a significant scale. You scale it again something like oil search, we think as a $10 billion market cap, it currently has around 3 million ton per annum net. So this is sizable. So part of it is about what's the right scale for Kosmos to go forward with. And then the second is now is a good time, we've reached value inflection point with the FID of Tortue. We have BP during the pre-FEED work on two more developments, this is moving forward. And so now is the right time for us to bring somebody in that we'll see that value. And I think, I'm bullish on LNG, I think there is -- I shall as that -- shell have that -- the sort of LNG session today, they're talking about even more growth and I think they were a year ago. So now is certainly a good time. And in terms of the process -- we're starting the process David. So do I have a number in my head? No.

We know what is worth, and I'm sure you can figure that out yourselves. You can do math just as good as I can from prior deals. But we believe it is strategic for the industry because of its scale and its strategic, because there is clear development plan in place now. And as I'll show you after the break, the concept we're using it replicable. It works on Tortue, it will work on Yakaar Teranga, it will work on BirAllah, and it's cost competitive. So you put that together with a competent operator, a great development scheme and a cost effective approach against a market, which is opening up. This is I think strategic. So in terms of pricing, now we know what it's worth, you can figure it out. We're going to test the market, we've had several unsolicited approaches. And in terms of timing, the proceeds maybe in '19 and maybe in '20, we've been -- we'll work the process through.

Jamie Buckland -- Investor Relations

So we'll take our second --

Mark Wilson -- Jefferies -- Analyst

Yeah, thanks, Mark Wilson again, Jefferies. Just wanted to go back this the ILx in the Gulf of Mexico. Maybe some timelines so Nearly Headless Nick is that now FID-ed or when is the expectation for that? So --

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Yeah, Nearly Headless Nick is FID, and as we showed you on I've got which slide it is -- it will start up in 2020. As I end the 2019 --

Richard Clark -- Senior Vice President, Gulf of Mexico

Early '19.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Early '19.

Richard Clark -- Senior Vice President, Gulf of Mexico

Late '19. Yeah.

Mark Wilson -- Jefferies -- Analyst

Okay. And are there any other competing developments that you don't own that are developing back to nearly to Delta House.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

No.

Richard Clark -- Senior Vice President, Gulf of Mexico

Everything that's tied back is shown on right now everything that we know about.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Great, Anish.

Anish Kapadia -- AKap Energy -- Analyst

Hi, it's Anish Kapadia at AKap Energy. I had two questions. Going back to the Gulf of Mexico again, so you talked about full prospects this year. I was just wondering if you could give the details of the other prospects that you haven't mentioned just the timing and the approximate size.

Richard Clark -- Senior Vice President, Gulf of Mexico

Okay.

Anish Kapadia -- AKap Energy -- Analyst

And then second question on Ghana. Few years ago, when we were talking about Ghana, there was the potential at Jubilee getting to over 150,000 barrels a day. It seems to have been struggling a bit in Q4 and again in Q1. Can you just give a bit of an update on kind of the outlook for the Jubilee over the next few years. And is that the potential to test the capacity, and then is there a potential to actually get significantly above the current capacity?

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Yeah. I'll do Ghana and then you can do GOM, Richard. Yeah, It'd be good to sort of give actually some detail on Jubilee. So the vessel capacity is 120,000 barrels of oil a day, it's currently gas constrained at the moment, so it's not liquids constraint it's currently gas constrained at the moment. And with the current GLR of the wells, you can get about a 110 through it. So if we take a perfect day, it will do about 110. The operators forecasting 96,000 barrels of oil a day which sort of suggests an 88% up time of the gas system. So there are two positives in that story. The first positive is actually to get to 120 the liquids throughput, you've got to uplift the gas right. And we have plans that we're working with the operator to do just that, and that is part of the process of getting up to that 120,000 of liquids. And then to sort of sustain it at reliable level, you've got to get the the uptime up and that is again part of the focus that we're working with the operator.

And incidentally, if you about 2018, the TLP was about a planned downtime around 10%, the gas system was probably not doing much better than 88%. So actually, we're forecasting the sort of the same performance in '19, but real opportunity to improve. And that's what's going to get as there. So through the year, Anish, you're going to see is improve the gas handling capacity, which will get the all right up, which will get you up to the 120. And then, clearly you sustain it by improving the uptime. So is it where we wanted to be today? Is it where the operator wants it to be there? Probably no. But I actually got clear plans to actually move it forward. So I think that's sort of the Jubilee story, and yes, it can do 120, yes, it is about maybe the gas capacity up, and yes, it is about getting more reliable. Okay? Is that clear. All right, good. Now Richard, you want to do the GOM.

Richard Clark -- Senior Vice President, Gulf of Mexico

So we're drilling four wells in -- that we have that we have planned. And I talked about resolution, it's 200 million barrel potential, Moneypenny, which is the deeper pool tested Odd Job that's 20. Oil field is tied back in kind of in the Devils Tower, Kodiak area and it's 30 million barrels. And then there is a Gladden deep which is near one of our existing prospects. It's a very shallow well and very cheap, and it's 7 million barrels.

Jamie Buckland -- Investor Relations

Great. So I think we're going to take a break there. We'll come back at 3:45, so that gives everyone in the room and on the phone 25 minutes and we'll start, there's plenty of opportunity to ask questions again at the end. So if you've got more, we'll take them all them. Thanks very much.

(Break)

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Okay. Well, thank you, everybody and welcome back. One of the points I made in my opening remarks was around what makes Kosmos unique. A key element of the Kosmos DNA is our ability to move resource from discovery to production quickly regardless of whether it's oil or gas. This rapid cycle development differentiates Kosmos from its peers in delivering value from basin opening exploration.

The world scale gas discoveries we've made offshore Mauritania and in Senegal, are an example of this strategy in action. On opening the basin in -- with Marsouin and the Tortue discovery wells, three things were immediately apparent.

First, the resource was clearly world scale, sitting today at around 50 Tcf to 100 Tcf of gas in place. Second, an aligned super major partner was required to provide the financial capability and the capacity to drive early competitive development. And third, the first value inflection point for the assets had been reached. We, therefore, quickly executed a highly focused, farm-down process that resulted in BP joining the partnership, providing Kosmos with around 2.5 times multiple on our initial investment. And allowed us to retain around a 30% working interest across the entire basin.

With the right aligned partnership in place and Kosmos benefiting from substantial exploration appraisal and development carries from BP, we set about rapidly establishing the true scale of the resource and quickly, driving the project to the next value inflection point, the final investment decision on the Tortue LNG project.

Tortue is the first of what we ultimately expect to be 3 million ton to 10 million ton per annum projects. The Tortue hub, the BirAllah hub in Mauritania and the Yakaar Teranga hub in Senegal is a demonstration of how basin opening exploration success, when executed with a clear strategy focused on monetization, can deliver asymmetric returns to shareholders. The purpose of this section of today's presentation is therefore to articulate the substantial value of our Mauritania and Senegal assets, and detail our plans for the assets going forward.

There are four points that I'm going to highlight. First, the scale of the resource. As BP our partner in the basin presented in their recent Capital Markets Day, the gas in place across our blocks totals between 50 Tcf to 100 Tcf in place. Kosmos owns around a third, 15 Tcf to 30 Tcf net to our interests. The significant gas resource is one of the largest undeveloped gas accumulations globally, sufficient to underpin around 30 million tons per annum of LNG liquefaction or 10 million ton per annum, net to Kosmos, with the first 10 million ton development now under way following the FID of Tortue late last year.

Second, the competitiveness of the LNG. It was clear from day one, unless these discoveries could deliver a highly competitive source of LNG, they would not be developed quickly. We, therefore, took a highly innovative approach to developing Tortue that I'll show in more detail later. This approach supported by BP has paid dividends. Tortue is now expected to be the fastest ever greenfield LNG project from discovery to first gas.

Third, the assets are covered (ph) by the industry. Over the past few years, large scale gas resource have increased in importance across all fronts. Supermajors and looking to gasify their portfolios. LNG demand is growing rapidly. Security of supply issues is increasingly important for many of the world's largest LNG consumers. These facts have resulted in Kosmos receiving several unsolicited expressions of interest for our Mauritania and Senegal assets.

With the scale of the resources confirmed and the FID at Tortue solidifying the next value inflection point, now is the right time for Kosmos to consider reducing its interest and accelerating value creation from the assets. Finally, the objective for our Mauritania and Senegal assets is to provide a self funded long-term growing source of cash flow for the company.

We, therefore, plan to sell down to 10%. Kosmos will not be leaving Mauritania and Senegal. We intend to retain around a 10% working interest across the basin or equivalent to 5 Tcf to 10 Tcf in resource at around 3 million ton per annum of LNG capacity, a highly material stake for Kosmos. This is the right level of interest given the significant scale in the Mauritania Senegal business going forward.

In just two years, we've gone from a 5 million ton per annum growth project to three projects in aggregate, with a 30 million ton per annum growth potential. It's important to point out that the BP development carry of around $500 million will ensure that Kosmos's positioned is fully funded through first gas of the 10 million ton per annum Tortue project. The 50-100 Tcf gas in place resource across Mauritania and Senegal is centered around three pools, each of which, we believe, has the resource to underpin a 10 million ton per annum project. The blue circle in the middle of the page is Tortue, the first of three expected hubs. Tortue is well defined, FID has been taken and gas is expectin ed in the first half of 2022.

I'll describe the innovative development scheme in more detail later. Importantly, it can be replicated, and we expect to adopt a similar scheme for the other two hubs BirAllah and Yakaar Teranga. During 2019, we expect to drill an appraisal well in BirAllahas and the Yakaar Teranga to further confirm the resource base as we move into pre-feed work in parallel to the well in Tortue. As I mentioned, the resources in Mauritania and Senegal are large. This slide shows the relative scale of the resource and its LNG potential against the other giant international LNG hubs.

Fully developed, we expect Mauritania and Senegal to rank fourth in the world after Qatar(ph)Mozambique and Australia. This slide was fundamental in driving the development concept for Tortue. It was clear that to ensure the rapid development of the resource and thereby create asymmetric returns from this basin of discovery. We needed to positioned Tortue and the subsequent hubs firmly on the left hand side of the cost curve, for Pre-FID LNG projects.

We're very proud that together with BP, we've achieved that goal. The cost competitive nature of the project was one of the key drivers behind the pace of development of Tortue. The project's expected to take just seven years from discovery to first gas, a world-leading timeframe and even more impressive given the cross-border nature of the field development.

This pace is a result of three things. First, the large high quality nature of the resource base to deliver a low cost feedstock. Second, the innovative, cost-effective nearshore development plan for Tortue. And third, the power of a simple aligned partnership that was able to move quicker than many of the traditional multi-partner consortium seen in the industry.

As I mentioned in my introduction, our Mauritania and Senegal assets are regarded a strategic by the industry. We've seen several unsolicited expressions of interest and with Tortue FID completes the next value inflection point has been reached. We believe now is the right time to accelerate a portion of the value we created. As you can see on the slide, this interest is aligned with the super majors, one to increase their exposure to gas. The trend is evidenced by the blue boxes which show recent LNG transactions. Some examples include Shell buying BG, Exxon acquiring both InterOil for over $2 billion and a 25% stake in Mozambique for $2.8 billion.

This is not just supermajors trend. Recently Saudi Arabia's Energy Minister announced ambitions for Saudi Aramco to create a global gas business. Tortue is also well positioned commercially with first gas target in 2022 to take advantage of the growing LNG demand and a lack of supply expected in precisely the same time frame. I started the section by saying Mauritania and Senegal was an example of Kosmos's strategy to deliver early value from our basin opening successes.

I want to focus your attention on the bottom half of this slide, which provides proof points and how we've already generated a return on our investment of around 2.5 times through the farm out to BP. We expect to significantly increase this return through a partial sell down of the assets, post the recent FID inflection point, all while retaining a valuable material stake across the basin, they can deliver a long-term growing source of cash flow for Kosmos. And I want to turn to a video, which shows in more detail that the Tortue development concepts. If we could play the video, please.

(Video Presentation)

Very good. Well, as you know, we announced FID in December. And you will see shortly from announcements and contract awards, the execution of Tortue is well under way. As the video showed, the project utilizes a highly innovative development scheme. So let's look at that in more detail. The first phase of the project is shown in green on this slide, and we'll provide around 2.5 million tons per annum of early LNG volumes. First gas is expected in the first half of '22, which as I discussed earlier, is very well matched with expected LNG demand window.

After a competitive marketing process, BP Gas Marketing has been confirmed as the sole LNG off taker committing to take 100% of the circa 2.5 million ton per annum LNG volume associated with this first phase. This is a long-term contract taking gas from all of the project owners, including the NOCs. The future phases of the project as shown in blue and gray on the slide. Each of these two phases is expected to add around a further 3.7 million ton per annum, targeting 2020 sanction and First Gas in '24 and 2025 respectively.

In total, therefor Tortue will be around a 10 million ton per annum project, which is double the size of the original 5 million ton per annum scheme that we first talked about two years ago. In summary, the concept has the following advantages. It's an innovative development scheme delivering a low-cost source of LNG. It combined standard industry solutions and is therefore quick to first gas and therefore first revenue, and perhaps equally important, it's repeatable, which is -- which will help accelerate the subsequent hubs at BirAllah and Yakaar Teranga. By developing the field entirely offshore, the project can be executed quickly and cost competitively. To drive early production and cost competitiveness, the project utilizes standard industry solutions, including Angola FLNG vessel that will provide low-cost liquefaction and by using an existing LNG tanker, will provide low-cost LNG storage. Placing the vessel behind the Bright Water creates a safe harbor and eliminates the key risks associated with FLNG, the impact of sea states on liquefaction and offloading reliability.

The future phases will utilize platform-mounted LNG modules located in shallow water approximately 30 meters, again allowing fast low-cost construction and easy installation. Finally, by placing the project offshore, the need for a conventional loading jetty is eliminated. The Bright Water itself will use 21 concrete caissons constructed in the facility in the Dakar port and ballasted using rock source in Mauritania, adding important local content to the project.

The scale of the caissons can be seen in the image on the slide. They matched the size of the Arc de Triomphe, as depicted by contract at France (ph). Gross recoverable resources as reported by BP are 15 Tcf. So, more than enough for the 10 million ton per annum scheme and the resources is likely to increase as more wells are drilled. As I mentioned previously, Kosmos's CapEx to first gas is fully covered by around the $500 million per annum development carry we have in place with BP.

In summary, we anticipate that Tortue, of the retained 10% working interest, will provide a long-term growing cash flow of around $150 million per year, net to Kosmos under the conservative price signal assumptions that reflect today's market. This translates to $3 billion of cash flow, net to Kosmos over the life of the project.

So in conclusion, as I emphasized in my remarks earlier, this is a world-scale resource, a 50 Tcf to 100 Tcf gas in place. Tortue is just the start of creating a new major LNG export center, offshore Mauritania and Senegal. Following very low appraisal investments to confirm the final resource amounts, we anticipate there will be two additional 10 million ton per annum hubs developed at BirAllah and Yakaar Teranga. We expect that we'll develop using the same cost competitive design concept as Tortue design one build many.

I'd now like to hand back to Tracy, who will talk through our basin-opening exploration portfolio. Tracey?

Tracey Henderson -- Senior Vice President, Exploration

Thank you, Andy. So, before diving into the individual exploration opportunities, I'd like to take a moment to characterize our basin-opening exploration portfolio.

So first, our exploration portfolio is deeper and more diverse than it's ever been. Second, it's capable of delivering a sustainable prospect inventory with quality through choice. And third, our strategic partnerships with BP and Shell leverage complementary skill sets, while providing development partners upon success. And finally, we expect this portfolio to deliver asymmetric value upside with a sustainable two-well per year program in basin-opening exploration.

So, as Andy described earlier, Kosmos has gone through a significant evolution over the last two years. I joined Kosmos in 2004, and I'm proud to be employee number 10. One thing that hasn't changed over the last two years is our distinctive approach to exploration. From founding the company to present day, our approach has been consistent.

We focus on geographies and geology, where our expert knowledge creates competitive advantage and generating new ideas. This focus ensures that we can leverage our people and their deep knowledge to create advantage -- to create first-mover advantage. And first-mover advantage is key for us and allowing us to enter basins at low cost with substantial running room.

Capital discipline is demonstrated in our rifle shot approach to exploration. But today, we have a deeper prospect inventory than we've ever had historically, which will ensure we are continuously high grading the prospectivity and providing quality through choice for our anticipated two-well per year program.

And lastly, we believe in strategic partnerships. Kosmos is good at many things, but we are humble enough to understand the advantages of good partnerships. Our innovative alliances with BP and Shell leverage those complementary skill sets, while providing world-class development partners. So, 2019 will be a busy year for exploration at Kosmos.

And first is drilling. In Mauritania, we expect to drill the Orca-1 well in the second half of the year. The objective of this well is to prove up the gas resource to underpin a second LNG development at BirAllah. Second, again, seismic acquisition and processing.

Having shot extensive seismic surveys in Cote D'Ivoire, Namibia and Sao Tome, we are focused this year on processing and evaluating the data, and to mature and rank our prospect inventory and where appropriate to select and ready wells for the 2020 program and beyond. And third, new ventures activity. We continue to replenish our exploration portfolio through new ventures activity to maintain and high grade our portfolio and to support a continued -- the continuous two-well per year drilling campaign.

So, I'll start with Mauritania and Senegal. And Mauritania Senegal isn't an -- still an emerging basin and there are significant remaining potential with lower risk as a result of the commercial discoveries. This prospectivity has the potential to deliver additional greenfield opportunities similar to Tortue 2. And then in the second half of the year, as I mentioned, we'll be drilling the Orca prospect in Southern Mauritania.

Our share of this cost is covered by -- is carried by BP. And this prospect is interesting and that it sits on the same structural ridge as Tortue -- as the Tortue and Marsouin discoveries. And in the proven inboard gas play, it's AVO supported and its calibrated by the discoveries along trend. This well will target a gross resource in place of around 13 Tcf, which together with our BirAllah discovery has the potential to support an additional gas hub in Southern Mauritania.

So, as you are likely aware, in Suriname and Guyana, Exxon has made some exciting discoveries recently in the Suriname Guyana basin. Next year, we plan on testing, in Suriname, one of the plays that was opened up in the Guyana basin by Exxon in 2018, which is the carbonate play. The play was opened with a range of one discovery with the well that tested 230 feet of oil pay and a four-way structural trap.

The Walker prospect, which we are currently maturing for drilling on the eastern side of Suriname Block 42 is analogous to Ranger. It has a gross resource of around 250 million barrels of oil, and this well will test a robust structural trap similar to what -- to Ranger, with a source rock actually on lapping the structure, which provides an ideal migration pathway from source to reservoir. The well design has been developed to see whether it is possible to test a second shower prospect in the Cretaceous award channel complex, which is age equivalent to Liza with a single bore-hole.

So earlier, I told you how excited I am to be exploring in Equatorial Guinea. Again, but that was really only part of the story. We have now established an extensive basinal position, roughly 47,000 square kilometers in the Rio Muni Basin, outboard of Equatorial Guinea and into Sao Tome, as you can see, which is the area that's completely highlighted in green on the map. This basinal position was completed with the recent addition of Block 24 and Equatorial Guinea, where we have acquired a fierce (ph) position. We are now operator of the block, with an 80% interest alongside the national oil company, which holds a 20% interest.

We're currently leveraging our knowledge of the inboard plays in Equatorial Guinea that I described earlier and applying that to the outboard. We have approved -- we have proven oil prone source rocks in the inboard that source Ceiba -- at the Ceiba, Okume Complex in those inboard discoveries. And in the out-board, we have active oil steeps on the islands of Principe and Sao Tome.

So additionally, new seismic data has allowed us to map the proven reservoirs from the inboard and ended in the deepwater, where there are large structural and stratigraphic traps that have been identified on the new 3D seismic survey. I'm excited by the significant position -- potential and we are currently high grading and maturing the prospectivity, and we expect drilling to start in 2020.

So in 2018, as part of our BP alliance, we entered Cote D'Ivoire. Cote D'Ivoire is an emerging basin and the deepwater is under explored. Wells drilled in the inboard have actually proven a working source and we believe that similar to the concept that we developed upon entry in the Mauritania, Senegal, that source extends end the deepwater and is likely mature.

2D and early products from our new 3D seismic survey have demonstrated that the reservoir extends into the deepwater and we are maturing a new play concept the basin for fan play. So we're currently identifying the maturing prospectivity and targeting drilling to start in Cote D'Ivoire in 2021. So, as Andy mentioned, our new ventures program is -- has been very active and in addition to Cote D'Ivoire, we also entered another new basin in 2018, Namibia. This is the first basin that we will explore with Shell as part of our alliance, where we formed into PEL39 that you see outlined on the map.

And like Cote D'Ivoire there is evidence for marine oil prone source rock in the deepwater beyond an outer high that actually separates this from the inboard gas kitchen. The block is multiple play types, including carbonates and plastics and both structural and stratigraphic play types. We are therefore leveraging the complementary skill sets that I mentioned earlier, both companies, Shells, Brazilian carbonate expertise and Kosmos's West African knowledge deck clastics knowledge. And we're currently identifying maturing prospects targeting drilling starting in 2021.

So I want to come back to the value that Kosmos attaches to our exploration alliances with BP and Shell. In October of 2018, Kosmos entered into a strategic alliance with Shell to jointly explore Southern West Africa. Initially, the alliance will focus on Namibia, where Kosmos has completed the into Shell's PEL39 as I mentioned on the previous slide. And in Sao Tome and Principe, where we have entered into exclusive negotiations with Shell to take an interest in Kosmos' acreage in blocks 5, 6, 11 and 12.

As part of the alliance, the two companies will also jointly evaluate opportunities in adjacent geographies. Similarly, our strategic alliance with BP has successfully established positions in North West Africa, where first in Mauritania, Senegal, as Andy mentioned, we're rapidly developing our discovered gas and exploring for additional resource. And second in Cote D'Ivoire where we've established a significant position I highlighted earlier. And third in Sao Tome, where we're planning to acquire seismic over two blocks, starting this year. And as Richard discussed earlier, we're also extending that relationship to the Gulf of Mexico. So these alliances are consistent with Kosmos' strategy of partnering with Supermajors to leverage complementary skill sets and then upon success ensuring a development partner that has the capability to fund and rapidly execute a development project.

So as I mentioned at the beginning, our basin exploration portfolio is deeper and more diverse than it's ever been, and capable of delivering a sustainable prospect inventory. Key to this is the depth of our basin opening portfolio, currently with an unrisked prospect inventory of around 15 billion barrels. This enables quality through choice and therefore allows us to adhere to our rifle shot approach to exploration -- to basin opening exploration. Only the best wells will get drilled. And as you can see from the next three year schedule, we expect to drill the Orca prospect this year, followed by two basin opening wells per year starting in 2020.

The drilling schedule showed on this slide is in addition to the ILX opportunities in the GOM and EG that Richard and I described earlier. And as Andy said, the combination of the two programs means that the 2019 program is going to be an exciting year for exploration at Kosmos with six wells targeting 500 million barrels of oil equivalent net to Kosmos, which would double our 2P reserves. So how are we going to ensure that we have the financial platform to do all this? I'll let Tom take that one.

Thomas P. Chambers -- Senior Vice President and Chief Financial Officer

Thanks, Tracey; and good afternoon, everybody. In the next few slides, I'll demonstrate Kosmos financial strength, which underpins our ability to execute the strategy that you've heard here this afternoon. And as many of you've heard me say before this, financial strength is an enduring asset of Kosmos. So I want to start first with the balance sheet, balance sheet strength that goes without saying that a strong balance sheet is a necessary component of our strategy.

Next, liquidity. Liquidity provides a flexibility to act opportunistically. Third, proper debt management, it ensures low cost access to finance. Fourth, our hedging program means we can execute the commodity -- through the commodity price swings. And finally, and not least, growing cash flow with disciplined capital management, enable sustainable shareholder returns. So we have a track record of being good stewards of our balance sheet. This is best example filed by this chart which shows our commitment to low leverage and our ability to maintain significant headroom on our debt covenants.

Over this period, we've experienced significant commodity price volatility. But despite this volatility, we've executed on our strategy, growing the Company's production threefold without diluting shareholders and keeping our leverage in check. For example, when we do increase our leverage as we did in 2018 with the Gulf of Mexico acquisition, we developed well thought out plans for reducing leverage back to levels typically under two times. Our overall target range for the long-term is between 1 and 1.5 times net leverage. In 2019, at $60 average Brent, we expect our leverage to drop to about 1.8 times. With any Mauritania and Senegal sell down proceeds, and then the incremental cash flow from higher oil prices, we expect our leverage to fall comfortably within our 1 to 1.5 times level, which provides the balance sheet flexibility to act opportunistically.

Maintaining a strong balance sheet together with healthy liquidity has been a key part of our financial playbook and a differentiator from many peers. It has enabled us to remain active during the downturn, supporting the drilling program, which resulted in multiple large discoveries while peer companies curtailed activity. It has also enabled Kosmos to acquire top quality assets counter cyclically at a time when many companies had to focus on improved -- improving overstretched balance sheets.

With our acquisition of DGE, Kosmos took advantage of a strong liquidity position to purchase a high quality company in the Gulf of Mexico. I share Richard's enthusiasm for this basin with its huge potential for players with knowledge, experience and financial strength. Typically, we target liquidity around $1 billion, which provides the flexibility and ensures we can manage our business through the cycle and be nimble when looking at inorganic activities. In 2019, at $60 Brent, we expect our liquidity to end around $750 million absent any Mauritania, Senegal proceeds or price upside.

Obviously help from either of these sources results in the double effect of reducing debt while still at the same time increasing liquidity. Part of keeping our balance sheet strong is actively managing our debt maturities. And as you can see on this slide, Kosmos has no near-term debt maturities that will impact our growth plans. We are currently looking to refinance our high-yield bonds, which became callable in the last two years and move that maturity out to potentially 2026, further enhancing our financial flexibility.

In 2018, we successfully refinanced both our reserve base lending facility and our revolving credit facility, both of which were oversubscribed and resulted in lower margins and fees. Our RBL now matures in 2025 and amortization was pushed out four years to commence in 2022.

An enduring part of our financial management is to mitigate the volatility of prices on cash flow through our hedging activity, and therefore ensures we can execute our disciplined capital program. We've been fairly successful, I would say, with our structured approach to having hedged and received around $325 million in cash settlements over the last four-year period. Our philosophy has been and continues to be that we maintain a structured disciplined hedging program over a rolling three-year period, with the goal to protect the downside price scenario while still retaining partial exposure to the upside.

Our rolling program typically targets to have around two-thirds of the current year's production hedged, with up to 50% in year two and 25% in year three. The rolling nature of the program allows us to hedge each quarter, taking what the market gives us and therefore, avoiding speculation.

Before I leave this slide, I wanted to make one mention and you might not have caught it in Richards remarks, and that's in terms of Gulf of Mexico pricing. Right now, our Jubilee 10 and Equatorial Guinea production is priced off of the Brent index. Our Gulf of Mexico pricing is priced off of what we call HLS. It's a benchmark -- it's a posting in the US called Heavy Louisiana Sweet. and it's about -- it's marked about $2 off of Brent. So, very close to Brent. Many people think it's priced off of WTI, which is not, which has almost a $10 differential to Brent.

So, that's an important distinguishment to make and keeps our margins high on the Gulf of Mexico as well. I want to conclude my section by reiterating our commitment to shareholder returns. We plan to use our strong free cash flow to execute our returns-based growth plans, while simultaneously reducing debt and returning capital to shareholders.

In late 2018, we did two things. We announced initiation of a dividend, the first in the company's history, which demonstrates the confidence we have in the platform that you've just heard about this afternoon. We bought back 35 million shares eliminating the shareholder dilution from the DGE acquisition, when we bought back those shares at the end of this past year.

In addition to being opportunistic around Warburg wanting to divest and buying shares at a 40% discount to where they were issued two months earlier for the acquisition, we've addressed an ongoing shareholder concern around Warburg and Blackstone's ownership. With the transaction, we've reduced Blackstone and Warburg to around 20% of our shares outstanding, which is 65% lower than they were two years ago. This has significantly reduced the overhang in the stock and their positions are now in line with our public -- our larger public institutional investors.

With the $75 million dividend, the current yield on our stock is around 3%. The first quarterly dividend of approximately $0.045 per share was declared today and shareholders at the close of business on March 7th will be paid on March 28th. This is around a 6% increase per share from the amount we announced at the time of the DGE acquisition and that's the result as of the share buyback.

So, this last slide is where I'll finish and this is for the analysts in the room who like numbers. This is a look forward to the 2019 guidance broken out into the first quarter and the full year. In the first quarter, group production is impacted by the planned Tornado dry-dock, as you heard Richard talked about and the lower than planned Jubilee production that Andy mentioned in his comments earlier.

We expect this to reverse in the subsequent quarters with full-year production in the range of between 69,000 and 73,000 barrels of oil equivalent. I don't plan to touch on every number on this slide. As you can see, you can go through that yourselves, but we've indicated the key expense lines together with our CapEx forecast for the year, which is expected to be between $425 million and $475 million, as you heard Andy say, which is a 20% reduction from our previous guidance.

And with that, that concludes my remarks and I'll turn the podium back over to Andy.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Great. Thanks, Tom. And thank you to everybody for your time and attention today. Before we open up for the final Q&A, I hope that we've conveyed my excitement and the excitement of the team on the future of Kosmos.

First, we've got a business that's incredibly resilient. Kosmos confirmed its dividend and sustaining CapEx of $35 per barrel Brent. Secondly, as Tom just said, we materially reduced our 2019 CapEx by around 20%, while maintaining our production CAGR guidance from year-end 2018 to 2021 of 8% to 10%.

Third, as I hope we've demonstrated, we made two great acquisitions, not only of these acquisitions in EG and the GOM already delivered significant returns on our investment, they have also created the next chapter of growth for Kosmos with major ILX opportunities in both areas. Fourth, the significant resource we've discovered in Mauritania and Senegal is highly valued.

It has reached a second value inflection point with the Tortue FID. And following several unsolicited approaches by third parties, we expect to sell down our interest to around 10%. Fifth, as Tracey has demonstrated, 2019 is a very active year for exploration in Kosmos. We expect to drill six exploration wells across the portfolio, 500 million barrels of oil equivalent, net to Kosmos being targeted, which would double our current 2P reserves.

And finally, our relationships with the Supermajors are creating differential value for Kosmos's shareholders. We are leveraging our expertise in complementary skill sets across all parts of our portfolio, ILX development and basin-opening exploration.

So with that, I'd now like to hand over to Jamie who will facilitate the final Q&A session. Jamie?

Jamie Buckland -- Investor Relations

So same format, we'll take questions in the room and then we'll open it up for anyone on the line. So, questions in the room.

Operator

(Operator Instructions)

Al Stanton -- RBC Capital Markets -- Analyst

Yes. Good afternoon. Al Stanton, RBC. I was wondering if you could just talk us through the sort of dynamics of the total (inaudible) in terms of what are we already assuming in terms of things like the gas price or at least, the mechanism in terms of whether it's a net-back calculation.

And then in terms of the timing, you talked you could get closer to this year or next year. How do you realize the value of the exploration that you plan to do this year? How do you factor that in? And then, Tom, are you assuming that you pay capital gains tax on any proceeds?

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

All right. Very good Al, let me -- we'll go in reverse order. I'll talk about the capital gains. I think what's interesting about capital gains is around ensuring that you generate the right dynamic with the country, and we've created a very strong above-ground relationship in both Mauritania and Senegal, and actually we've already been through one sell down. We've been through the sell down process with BP, a significant sale.

And we did that in a way where there was no value leakage to Kosmos. And part of that was actually getting ahead of the game with the government, so there's no surprises. I spend with Mike a lot of time actually discussing the strategy for what we did with the gas resource offshore, Senegal and Mauritania with both Presidents.

We were clear, we found something big. We were clear we needed a supermajor and they were clear they needed a supermajor. So, how did we facilitate the process? So, it wasn't about us sort of commercially gaining from the process. It was about the right thing to do next. And we've already started that conversation with both governments about what next in Mauritania and Senegal. And it's clear to me that what next is you need another partner. BP is Great, but actually the scale of what we have today requires another partner. And I think by being in a genuine conversation, I believe that we can ensure that we get to the right outcome with both governments.

In terms of gas pricing, I'm not going to tell you what the arrangement is. I don't think my colleagues in the BP would give me many plaudits for that, if I did tell you. So, what I can tell you is, I think what you want to do is fill out your commercial model for the Tortue. And for the analysts, investors in the room, we have shared a model for Tortue, Tom, which I think is pretty detailed.

I think what we can tell you a little bit more about is the CapEx that goes into that along and actually that will help you get to a better value description. One of the key things is the timing. To first gas, the CapEx is going to be around $3.8 billion. When we first talked to you about it, it was a lower number, around 2.5 something like that.

We want to change. The big thing is this change is we've gone from the 5 million ton per annum project to a 10 million ton per annum project. So, rather than lease the FPSO, we're actually going to buy the FPSO. It makes much more economic sense because of the scale of the project now. So, that's one thing that's changed and that's around $900 million of the change, and the residual is actually around moving the break water out from 20 meters out of 30 meters, and that's simply optimizing the engineering design. But you can see it's $3.8 billion to First gas, we've got a 10% share. The BP carry of over 500 takes as well through first gas into Phases 2 and 3. So we know we're well setup in terms of the project.

And in terms of timing of it, there are various mechanisms we can use to take into account future resource development as you say, we're drilling three wells, there is plenty of ways in which we can do with that commercially. So the timing is not going to be affected by the drilling program in terms of the format.

Al Stanton -- RBC Capital Markets -- Analyst

Thank you.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

So, Al is just in front of you. Alwyn would be great. Thank you.

Alwyn Thomas -- Exane BNP Paribas -- Analyst

Hi, Alwyn Thomas here from Exane again. I shouldn't ask actually about gas and the strategy, if I mean intend to farm down further. Do you still intend to drill specifically in new basins for gas?

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Yeah, I think we've demonstrated, gas is valuable. And I think it having delivered 2.5 times our investment so far with more to go. I think it's pretty good. So I think we are targeting oil in the basins that we're drilling. Phase risk is always a risk, but we believe that if you find things that have a scale, what distinguishes Tortue is the size of the things that we were targeting, yeah, and the quality of the rock. These wells will deliver over 200 million standard cubic feet per day. So these are very productive wells, which gives you a very low cost of supply. And if you can ally with that an intuitive development scheme, which we've proven now this sort of nearshore technique. And then you've got very commercial resource. So for us it's about almost Oil Gas agnostic as long as things have gone commercial attributes that mean that you can develop it quickly and in a very commercial way. And I think we've demonstrated that with Tortue. So if we can find another look alike to Tortue, I'd love to do that.

Alwyn Thomas -- Exane BNP Paribas -- Analyst

Okay. Can I just follow up with one -- on the dividend, you talked about 25% free cash flow. Would you consider either moving to -- based on the $100 million, sorry, the $75 million you talked about so far. Would you think about that in a sort of fixed and variable sense looking forward or if there is further sell downs from the founding PE partners, would you consider buying that back?

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Right. All right. So just to be clear, it is good question. So what we said -- and chime in Tom if I get this wrong, but I think what we said upfront is we're going to pay the dividend, right? And we sort to say 250 over three years starting at 75, but growing in line with the performance of the business. Yeah. Thereafter, we're going to get the data into what we believe is the long-term range of 1 to 1.5 times EBITDAX, that gives us flexibility. And flexibility is then about being opportunistic. I think the opportunistic in two ways. I think we have up -- we there are -- there is the potential for doing further deals we've demonstrated, we've got a good track record and if we can continue that record we set a pretty high bar with both the deal in EG and the GOM. But if they were to exist, I believe, we would have support to do it. And alternatively, if there is excess free cash flow, then there is the opportunity to do further returns to shareholders.

Alwyn Thomas -- Exane BNP Paribas -- Analyst

Okay, thanks.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

So, I think is the frame is clear and we're clear as to how we're going to use free cash flow.

Ilkin Karimli -- Berenberg -- Analyst

Hi. Ilkin Karimli from Berenberg. Just two questions. Firstly, just to get it right. So how important now these appraisal wells that you'll be drilling around Yakaar Teranga and BirAllah. Is it correct to assume that you already have two more 10 million ton projects. And so the appraisal, if it's successful, is just about proving the size to the upside? That's question one. And question two in terms of capital allocation priorities. Once the sell down is complete, I understand it's a bit early for this, but how do you plan to allocate that capital? Would you look to return that to shareholders or would you think of another kind of big M&A.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Yeah. So just sort of -- so take two bits and Tom can do the idea of free cash flow. But, yeah, in terms of, we've got sort of two appraisal wells, which is this is one the own Greater Tortue which is ultimately that one is about optimizing the resource base of what where to start. So that is about providing that we to ensure, we've got the right well order. So as we've said on Tortue, we've got more than enough resource were 10 million tons. So this is about ensuring that you're drilling the best first. So we need to make sure we've fully described. In terms of Yakaar Teranga, there is a lot of gas in place in Yakaar and Teranga again. So we're not constrained by the resource there, that well is about ensuring again that we've got, we've optimized the development scheme.

So I think the first two wells are around that. All carries a new channel. As Tracey described, it's on the crest of the Inboard gas play, it's analogous to BirAllah, Tortue. And so it's -- it is an exploration well, but it's in that proven gas strength, that is adding additional resource that will firm up the BirAllah up, and then there is another target that Tracey showed on the slide that would add more resource. The trick though now is not to over a price. If I look at another basin not far away in East Africa, there is a danger of over appraising and damaging the economics. And I think we've been very, very clear and objective about the appraisal program on Tortue and Yakaar Teranga get to the minimum and stop. And I think we're -- and if you're going to drill an appraisal well to help you phase the capital, it has to be truly value-adding.

So I think the message is around being very, very rifle shot with exploration, rifle shot with appraisal, don't over appraise. We're not short of gas here, what we just need to make sure is that we're drilling things in the best order, OK?

And then on free cash flow?

Thomas P. Chambers -- Senior Vice President and Chief Financial Officer

So in terms of free cash flow, as we said, the first priority with any proceeds from the sell down will take our net leverage down in the 1 to 1.5 range. Because right now, at $60 Brent, we don't quite get there. So we want to restore that flexibility to the balance sheet, so that's priority number one. Once we get there, then any excess cash over and above that and any -- becomes a matter of organic opportunities versus inorganic opportunities versus share buybacks. So we've got the flexibility at that point to do all three or one of the three, two of the three depending on how much excess cash, we actually have. But then that will compete those -- all those opportunities will compete against each other and we'll make that decision on a go-forward basis.

Colin Smith -- Panmure Gordon -- Analyst

Colin Smith from Panmure Gordon. I wonder if you could talk a little bit more about your view about further acquisitions and particularly in light of what Thomas just said whether essentially they ruled out until you get back into that 1 times to 1.5 times gearing range. And perhaps more philosophically, how it stacks up against your view about the choice to explore with fairly high risk exploration wells? Thank you.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

And yes, what I'd say is acquisitions are not without risk. The history of the industry is actually some poor deals. And I think we've been very focused on doing deals, which we believe are truly value accretive. And I think we've demonstrated that with these two deals. And of course, you look at each of them, and say that they're quite unique. There is a sort of timing aspect to it, the right thing arrives at the right time. You've got the balance sheet strength to do it, but the opportunity existed.

We've talked a lot about (inaudible) today, but it was the ability to put together a sort of unloved producing fail that had some straightforward things to do to it, and there's a reason why it was unloved, because it actually has other things they could do with the cash. And I think there was a reason why they did what they did, and there's a reason why we came in. But the real interest was around getting the the surrounding exploration blocks and then being able to really leverage that infrastructure. So we -- it was a real package and that was tough to it, and I think we've -- we've demonstrated that we've got something that's quite unique.

On the Gulf of Mexico, it was about a platform. And I hope we've shown you today, we can do something with that platform now because of the timing. And I think the lack of competitiveness there and the ability for us now to compete with expertise, with technology is going to make a difference. So strategically, first what I'm say is it's got to make sense, there's going to be ways in which you can now add value to what it is you've acquired. And we're going to be very hard-edged about that. Because alternatively, we've got a great set of prospects internally here today. We're not short of being able to deploy capital. And the Gulf of Mexico business is high return.

So it's great to have competition for capital. So as Tom said, if there's an inorganic opportunity competing with an inorganic opportunity, it sets the bar pretty high for the inorganics. And I feel good about that today, that the competition is quite strong. So if the right thing arrives at the right time, it's truly strategic. We can add a huge amount of value to it, because of what we're good at, then we'll clearly look at it. I don't think we have to do it today, which is the big point. I think the platform can grow itself, we're confident about doubling the size of the business. The question is can we do something that delivers similar money multiples to what we've done in the past? And I'd say, today it's a pretty high bar, but we're going to go and -- weight and test that. And I'm excited by it, because -- and I hope we've shown you today a little more about the -- they said, there are hidden value there is in both of these assets and our ability because of our exploration skills to go in the market.

Colin Smith -- Panmure Gordon -- Analyst

Thanks.

Mark Wilson -- Jefferies -- Analyst

Yes. Mark Wilson with Jefferies. A few final points. You spoke a lot about returns and dividend of various cash flows, but it sounds like a special dividend could be in the future. Could you speak to that possibly? The second point, could you explain quite where the CapEx savings have been made? Or is it a phasing for 2019 of $200 million? And then the last point, I guess to Tracey regarding Suriname, which we haven't spoken so much about. But the aim to look at the carbonate play. What are the learnings in the other -- in the Liza look alike targets, let's say that you've looked at and are they off the table or does it appears that the border is a barrier there? Thank you.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

We're going to address it. Tom, are we're going to do a special dividend?

Thomas P. Chambers -- Senior Vice President and Chief Financial Officer

Yeah. Right now we don't have any plans for special dividend, we've got -- we showed you -- we're currently planning and paying a $250 million over the next three years. And if the performance of the business is better than what we've predicted will be here, then we could potentially increase the dividend, but, as we've said, we've got excess cash flow paying the dividend is first and then taking that excess cash flow then we look at where is the best opportunity to put it, is it an organic opportunity. And as you've seen today, we've got a whole portfolio of organic opportunities that we can put it in. And that's a pretty high bar given the high rates of return that you've heard. Is it an inorganic opportunity or is it increasing the shareholder dividend or is it a buyback. All those things will compete, but right now we don't have any plans on paying a special dividend.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

All right. Tracey, you do Suriname, I'll do (inaudible)

Tracey Henderson -- Senior Vice President, Exploration

Sure. So start Liza. I think you can -- what you can say about Suriname, Guyana, it is still an emerging basin. Every well that they're drilling on that side is still a learning well, and the petroleum system, which does extend beyond the country borders. You've got -- on Suriname side, a 1 billion barrel field the Tambaredjo oil field onshore, that's actually been sourced from the source rock. That's in -- basically within Block 42 that extends the entire basin. So we believe in terms of potential, potential is still absolutely there. So they -- because sort of the Liza like plays within Block 42 are not off the table. As I did mentioned on the well that we're drilling, we're looking at -- basically looking at a well-designed that will test still an age equivalent zone to Liza, with a well that will target Ranger. I think Ranger is an interesting well because it is a four way structural trap and it will be on led by the source, which will gain a huge amount of information from with drilling that well and it will drill basically an analog which is the lowest trapped geologically the lowest trap type risk, you can drill as a four way structural closure, and the ability to test too, like I said, is attractive, where we can design a well to do it.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

All right, (inaudible) it's interesting. So I think when we gave you the reasonable guidance of 500 to 600, we just sort of completed DGE and we're sort of starting to get our arms around the Equatorial Guinea opportunities there, sort of creating the business unit structure, as well as given as real competition for capital now internally and I think it's healthy. So we said about looking at ways in which we could drive capital efficiency, which is first to be is effectiveness, so you're applying it to the best projects. And the example I gave earlier is kind of one of the examples of the saving. We had an opportunity to drill an infill well in Equatorial Guinea, it was an expensive well and it required a flow line as well, because you were looking to sort of debottleneck that part of the field. There was an existing well that sort of wasn't fully supported. Actually when we went back and said, don't really like the return on that, it doesn't compete with Ghana, that they -- the team came back, Neal came back and said, I got a better idea, which is actually we've worked well over still put the flow line in, I guess, two-thirds of the reserves with third of the cost. We didn't get that sort of competition for capital when we just had Ghana, because that was a Ghana well over Ghana well. Now where we're actually creating, I think a much more effective use of capital because there is more to do then there is actually the capital available and we're going to get the highest quality projects as a result. So it's not phasing. We've -- an enriches area, we've looked very hard at and how we feel Delta House and get the right timing of those wells. We've adjusted the order as a result. So to me, is sort of coming of age almost now, you can be far more effective with your capital allocation because you've ultimately got internal competition, and I think that's what's driving the ability to sort of deliver the same with less is because you're doing better projects.

Jamie Buckland -- Investor Relations

Any more questions in the room?

Anish Kapadia -- AKap Energy -- Analyst

Hi, Anish Kapadia again. I've got a couple of questions. Just thinking about the Gulf of Mexico and how the market views that, as interesting to say the slide of the independence of exited the Gulf since the Macondo disaster. I'm just wondering whether you think the market structurally is putting a discount on the Gulf of Mexico, as a result of Macondo and the additional potential risk, the same from the Gulf of Mexico and how you mitigate that? And then the second question is going back to Mauritania, Senegal. With the new kind of CapEx numbers that you've given, I think the $6 also delivered cost into Europe. Is that still applicable for the first phase of the project or is that when you've kind of got the full 10 million tons, up and running?

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Yeah, OK, let me sort of take that sort of about the Gulf first. I think this, the market sentiment is around sort of two things, I think in the Gulf. I think one was there was a lot of wells drilled in the that absorbed a lot of capital, that didn't deliver a lot of production. So -- and if you go back, Richard those wells were drilled sort of 250 million, a well?

Richard Clark -- Senior Vice President, Gulf of Mexico

High cost.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

High cost. So we went through a period of where there was a lot of expensive exploration with very little commercial delivery. And I think that you're sort of getting a sentiment around people have spent a lot of money and not deliver a lot. So the one of the things we wanted to communicate today was around a business model that's worked and it's worked because you're drilling actually relatively, relatively straightforward geology, it's shallow. It's much lower cost environment to do it and now and its delivering high returns and actually delivered high returns when the oil price was actually higher and service costs were higher, yes? So I think like with all things, you've got to differentiate the base and actually sort of say which business models have worked and you look at the big things that have been done, you would look at Shell sort of recent success, and say, they've done a pretty good job actually in delivering sort of a new play and actually have done it in a relatively cost effective way, yes? But the real success has actually been in taking things that are regarded as being relatively small and actually making a really good business out of there and that's where companies of the scale of DGE have done a really good job. And I think as once Richard hopefully has articulated today is as more of that to go and as more of it to go, because of the lack of competition and because of technology changes. So I think part of I would say that the -- we've got -- we've been clear about what we're going to do in the Gulf. We've been clear about our track record and actually we're being clear about the things that differentiate us from others. And I feel genuinely good about that and we know that we can do it in a way where the cost structure is probably more intact than the lower 48 which is seeing I think real supply pressures whereas, Richard, today you feel good about being able to replicate those F&D costs.

Richard Clark -- Senior Vice President, Gulf of Mexico

Oh, yeah, our F&D costs were generated our track record goes back, as you can see on the slide, it goes back seven years. So when we started the tracking the track record, our costs were quite high with rig rates in the 400,000, 500,000 a day. Since that time from 14 to 17 the drilling and completion costs dropped about 65% in the deepwater area. And so we have the opportunity that maybe we can do better, because our cost base is going to be lower. But it's-- and you know I really don't see much opportunity for service cost to go up because there's so much oversupply of rigs and vessels and things and the activity. So low, so I think we've got running room on the cost environment we have, that's very favorable and that's really what drives the good economics today as how lower cost are going. So I feel really good about that.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

So (inaudible) is the big message is about the execution of the business model, and I think there are very few people doing what we're doing today. And the independents used to do it in and, but no longer they're doing it today. So I think that to my mind is the real part of the education for the market is about -- this is the business model that's worked, it's going to continue to work. We've got a great prospect inventory and actually the cost of supply we feel good about. So I think that's the -- answer your first question. I think the same question on Mauritania Senegal in terms of the breakeven, we are putting more capital into Phase 1 because we're going to build Phases 2 and 3, as simple as that. So I think the big message is you get out of it is that if you're pre-investing in Phase 1, you must be building Phases 2 and 3 and I think that's BP's mindset now is they're absolutely after Phases 2 and 3. And so, yes -- the cost of Phase 1, so having gone up in each they've gone up because we're pre-investing in Phases 2 and 3, is actually better to do the work upfront that it is to do it later, all right?

So, if part out the pre-investment we're making, the cost of Phase 1 is the same, but if you put the pre-investment, it's gone up because you're doing Phases 2 and 3 , and the $6 number that we talked about for the full development is absolutely secured, it's below $6 for the full phase. You're right, it's a bit higher on the first phase. But that's not really the point, the first -- the real point is what happens when you get 10 million ton per annum going. Is it a cost-effective supply for the world the answer is, yes it is. And just to remember that if you take the BP carry on it at the 10% level we're talking about, I think our breakeven is below 4. So it's a very, very good project, I told you, for Kosmos.

Jamie Buckland -- Investor Relations

We've got time for one or two in the room. Thomas we will take one more.

Thomas Martin -- Numis Securities Limited -- Analyst

Can I just ask on the Gulf of Mexico side, sorry, Thomas Martin U.S. You showed us some of your jointly owned infrastructure we spoke about the business model being subsea wells going back over other people's infrastructure. Can you just talk about how you manage that and clearly you have to have access at a reasonable price, the infrastructure, and the infrastructure time has to be good. So what are the regulatory -- what is the regulatory environment with respect to that and also how do you manage that sort of business risk, which is slightly out with your direct control?

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

First remember number you get -- through what percentage of facilities today are for the Gulf of Mexico. I think the numbers are --

Richard Clark -- Senior Vice President, Gulf of Mexico

Very high.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

It's around 75%.

Richard Clark -- Senior Vice President, Gulf of Mexico

Yeah.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Yeah. So the first thing sort of is Gulf of Mexico has a lot of -- deepwater Gulf of Mexico has a lot of infrastructure, that is full, all right? So one of the, I think, misunderstanding is the idea that it's hard to get the stuff into stuff. All right? It's not -- you've actually got a lot of it's geographically well placed and by the way it's not full. All right? So therefore there is a desire for people who own host to bring stuff in.

Richard Clark -- Senior Vice President, Gulf of Mexico

Yeah. So we like to focus around certain assets like Devil's Tower and we would like to bring more stuff for Delta House because if we put more throughput through there, we're lowering our lifting costs and it becomes more and more efficient. So we like to focus around these once we're already there. But when we get a new project, we are going to go out and we're going to look at what are the available vessels around us that we could go to. And if there is only one, that's where you have a very particular situation. So what you're going to do is before you drill your well, you're going to make a deal with them and you're going to get a letter of intent or something like that for agreed processing fees if you are successful. And you want to do that before you've spent money and you can always say, well, I'm not going to drill the well unless this dealer is done. So it's -- and if you have something the size of of resolution, then you have other options, because you could do a new build for resolution, because it's big enough to do that. If it was 30 million barrels and you only have one option then you've got to do a lot of work ahead of time to make sure that you don't put yourself where you don't have any leverage.

So it's a good question and it's something that we think about all the time.

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

It's not been a barrier. I think intriguing for me is as I said there about, there's a lot of it around, it's not full and actually if you take something like resolution. We've got an existing Spa which is close to abandonement, so we have that as an option and actually you have an alternative option of sort of doing a Delta House and there -- probably the PHA, they're probably pretty similar, in terms of overall economics. So it's, again it's sort of -- require -- it's a part of the education I think about saying this isn't a barrier to doing business, the barrier is making sure that you build things around hubs and ultimately, as Richard said, if you get the reserve density which he showed around Delta House, it's a very, very good project for everybody.

Thomas Martin -- Numis Securities Limited -- Analyst

75% of the platforms are under 50% utilized.

Richard Clark -- Senior Vice President, Gulf of Mexico

Yeah. Under 50%. Yeah.

Thomas Martin -- Numis Securities Limited -- Analyst

65 (inaudible) 75% or under 50%.

Jamie Buckland -- Investor Relations

We've got time for one more question in the room and then we'll -- Ilkin finish off and then turn back to Andy.

Ilkin Karimli -- Berenberg -- Analyst

Hi, Ilkin again from Berenberg. Sorry, to go back to Yakaar Teranga. But is it realistic to assume FID there next year or in other words, leaving SPAs aside, what are the kind of operational hurdles that you guys have to overcome before an FID?

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Yeah, next year it's not feasible. Yeah, so 2018 will be around the appraisal well than the interpretation appraisal well. We have a concept, then it's about doing the pre-FEED work of taking that concept, so that is 2020. So we're looking -- beyond 2020, 2021 is probably a more realistic date associated with that.

Ilkin Karimli -- Berenberg -- Analyst

Right. That's (inaudible)

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

It is (inaudible), this is very long facilitated, Jaimie. It's exactly 5 O'clock. Nicely on time. It's been a great afternoon for us I hope you've got out of it what you want to get out of it. I think from our side of it, we feel great about the business we're building. I think it's got more optionality today than it's ever had, we have clear plans about how we're going to deliver value from it across all phases whether it's production, optimization, whether it's ILX, whether it's the development, whether it's a basin opening, exploration. And I hope we've demonstrated from our side of the table that we're excited about it.

It's a pretty restless management team, it wants to go out and do great things and we've got people that are really engaged. So I couldn't be happier about the team, I couldn't be happier about the portfolio and I believe that we've got a very clear set of plans. So, thank you and I'm sure you still got more questions. We are going to go out and have a drink and we can talk through those as we're available. So I appreciate your time. Thank you very much.

Duration: 165 minutes

Call participants:

Andrew G. Inglis -- Chief Executive Officer, Chairman of the Board of Directors

Richard Clark -- Senior Vice President, Gulf of Mexico

Tracey Henderson -- Senior Vice President, Exploration

Jamie Buckland -- Investor Relations

Mark Wilson -- Jefferies -- Analyst

Thomas Martin -- Numis Securities Limited -- Analyst

Alwyn Thomas -- Exane BNP Paribas -- Analyst

Richard Tullis -- Capital One Securities -- Analyst

David Graham -- BMO -- Analyst

Anish Kapadia -- AKap Energy -- Analyst

Thomas P. Chambers -- Senior Vice President and Chief Financial Officer

Al Stanton -- RBC Capital Markets -- Analyst

Ilkin Karimli -- Berenberg -- Analyst

Colin Smith -- Panmure Gordon -- Analyst

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