Welcome to Kosmos Energy's fourth quarter 2016 conference call. Just a reminder, today's call is being recorded. At this time, let me turn the call over to Andy Inglis, Vice President of Finance and Treasurer at Kosmos Energy.

Thank you, operator and thanks to all of you for joining us today. This morning, we issued our fourth quarter earnings release which is available on the investors page of the kosmosenergy.com website. We have also published a presentation this morning that we plan to refer to during today's call which is also available on our website. We anticipate filing our 10-K for 2016 with the SEC later today. Joining me on the call today are Andy Inglis, Chairman and Chief Executive Officer; Brian Maxted, Chief Exploration Officer; and Tom Chambers, Chief Financial Officer. Before we get started, I'd like to mention that this conference call includes certain forward-looking statements based on our current expectations. The risks associated with the forward-looking statements have been outlined in the earnings release and in our SEC filings. We may also refer to certain the non-GAAP financial measures in our discussion. Management believes such measures are important in looking at the Company's historical and future performance; and these are commonly referred-to industry metrics. These measures are provided in addition to and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP and included in our SEC filings. At this time I will turn the call over to Andy.

Thanks, Neal and good morning, everyone. Amid a challenging macro environment, 2016 was a successful year for Kosmos. We accomplished all of our key objectives because we entered the downturn in a strong financial position and stayed disciplined in the execution of our strategy. This financial strength and business discipline is what differentiates Kosmos from other exploration companies and ultimately enabled the successful farm-out of our Mauritania and Senegal assets. Before we discuss the benefits of the BP farm-out, I would like to begin by highlighting our achievements in 2016. In Ghana, we effectively managed the Jubilee turret issue identified early last year, the impact of which is largely cash flow neutral as a result of the insurance coverages we have in place. The TEN fields began oil production on schedule in August. With TEN online, we became free cash flow positive in the fourth quarter through the combination of increasing production and decreasing CapEx, a trend we expect to continue in 2017. In Mauritania/Senegal, we completed appraisal drilling of the Tortue discovery and successfully drilled the Teranga exploration well in Senegal. To date, we've discovered a gross Pmean resource, approximately 25 trillion cubic feet of natural gas and de-risked at least an additional 25 trillion cubic feet of gas along the inboard trend. In the basin as a whole, we've now defined resource potential in more than 25 billion barrels of oil equivalent which could make this basin comparable in scale to Mozambique but with liquids potential. [Indiscernible] during the drilling continues to support our charge model which predicts the presence of liquids in the outboard part of our acreage. During the farm-out process, several super majors peer-reviewed our work and came to the same conclusions, supporting our view of the basin's quality and potential. In the exploration portfolio…

Thanks Andy. Our primary objective this year is to deliver a company-making ALLL and/or liquids-rich gas discovery. In my commentary this morning, I'd like to discuss in more detail the drivers behind our exploration program and the specifics around the exploration targets in our upcoming drilling program in both Mauritania and Senegal. After this, I will conclude with a short update on Suriname. However, before proceeding further, I would like to take a moment to briefly add my exploration perspective to Andy's opening comments. The clarity of our exploration plan, the quality of our process, the capability of our people and our discipline in execution, including patience, persistence and performance over the last several years, is now paying off. Since we formed the Company 13 years ago, we've played a key role in unlocking two of the three Cretaceous petroleum systems which have been opened by the industry in our geography, the South Atlantic margin. And now we have carefully assembled a new, large, high-graded exploration portfolio which includes a strategic presence in both of the current proven cretaceous exploration hotspots at Mauritania/Senegal and Guyana/Suriname, as well as positions us to open up the next space. Our position as a leading global deepwater explorer is underpinned by the size and quality of the prospects we’re drilling over the course of the next couple of years. In aggregate, the prospects to be drilled amount to over 15 billion barrels of oil equivalent of gross unrisked potential. They include some of the largest prospects to be drilled by the industry anywhere in the world during this time. Now let me turn to the drivers behind our second-phase exploration drilling program in Mauritania and Senegal. As you will see shortly, this independent oil well program is scheduled to start next quarter and continue…

Thanks, Brian. At the end of the fourth quarter, Kosmos had total corporate liquidity of over $1.2 billion as we became free cash flow positive with the delivery of the TEN field. This includes $617 million of undrawn availability on our reserve based lending facility or RBL; $400 million of undrawn availability on our revolving credit facility; and $194 million of available cash. So we entered 2017 with a strong balance sheet and liquidity position. And as Andy mentioned, we expect to generate approximately $250 million in free cash flow at $50 oil this year. We expect to use that free cash flow to pay down a portion of the borrowings on our RBL and create additional headroom to further fund exploration success and continue our strong organic growth. In fact, this year we have already received $162 million in cash proceeds from the closing of the BP farm-out in Mauritania; and expect to receive approximately $60 million in further consideration in the first quarter from the closing of the Senegal transaction. As a result, we plan to repay $150 million under our RBL during the first quarter. So now I will turn to the results for the quarter and the full year. We finished the year with seven crude oil liftings, three of which occurred in the fourth quarter, in line with our revised guidance issued on the third quarter conference call. This generated full-year 2016 oil revenues of $310 million, excluding $188 million of derivative settlements. When you add our revenue to our settled hedges, it reflects a realized price of approximately $73.76 per barrel in 2016. Full-year revenues were down compared to 2015 as a result of lower realized oil prices, as well as downtime and reduced production related to the Jubilee turret bearing issue. LOPI insurance…

[Operator Instructions]. Our first question comes from the line of Brendan Warn with BMO Capital Markets. Please proceed with your question.

Just first question -- and I'll have a follow-up after it -- probably more to Brian. I appreciate a lot of new detail on slide 6 and 7. Could you just talk through for me, as an engineer, more putting a lot of this detail into, call it, probabilities of the geological chance of success for your first prospect that you've got award of on 3D seismic over? And then I'll leave it for a follow-up.

Yes, the geologic chance of success on Yakaar we consider to be a very, very high chance of success. It's a base of slope fan that's downdip; it's downdip off the Teranga discovery which, although it's 30 kilometers away, we see a good seismic continuity and therefore good calibration. So the AVO is calibrated. As you know, the AVO is not able to just, in itself, determine the difference between oil or liquids and gas. So, depending on the deeper source rock to be, one, more in an oil facies as you come out of the main delta; and, two, being more oil mature; and, three, being closer to the Albian/Cenomanian reservoirs and therefore suffering less fractionation. The longer the distance -- and that's shown on those slides -- the distance below Teranga, as an example, is 3 kilometers from the [Technical Difficulty] to the reservoir. In Yakaar, it's just 2 kilometers which is less of a distance for fractionation and drying of the gas. And then the final point is it's in an area that's got access to the mature, oil-prone Albian source rock that we saw in the deeper part of the Teranga 1 well which, as you may recall, had a gas condensate ratio of 167. And the Cenomanian had a gas condensate ratio of 30. So to get to 50 is not asking a lot. And the geological setup of the Yakaar prospect is quite different from Teranga which is why we believe that we've got a decent chance of finding oil -- or liquids and/or oil in Yakaar. And then with the AVO, we think it's a very low-risk prospect, in and of itself, in terms of the discovery of anything.

Are you willing to give your, call it, either your own personal view or your corporate view on the probability, firstly, of be it dry gas or a liquids-rich discovery, obviously being two different numbers? Having built up, having Albian as full disclosure --?

I think, look, if you look at the risk segments on the charge prediction map which suggests it's in that range -- 1 in 3, to 2 in 3 or slightly greater; 1 in 3, to 2 in 3 -- I think we feel good about that. That's a decent chance. I wouldn't go beyond what that suggests. But I think that 1 or 2 out of 3 chance of finding a commercial liquids discovery is as good as we can refine it, based on the model as it sits today which is not calibrated, outside of the slope trend and the oil discoveries to the north and south of us.

Okay. Then in follow-up, my question relates more to the free cash flows or cash flows. I appreciate the guidance you have given. At $50 a barrel, generation of $250 million, I just wonder what the sensitivity of that is for every, call it, additional $10 -- or what is it at $70 a barrel? Just for calibration of model.

Brendan, it's Andy. So for an additional $10, if you went from $50 to $60, it's around additional $75 million of free cash flow.

Our next question comes from the line of Ed Westlake with Credit Suisse. Please proceed with your question.

I guess this is more sort of a commercial question. Each of these prospects that you've identified, if you have the right gas/oil ratio, would clearly be large enough to develop. Maybe -- there is perhaps two questions here. Maybe on the first one, if, say, they do prove to be gassier, at what point does it make sense to go instead of with FLNG, but to move to like a full LNG development? That's the first question and then a follow-on.

Why don't I --? I'll take that. I think what's interesting to me is the competitive nature of FLNG versus an onshore scheme. We think today that the fundamentals of the way in which FLNG can be modularized, the way the capital spending can be matched to the growth of LNG demand, means that FLNG is actually competitive with a big onshore scheme. So, I think, as you start to think about the commercial approach to it is fundamentally the way to move a gas project to ensure that it's the lowest-cost gas around and we have an FLNG scheme today which absolutely does that. I think we can expand that scheme from an initial phase of around 5 million tons to 10 million tons, Tortue growth. If you had additional gas in the future discoveries, you could continue with the same approach which I believe will continue to be very cost competitive. And it allows you to take that modular approach to be able to build it to the future demand. So I don't think this is simply a question of offshore versus onshore. It's actually a question of what is the lowest-cost way of doing it. And I think today, I fundamentally believe the advances that are being made on FLNG -- it is a cost-competitive approach. And it may well be the enduring cost-competitive approach.

And then so you do get enough oil, I guess maybe 0.5 billion barrels, typically would support an FPSO. Any early idea of where you think the breakeven is? It may be very early to answer that. But obviously the prolific gas fields have low gas breakevens. I'm just wondering what your thoughts are, at this point, on the oil side.

Well, I think what we've said -- and again I think it's early days yet, so we need to be sort of careful about being too proscriptive. But we've looked at what we believe is an economic liquids yield at the current oil price. And we believe it's around $50 barrel -- 50-barrel CGR. So we believe, therefore, the liquids targets that we see in the prospects we've described are economic to develop in the current price environment.

Using the strip kind of price.

Using the strip kind of price of about $50 world. So we’re not -- look, I think you know -- and the point about all of that is you go back to -- it's a slide that we've shown you many times in the past. But Kosmos' strategy was always about targeting things that were economic and provided a healthy return in a $35 to $50 world. Nothing has changed. Why does it work? It's because entered early, good fiscal terms; and these are world-class prospects. If you put that together, it gives you efficiencies around the development scheme. And I think that's a point that I really want to emphasize today is that Brian has showed you four world-class prospects. These are large; and, therefore, through scale, have natural development efficiencies. And I think that's the big driver behind what we see in this exploration program we’re embarking on. These are very differentiated in terms of the scale and, therefore, the quality.

Our next question comes from the line of Anish Kapadia with Tudor Pickering. Please proceed with your question.

A couple of questions from me, first of all, just looking at your stock price, where it's trading relative to when you did the deal, just really a few percent higher than back then. Just wondering are you thinking about essentially share buybacks, given the market is not appreciating the deal, the size of the exploration prospects you are seeing this year? Is that one area that you would consider over the course of this year?

I'm not in the mindset of share buybacks today. I think our fundamental belief is that we believe we're going to be successful with the exploration program. And therefore, our objective is to ensure that we’re in a strong financial position to be able to follow up with the appraisal and development programs that would follow. We believe, actually, very strongly that the value in the deal is in the 30% that we retained. And I think our strength as a Company comes from our ability to be able to have the financial firepower to be able to stick with that 30% and be able to capitalize on it fully. And so we’re planning for success. We believe that we’re going to be successful over this well program; and, therefore, having a balance sheet that allows us to pursue that success and not be compromised because we can't pay our way is critical. So I don't anticipate share buybacks being the use of capital versus the opportunity to be able to invest in the success from the exploration program.

Okay. And the second question, on Morocco -- I was wondering if you could give an update on your views on the Moroccan exploration acreage that you have and any update on the drilling carry with BP.

Yes. Brian will pick that question up.

In Morocco, we’re actually -- just last day or so -- started a new 3D seismic program off the Sahara, large 3D, nearly 10,000 square kilometers. And in the middle of the year we will be shooting another 3,000 or so in our Essaouira block, offshore Morocco census stricto. So we’re back after the initial drilling in Morocco and Sahara a couple years ago to shoot the seismic and pursue new ideas, principally in the outboard parts of those two fairways. And that's where we’re at the present time.

And the drilling carry from BP, though, is still in place?

BP have exited Morocco. And in lieu of that exit, they provided us with a consideration to enable the exploration to continue there.

And one quick follow-on, could you give what the cash flow impact would be if you did, in fact, have the full 12-week shutdown on Jubilee? What impact would that have on your current free cash flow guidance?

I think that the best way to look at that is to see it as a process where we now have the vessel spread moored and we have made a lot of progress on that. We believe it will be finished within the next three or four days. At that point, we're going to evaluate what is the right long term solution to the heading of the vessel. We believe we’re in a position today where it's fundamentally about stepping back and ensuring that we do have the fatigue life that will give us the life-of-field. And there are several ways of doing that. And we need to come through with the right long term solution that enables us to deliver that outcome for both ourselves as a partnership and the government. So I think it's too early to actually determine what the length of the shutdown is going to be. Tullow have clearly talked about a shutdown of up to 12 weeks. We've taken the view that it could be shorter. And I think within the two numbers, there would be a cash flow impact. But it's not significant, given the $250 million that we’re delivering.

Our next question comes from the line of Richard Tullis with Capital One Securities. Please proceed with your question.

Just looking at the exploration program set up over the next several quarters, Brian, still expecting something around 80 days to drill the first well?

Yes. We've historically said 2 to 3 months; and then in the kind of 60- to 90-day range. We expect these wells to be relatively straightforward. We've got pretty good control now, we believe, on the seismic in terms of both depth prediction and pressure prediction. So hopefully there won't be too many drilling issues, but in that range.

And lastly, looking at things more globally, we have been hearing a lot about rising costs from many of the shale operators over the last several weeks. And could you discuss current expected exploration development cost from the deepwater projects perspective? I imagine the global deepwater projects maybe don't see much of an increase at all or maybe nothing at all. Could you talk about things from that perspective?

Yes. I think, Richard, we’re actually in a different part of the cycle. I think we're actually in a cycle in the deepwater where we still have significant oversupply of capacity across all dimensions; whether it's deepwater drilling rigs, whether it's deepwater fabricators, seismic. So I think we’re in a very different world. And we have a world also where the cycle time is clearly different. If you start to think about the current price environment we have been through, the cycle time of the big projects is typically three years, once you approve a project and once it gets into production. And so as we go through the current price cycle, all of those projects are, quote, now coming to an end; and therefore actually supply, the oversupply of capacity of the industry is growing currently rather than diminishing. So I think we're actually still on a downward trend in terms of costs, rather than at a rising trend. And it has always been the same. It's about the cycle time of projects. The cycle time of the well that is, in a matter of days, in the lower 48 is very different from the multiyear projects that are occurring in the deepwater. So it's no surprise that I think we’re still in a downward trend in deepwater; whereas, as you say, the reverse could be occurring in the lower 48.

Our next question comes from the line of John Herrlin with Societe Generale. Please proceed with your question.

I just have a quick one for Brian. For the five factors you gave, what do you think is more critical, the depositional situation or the timing/vertical fractionation?

Yes, John. We’re in a complicated 40 kind of world here, dealing with multiple processes that are interacting together. So the weighting and bias of each of those processes is, at this point in the development of the model -- and it is calibration which is still obviously quite early. It's difficult to predict. And that's why we try to move away from the individual source rocks and articulating those to one of consolidating the picture into simple, 1-in-3, 1-in-2 and 1-in-1 chance of finding liquids beyond 50 barrels an MCF. As you move out into the -- as you move north into Mauritania and as you move south into Senegal, the influence of the shallower source rocks switching on is significant, we believe; particularly in northern Mauritania, where you are dealing with essentially intra-formational reservoirs within the upper Cretaceous and the Cenomanian through the Campanian. And there we've got, I think, a really good chance of finding liquids because of the contribution of those two source rocks and because those areas are being higher in the stratigraphy and more remote from the deeper source that's in a gas facies and gas maturity. And obviously, the examples there are Chinguetti and SNE. As we move outboard on the Senegal and the Nouakchott River system, facies is important. And I mentioned in my script that it's based on -- the model is based on a number of assumptions. We have an outboard well and a deep-sea drilling project well that's got really good oil facies within the deeper Valanginian, Neocomian-Valanginian section. And then inboard, of course, we know that gas is sourced from that same reservoir. So we’re extrapolating. But directionally, we will see a more oil-prone facies within that charge horizon. We’re much more confident with our control on the maturity now, given the calibration that we have. So if it was one thing, I would say it's the source facies process and driver which will be key which is going to be aided by the fact that that source rock is close to the Cenomanian and Albian reservoirs; and, therefore, hopefully less fractionation is occurring.

Was this something that you had a lot of discussions with, when you had the data room open?

It is, actually. As you know, we had three super majors in the data room. And what you are shown here is very much the consensus that came out of both our own work and the detailed technical discussions we had with all of the super majors, who were obviously very focused on finding liquids in this basin as well. And I would say there was a general consensus around the fact that there are no dry gas basins in West Africa. We’re dealing with three oil source rocks. We do have an oil field to the north and an oilfield to the south of us. And we do have gases which suggest there is an oil component in the system. So based on all of that, the question is where is the sweet spots for oil? And we believe that math is probably going to end up, in general terms, a good depiction of the distribution of liquid content in this basin. Obviously, it will be subject to, in detail locally, refinement as we put more holes into the petroleum system.

Our next question comes from the line of Al Stanton with RBC. Please proceed with your question.

Brian, really with respect to that last comment in terms of the distribution of the liquids and that is where you are seeing the value; how do you see the value of liquids or the discovery of further gas impacting on the Tortue development? Because you are starting with a field that straddles the border. I would have thought you would start with something easier, particularly given that there is potentially a substantial 60 Tcf gas prospect in a single country just to the south. So how can you present slide 5 and say, well, we hope to find something completely different that would surely ultimately change the timings that you present in slide 5?

Al, I'll let Andy answer that question. I would say it has been a major discussion point internally, with the governments and with all the data room attendees, including BP. So I'll let Andy answer that.

And I think it's a conversation that, as Brian said, that we've had with the farmanees and with the government. Simply said is is that Tortue is a world-class gas discovery. It is very LNG friendly because it has the right amount of liquids, but not too much. It has massive well rates in terms of the quality of the reservoir. It's in the thickest part of the depositional zone because it's in the core of the river system. And that will benefit from that. So it is the ideal LNG gas project. And we think that if we were to find additional gas, as it comes with additional liquids, with sort of liquid stripping gas will actually be probably the way forward; and, therefore, those projects probably wouldn't be exporting gas. You would be using the gas to recharge the reservoir. So we've had the debate with both governments. Both governments are fully behind an early gas development. They are fully behind a gas development that can be delivered in 2021. And Tortue can absolutely do that. So we don't see any bifurcation in agendas between the countries if we find additional resources. I think what we will find is additional projects being done in parallel, potentially an oil project and maybe a liquid stripping project in another country. Who knows? But the fact that Tortue will anchor an LNG development that enables early gas in 2021 is absolutely the agenda of the partnership with BP and the agenda of both governments.

So you are quietly confident you have two Mozambiques, rather than the Mozambique and the Tanzania?

I know; I'm confident that what we have -- and I'm confident in what we have is, we have a low-cost LNG project today that is cost competitive; and, therefore, is gas that is absolutely going to move forward. I'm confident in that. I am also confident there will be follow-up projects that will involve liquids and/or black oil. That's what I'm confident about.

Our next question comes from the line of Pavel Molchanov with Raymond James. Please proceed with your question.

So the fact that FID on the LNG development is not expected until next year -- is that partly to enable an integrated resource development, should you find liquids over the next 12 months?

No. It's simply the time it takes to get from where we’re today with the subsurface appraised. We need further work with the DST to ensure that we have the gas composition nailed which then allows FEED to start in the third quarter which is typically a six-month process that would allow us to be in a position to demonstrate commerciality, mid-2018 which would then allow the FID decision to be made. So this is being driven by the timeline to do the engineering necessary to get to FID, not anything else.

Okay. But if you were to make a liquids discovery, as you are anticipating, would there be, at least theoretically, the possibility of integrating the two development cycles into one? Or would they be treated completely separately?

Pavel, today, the way that we would see it is they would be separate developments, geologic -- geographically, they are separate. Geologically, they would probably separate, at different pressure regimes. And they probably have different drivers around liquids versus gas. And as I said in the answer to Al's question, you have in Tortue a gas resource which is very well disposed towards an LNG development. And we have a very credible, low-cost scheme that enables that to go forward. I think thereafter, you then have to think about how you would do a black oil maybe in parallel with it. And then, if you know, you had a rich liquids gas discovery, how you optimize the liquids recovery from that, you certainly wouldn't be exporting gas. So those are very different schemes. And I think you should see them as separate projects which will run in a sequence, but probably parallel overlap between them. Yes and then maybe I'd follow up. Maybe one of the reasons we decided to farm down at this stage was to bring in a development partner like BP that has the capability of doing projects of this scale in parallel; and, clearly, the ability for us, as a 30% share with the balance sheet strength, is that we can move along with that. That was part of the whole strategy. Now is the right time to enable us to be at a credible working interest that allows us to move forward with multiple projects.

Our next question comes from the line of Neil Mehta with Goldman Sachs. Please proceed with your question.

Just more housekeeping questions, to start off. I Wanted to confirm that you said you'd expect and 11 Ghana liftings, net to Kosmos. I believe in the January presentation, you had said 10 liftings, net to Kosmos. So just want to confirm. And then what changed?

It is 11 cargos. And obviously, we've had some more time. We factored in the 10 operations; and what we think Tullow with a shorter shutdown, in our view, on Jubilee. So that gives us 11 cargos.

And then you rattled off some numbers in the beginning about production levels at Jubilee and TEN, thus far in the first quarter. Can you go through that again? There was some trade press about some of the downtime at Jubilee, in particular. But it sounds like you guys are running okay.

I'm not sure what trade press you are referring to, Neil. But in the first quarter we have been going through a process of ensuring that we deliver the spread mooring project. That project is very close to being finished, a matter of days away. While we have been doing that, you are clearly working at the aft of the vessel which has interrupted some of the offloading. So that's probably the up-and-down that you have been reading in the trade press; nothing that wasn't planned. And actually, the most important thing out of it is that when we have had periods where we have had stable access to the offloading, with the two shuttle tankers which gives you -- it removes the constraint on the offloading, the production level has been very high, up to the 120,000-barrel-a-day number that I talked about which is the FPSO vessel. So clearly reservoir working well, vessel working well and we have been working on ensuring that we get the spread mooring done. That has obviously caused some downtime on the production levels while we have been doing that.

And then the last housekeeping question for me is -- I guess in 2018, we should expect FID at Tortue. What percentage of the asset do you need to have committed from a marketing standpoint before it's ultimately sanctioned? And the gas market is oversupplied, but I think there are some idiosyncratic things about the fass that make you more comfortable around your ability to market the assets. So can you talk about that?

Yes. Well, I think you know -- you need to think about -- I'll just make two big points. The first is with the development scheme that we have, we have an incremental phasing of the buildup of the LNG capacity; an initial vessel gives you around 2.5 million tons. The second -- which would be 2021 -- a second vessel, probably about 18 months to 2 years later, builds that up to around 5. So you're not putting a lot of LNG on the market in one go, point one. The second point is part of bringing BP to the table was not only do they have the deepwater expertise, the LNG development expertise, they also have a very large LNG portfolio. And so, therefore, they are a credible buyer of the incremental production. And that was one of the things that attracted them to the project was they are looking for new sources of gas. You are probably -- as you are well aware, that they bought the Mozambique gas recently. So I firmly believe, as I said in my remarks, that I don't see the marketing of the gas, the quantities we’re talking about here and the ratable buildup of those quantities to be an issue. The fundamental issue is ensuring that you have the lowest-cost gas around. And that's what we’re targeting in terms of the $5 per MCF FOB. So I feel good about the marketing of the gas and it will not be an impediment to the pace at which the project moves forward.

We have reached the end of the question-and-answer session. I would now like to turn the floor back over to Neal Shah for closing comments.

Thank you, Operator. We appreciate all of you joining us on the call today and your interest in Kosmos. If you have any further questions, please don't hesitate to contact me. Thank you very much.