Good day, everyone. Welcome to Kosmos Energy's Second Quarter 2015 Conference Call. Just a reminder, today's call is being recorded. At this time, let me turn the call over to Neal Shah, 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 second quarter earnings release, which is available on the Investors page of the kosmosenergy.com Web-site. We anticipate filing our 10-Q with the SEC later today which will also be available on our Web-site. Joining me on the call today are Andy Inglis, Chairman and Chief Executive Officer; and Tom Chambers, Chief Financial Officer. Following our prepared comments, we will have a question-and-answer session. Consistent with prior calls, I request that you ask only one primary question and one follow-up question. This will help ensure we get to everyone on the call. If there are questions we aren't able to get to within the 45 minute timeframe, please contact me later today. Before we get started, I'd like to mention that this conference call includes certain forward-looking statements based on our current expectations. The risks associated with forward-looking statements have been outlined in our earnings release and in our SEC filings. We may also refer to certain non-GAAP financial measures in our discussion. Management believes such measures are important in looking at the Company's historical and future performance, and these are commonly referred to industry metrics. These measures are provided in addition to, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP and included in our SEC filings. At this time, I'll turn the call over to Andy.

Thanks, Neal, and good morning everybody. Through the quarter we maintained our disciplined approach to executing our strategy and are w4ell-positioned both financially and organizationally to execute our plants and create value for shareholders. As I go through my remarks today, there are four points I want to emphasize. First, our Ghana assets continue to grow and we remain on track to double gross production by 2017. Second, after our initial success at Tortue-1, our plan for creating an accelerated value from Mauritania and Senegal is taking shape. Third, our exploration portfolio continues to mature generating additional near-term high-quality opportunities to create significant value. And finally, our continued focus on financial discipline and maintaining a quality balance sheet. In Ghana, production continues to grow from the Jubilee Field averaging approximately 108,000 barrels of oil per day sales during the second quarter resulting in two Kosmos liftings as expected. It's important to note that selling around 108,000 barrels of oil per day means we're actually producing on average through the quarter approximately 113,000 barrels of oil per day meted. Difference between meted and sales production is shrinkage from the oil separation process and typically results in around a 4% difference. We've consistently been within 5,000 to 10,000 barrels of oil per day at the nameplate FPSO capacity, so we've been making good progress on this front. We also saw reliable gas exports during the quarter with export volumes regularly in the range of 70 million to 80 million cubic feet of gas per day. The expected increase in gas-fired power generation capacity at the Aboadze power plant in the third quarter should enable us to continue to increase gas exports. As some of you are aware, early in July gas compressed on the Jubilee FPSO experienced unplanned downtime limiting our ability…

Thank you, Andy, and good morning everyone. Financial performance for the second quarter was strong and we finished the second quarter with two crude oil liftings generating oil revenues of $119 million. This excludes derivative settlements of $42 million over the quarter. When you add our revenue to our settled hedges in the quarter, it reflects a realized price of approximately $82.96 per barrel. For the quarter, we generated a net loss of $75 million or $0.20 per diluted share driven largely by the non-cash $45 million mark to market loss on commodity derivatives. Adjusting for the impact of one-time items that affect the comparability including non-cash changes in the fair value of derivatives, cash settlements on derivatives, gain on sale of assets and other similar non-cash and nonrecurring charges, the Company generated an adjusted net loss of $1 million or $0 per diluted share for the second quarter of 2015. On the cost side, operating expense in the second quarter was $20 million or $10.40 per barrel sold versus $23 million or $7.87 per barrel sold in the second quarter of 2014. The higher per barrel cost reflects the fact that last year we lifted three cargoes in the quarter versus two in the current quarter. Exploration expense for the quarter was $15 million reflecting ongoing seismic and processing charges. General and administrative costs for the quarter were $41 million compared to $39 million incurred during the first quarter of 2015. General and administrative costs during the quarter were impacted by the timing of recognition of our stock-based compensation awards. Completion and depreciation expense was $38 million or $19.29 per barrel of oil sold versus $23.85 per barrel sold in the second quarter of 2014. Income tax expense for the second quarter was $25 million. The majority of the…

[Operator Instructions] Our first question is from Brendan Warn with BMO Capital Markets. Please proceed with your question.

Thanks for the opportunity to ask some questions. I guess just two questions from my side please. Just firstly to your rig rate, just if you can update us on any discussions with your rig contractor regarding the rate and sharing of some of the pine in the current weak oil processing environment, and if you can just remind me, and I know I can look it up, but just your minimum commitments for that rig into the next couple of years? And just second point on the rig, for this slot that you farmed out in the second quarter, will you be or have you booked or will you realize a loss or is there a cost associated with this farm-out? And then just second question I had just in terms of the next well coming up, Marsouin, just are we expecting a similar pressure regime dip, can you just talk about the technical parameters of drilling, technical parameters that lead to what you expect the cost of the well net to yourselves?

It's quite a few questions. I'll just sort of do them sort of in reverse order, just go through them. So in terms of the farm-out, the answer is, no, there is no loss associated with that. So it's just simply a straightforward farm-out. In terms of the rig rates, it's clearly a connected question. No, we're not in discussions with that at the moment about changing the rig rate. In our sense, a contract is a contract. What we are looking is the potential if we are successful in other areas and we wanted to increase our drilling capacity then play our opportunities then where we'll have a different conversation. But I genuinely believe that we should honor that contract. Clearly what we are doing, if you look at the spread rate, the drilling is probably 40% of that, the headline rig rate is 40% of the overall spread cost. And so we are focusing on the remaining 60% and we're making progress on that. We're seeing savings of 10%, 15%, 20% coming through and I think we've just started on that. So from a deflationary perspective, I think we're starting to see it coming through in other sectors. And clearly, as that contract moves through, we will have the opportunity to look at other options. In terms of our commitment on that rig, it's a three-year contract started in the third quarter – started in mid 2014 and will run through mid-2017. And then finally I think you asked questions about Marsouin. The overall cost of the well will be what we have forecasted in the past about $120 million. It will target a series of stratigraphy. Clearly the Cenomanian which was the target in Tortue-1, we also entered the Albian in Tortue-1 which is [also a horizon] [ph], and then we'll be deepening Marsouin into the Albian. So we'll be looking at all three Cretaceous reservoirs which we believe are prospective.

Our next question comes from Ryan Todd with Deutsche Bank. Please proceed with your question.

Maybe if I could ask one on, can you talk a little bit about the takeaways from the successful 10-metre lower Albian section, do you have there Tortue-1, I think that's new relative to the last time we had a conference call? What does it mean for the current Tortue structure, and more importantly, have you looked towards the other structures, Tortue East and others, how does it inform you of your other targets in the basin?

Yes, it is new since we chatted last time because we put the second press release out on Tortue after the earnings call. First point is, the Tortue-1 well was targeting Cenomanian and actually we had a very good tie between the well and the seismic. We deepened the well to get some stratigraphy information, particularly down into the Albian. We didn't anticipate actually tagging a reservoir in that location, because as you know, the sort of two main structures on Tortue, two anticlines, West and East, and actually the Albian really bypasses the Western anticline and is predominantly on Tortue East. So it was really an upside to tag quality reservoir there and actually it was an upside to tag hydrocarbon there. So what it does do is it significantly derisk the Albian, it's derisked the Albian in particular in East Tortue which is one of the three appraisal wells that we'll be drilling. And I think the other sort of takeaway from it, when you step back from it, always just sort of remember that in Tortue-1 we've drilled the uppermost of the three horizons, Cenomanian, the Albian and the [indiscernible], we just sort of tagged the top of the structure. And the fact that we have gas in the Albian in the West Tortue location is I think is a real positive indication to be proven now through the subsequent appraisal. And again, I just want to emphasize the point about sort of not running away with this. This is really about the minimum number of appraisal wells to prove the gas volume which allows us to deliver commercial LNG scheme. That's the first thing we're doing. And the second thing we are going to be doing through that appraisal program is testing any liquids potential that we have in it. So it's going to be very disciplined. We're clear about the three wells we need to drill to do that and we don't anticipate we'll be doing anything else.

Thanks, that's very helpful. And now maybe one follow-up question on Jubilee, and I realize that it may not be the primary driver maybe going forward, but you have there in the release, you're going to estimate later this year a development plan in Jubilee including plans for Mahogany, Teak and Akasa. Any thoughts as to what that might look like? Is there going to be – any idea in terms of maybe in the plan what you might be able to do to pull forward or potentially accelerate some of the long-lived resource there or is it more going to be an exercise and kind of filling the haulage in the facility?

I appreciate the spirit of the question. Again just sort of stand back and make a big point first before going through the detail. Over a number of years the resources at Jubilee have grown. We replaced reserves at 135% in 2013 and 115% in 2014. So what I understand is that Jubilee is a world-class field, big fields get bigger, alright. So we have an increasing scale of resource. We now have the ability to sort of integrate MTA into that. So the word that's going on with the full field development plan is to look at that economic optimum of is there the ability to increase the production level, and it will require additional facilities offshore, additional power, additional gas compression, additional order that allows you to create both [indiscernible] an economic price from the acceleration of that larger resource base rather than simply filling haulage. Now have we submitted the plan yet? No, we haven't. We anticipate doing that in the coming months, but that's absolutely one of the options. And I will give you my personal view today, I believe it is an option that we'll have real value to all parties, ourselves, the government and clearly for shareholders. So that's the word that's ongoing and I don't – I know that you'll also respect, I'm not going to tell what do I [indiscernible] do we know what we're going to announce [indiscernible] saturate, but if you just stand back for me, you're asking the right question. Look, the field is bigger, it's bigger than you anticipated when you sanctioned it. Therefore there must be an opportunity to do more with it, and the answer is, I believe there is an opportunity to do more with it. What we have to find is the right economic optimum between the capital end and exhibit signs to be really disciplined about our capital, so you're not exposing yourself to a sort of fool's errand there, but what's the right amount of capital [indiscernible] benefit.

Our next question is from Anish Kapadia with TPH Partners. Please proceed with your question.

Just the first question was on the drilling of Tortue going forward. I don't think we had some comments from Chevron related to that going back some more on that early stage upstream spending. Just wondering in the scenario that Chevron doesn't farm-in, would that change your drilling program at all for next year if you had to fund Tortue 100% through the appraisal phase, and then kind of outside the Chevron have you received much interest from any other integrators to come into that prospect? And then the second question was also in terms of Mauritania exploration. Given how well the seismic seemed to work on Tortue, just wondering if you could talk about which prospect Tortue is being risked and how the chance of success is changed for these prospects from what you've learned on Tortue?

It certainly is a complex time in the industry in terms of individual companies having individual agendas, but if you sort of again sort of step back, when we [indiscernible] on Mauritania we only invited the majors in and I think all of the majors came and looked at it. As I've said in the past, we did the deal with Chevron because they were sort of the most accommodating around actually with the working interest that we were prepared to push out at that time. Clearly having drilled Tortue now and open the petroleum system up, everyone that was in the data room and didn't get a deal has come back to us and asked how they could actually get back into the prospect. So I'm not overly worried actually around an individual company and its individual plan. Clearly that will be a decision for the Chevron to make. If they decide ultimately not to participate, we have plenty of opportunities to work with us, we clearly would like to go forward with Chevron. But what I think we're actually – today as I look at it, the [indiscernible] in fact fundamentally a strategy which is, we believe we've opened up a big basin. It's the scale of the resource, this is the scale of the resource which is attractive to the super-majors. You look at the super-majors' portfolios today and look at their exploration track record, what they have to develop in the next decade, and it fits. So do I worry overly about that? No, I don't, and I think it will be about individual companies and the timing of their own individual circumstances. Therefore, our strategy remains the same. We intend to drill this out and we intend to demonstrate the scale through a very focused…

Our next question is from John Herrlin with Societe Generale. Please proceed with your question.

Following up on what you just said, with Tortue that means you've got more than C-1s?

Yes.

Okay. How long do you think it will take for you to get those three wells needed to delineate the gas resource done, chronologically I mean? 17?

No. I mean chronologically, John, just to sort of if I wasn't clear in my remarks, if you look at the drilling sequence, it's Marsouin which we anticipate to start this quarter when the rig comes back from [client] [ph]. It is anticipated a 90-day well. Clearly we are successful at well being – it could be slightly longer. Therefore you would start the series of three wells on the appraisal side on Greater Tortue in the fourth quarter. If you chart them through on 90 day wells, then what it takes you to is sort of mid-year sort of into the third quarter. The third quarter 2016 is really where I believe we would finish the three well program.

Okay. Say you have encouraging results from the subsequent wells, will you start making soft conversations with LNG companies or will you wait till you fully delineate things?

I think so the answer is sort of, yes. I think the story will start to evolve but we're demonstrating what we believe and what I believe is sort of a incredible world-scale project, what people are going to say, you know what, this is a new source of supply for the world's existing [indiscernible]. That will start to emerge but I think the chronological order is to sort of by the second half of 2016, to say, yes, we've got a world-class resource [indiscernible] TCF of gas, we have in place the basis for moving forward the cooperation agreement between the two governments and we have an LNG partner who is going to take it forward, and that's really the value. Now what we're not going to be doing is sort of selling pieces of the project off to buyers. Credit complex partnerships that actually slow down progress rather than accelerate. I think that's what history has shown, projects, bigger projects have got into difficulties because they've got too fragmented a partnership and they've got multiple agendas as a result. So if that's not explicit, that's really what our thinking is.

Our next question is from Ed Westlake with Credit Suisse. Please proceed with your question.

Good news to hear on the potential liquids content. Just on the timing of wells, you mentioned C-12 [indiscernible] and Senegal would follow on from Marsouin and Tortue. When do you think is the earliest that you could get onto those and you sort of alluded that it might make sense even to get an extra rig slot or something to get onto them earlier if that was possible?

Good question. Again, it is important that first point is we're trying to be really disciplined about making every dollar count and not actually putting pressure on the Company's budgets, how do we do more with less. I'm pretty rigid about the capital inputs at the moment. Therefore it's about making choices around timing. Part of the issue really around timing is two things really. The seismic to the north in C-12, we're sort of completion of the evaluation of that today. So that becomes our sort of first opportunity to sort of look at the northern part of our acreage beyond C8. It will be on Block C8 and that we'll be ready to drill by the sort of middle of 2016. So as you think about the three wells that would define Greater Tortue and then you get onto that in the second half of 2016, so that sort of defines our timing. And then if you remember our entry at Senegal, we only shot the seismic in Senegal in the second half of 2014. It's been processed at the moment and so the earliest we can get to that will be with fully worked up prospects. You would not see us pass frontlines which we shared with the market. It will really be the back-end of 2016. So the natural sequence here of doing the right things in the right order and ensuring we've got quality before we get into them will be to drill. Marsouin is ready to go now, great prospect. You then get into the appraisal, very clear three well discipline and then you open up probably [indiscernible] which will be the C12 prospect followed by the two wells in Senegal. So I don't think you're going to see us going out and particularly getting a second rig just because of the timing around getting the seismic and ensuring that we're fully defined on the best prospects [indiscernible]. So I think we've got what I would call a practical drilling schedule now that matches the subsurface development in terms of the seismic and separation but also one that sort of meets our financial and even resources capability as well.

And then on Jubilee I guess Phase 2 and [MTAP] [ph], I appreciate you probably can't give a CapEx number at this point but maybe talk a little bit about what the landscape looks like in terms of your ability to either negotiate or engineer costs out of that second phase?

We're going to see cost coming from two dimensions. Clearly there are many significant number of wells drilled and going forward we'll obviously have the opportunity to take advantage of what is obviously a much better rig market today. So I think you'll see cost coming out in the second phase of the development program. The facility's work, again without getting ahead of myself in the conversation, I think is realistically not huge. So I think in a relative sense as you see the second phase, it's going to be dominated by drilling. How many percentage will be on drilling is difficult for a front-end project and therefore I think there is actually a real opportunity to see some benefit from the lower rig rats.

And on the subsea?

And on the subsea – fair enough, good point – subsea exactly the same which is as you say [indiscernible] well has some flow-ons coming back, and I believe the timing of this, I think we're seeing a slightly slower deflationary impact coming in from the deepwater as the sort of market clears. The cycle time on projects is longer in deepwater than it is in a shallow play, therefore that timing impact. But I think we would be executing this project at a time when we can take best advantage of that. So I think there's real opportunity to drive value into this next phase at Jubilee because we'll be working and drilling in subsea wells operating at a time when we're probably at significantly more advanced prices.

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

Just kind of a high-level one for you on your LNG planning. Obviously we've seen a lot of softness particularly in spot LNG pricing amid rising supply from particularly Australia and eventually North American supply and European demand for gas is at a 20 year low. So as you think about LNG economics for this project, what are some of the sensitivities that you're running in terms of kind of oiling off-takes or anything along those lines that you would need to see and your partner would need to see to be able to pull the trigger?

I think good question. Lets sort of look at this, this is gas that will be actually looking for a market in the next decade and it may well be the middle of the next decade, and it's typically the time horizon. So I'm not overly worried today about today's spot prices. Today's spot price has been influenced by a lot of supply that's come on all at one time and that's the nature of LNG. You take the big projects, they come on the market, absorbs acreage, it moves forward. I think I stand back and look at the word and say, the world is getting gassier, there is – whichever sort of house you go to, it's sort of common view as you get to 2025 the world needs another 100 million tons per annum of LNG. I think that's a reasonable consensus. U.S. supply is going to take a big portion of that. But we'll scale resource that is cost competitive because it's got great reservoir that's adjacent to market and has good fiscal terms, we'll be competitive, and that's all we're about. As long as we can demonstrate, and sort of back to John Herrlin's question, in a reasonably short timeframe which is sort of back end of next year, that we meet those three criteria that are competitive with the U.S., then we have a scheme and we have a scheme that's credible of what the world wants. So that's where we're aimed at, and again, we need to demonstrate that through appraisal. I'm very clear about what it takes to do that and we need to demonstrate through progress both at an inter-government level and with our partner, but it's a relatively short timeframe to get there.

Okay. And so when you talk about for your oil development, you've kind of set out $30 to $50 a barrel kind of breakevens, will you provide that analogous range for LNG pricing in relation to this project?

And again, I don't think it's quite as simple as that. I think what you have to look at is the frame of saying, what's the alternative supply cost, you have to be competitive with that, and I think that's what I'm looking at. I'm looking today at actually saying, the cheapest LNG in the world is coming from the U.S., am I competitive with that. It's a market. And that's the thing on my mind.

Okay, it's a high-class problem to have in any case.

It's a high-class problem to have but I think that's the mindset, the mindset has got to be is, for the world to buy it, someone to come in and buy it, they have to say, is it competitive with the alternative supply. Now there are clearly other dimensions other than price, there is exposure to Henry Hub, you want it, don't you want it, there's the credibility of the supply, how big is it, all the molecules there, et cetera. So those are the things that are ultimately going to determine the buy pool and that's the world we're working at today but we have no illusions about having to demonstrate a project that's competitive against the best in the world today and that's what our work is focused on.

Our next question comes from Ritesh Gaggar with GMP Securities. Please proceed with your question.

Can you please provide whether the post-well analysis that has been carried out since April and May on the Tortue discovery, whether there has been any change in understanding of your geology in terms of the liquids content and whether the next three to four wells will be focusing on just proving up the gas resources so that you can farm into an LNG partner or you might target something differently in terms of the liquids content?

What I can say is that we've got the early geochemical analysis back from the well and I was very clear in my remarks to say that what the fluids and formation samples demonstrate is there are multiple sources of opportunity at the play. So clearly that's sort of to an agenda. We see this, we've tagged the, we've drilled the Cenomanian and I think it was the first question of the day, and we've tagged the top of the Albian. On Greater Tortue we're clearly as we appraise it out we've got an agenda to demonstrate what I would call a threshold volume of 15 TCF. That gets us to a world-scale project. Then the world can look at it and say, yes, there is a credible resource there. But we're also going to get to the bottom I think of the potential liquids by drilling deeper. In particular in one of the wells we'll target the western side of Tortue West and clearly the well is targeting an oil – what we think is an oil water – a gas water content, but clearly we need to demonstrate that. It could be something else. So what I would say is, there remains the potential but we're clearly focused today on the drill-out of the gas resource to demonstrate the threshold I believe and fully understand the sources that have been at play. Now whether the timing allows them to have a liquids content in Tortue is one aspect of it, it will clearly allow us then to have a better understanding of Marsouin and another prospect [indiscernible].

Our next question is from Al Stanton with RBC Capital Markets. Please proceed with your question.

Just a quick question, you said earlier that there will be a final announcement from the [indiscernible] about Ghana determination in the second half of 2017. You obviously said that you had significant financial headroom. I was wondering if I could draw a line between the two and ask whether you have any concerns of [indiscernible] being paid in cash for any oil you produce in the second half of 2016 as sort of 12 months between first oil and the final decision on the [board at dispute] [ph]?

No, we don't.

There is no consent at all? Hedging will only be impacted by the usual technical concerns about first oil and new development?

We don't have – so I have no indication from [indiscernible] as they were all from the Government of Ghana that they would hold back any payments to us. They've made no indications around that at all.

Okay. So until the second half production, I mean we should be anticipating cash flow to go in line with production in my forecasting 2016 numbers?

Yes, what I said is, that we've had no indication from Government of Ghana that they would hold back any of those payments to us.

Since there are no further questions at this time, I'd like to turn the floor back 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.