Good day everyone. Welcome to Kosmos Energy's Second Quarter 2012 Conference Call. Just a reminder, today's call is being recorded. At this time, let me turn the call over to Brad Whitmarsh, Vice President of Investor Relations at Kosmos Energy.

Thanks operator and thanks to all of you for joining us today. This morning, we issued our second quarter earnings release, including an update on Jubilee and our 2012 capital program. The release is currently available on our website, which is also where you can find our 10-Q expected to be filed with the SEC later today. Joining me on the call with our prepared comments are Brian Maxted, CEO; Greg Dunlevy, Executive VP and CFO; and Paul Dailly, Senior VP of Exploration. Darrell McKenna our Chief Operating Officer is out of the office today, but he will be joining us for the question-and-answer session, which will follow our prepared remarks. During the Q&A session, I would ask that you keep your questions to one primary and one follow-up so that we can get to all who are on the call 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 the earnings release and in our SEC filings. We may also refer to certain non-GAAP financial measures in our discussion. Management believes such measures are important in looking at the Company's historical and future performance and these are commonly referred to metrics in the industry. 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 included in our SEC filings. At this time, I like to turn the call over to Greg for a review of our quarterly results.

Thanks Brad and good morning everyone. I will first provide a brief review of our financial results for the second quarter before reviewing our updated guidance items. I will then hand the call over to Brian and Paul to review our production, development, and exploration programs. Overall our results for the second quarter were generally consistent with prior expectations. We had one Jubilee sales lifting during the quarter net to us of approximately 1 million barrels of crude. This generated total revenues of nearly $113 million for Kosmos, with the lifting price at premium of $0.77 per barrel above the Brent settlement price. With regard to our net production versus sales during the second quarter this year, we under lifted by approximately 240,000 barrels and our cumulative under lift position was around 500,000 barrels at quarter end. Our third sales lifting for the year occurred in later July for nearly 1 million barrels and it will price slightly above August monthly Brent settlement average. On the cost side, our product expense for the second quarter 2012 included 10 million associated with the enhancement program for Phase 1 wells at Jubilee. Excluding these work over cost, the average production cost was a little over $9 per barrel. Exploration expense was $17 million for the period, being primarily composed of some seismic, G&G studies and the second quarter costs associated with the Teak-4A well. General and administrative costs were slightly lighter than expected at $35 million for the quarter with 50% non-cash long-term equity compensation expense consistent with prior periods. Tax expense was $22.5 million for the quarter with about two-thirds of this attributable to our Ghana operations. We also incurred additional book tax expense as a result of a change in our deferred tax asset position related to the vesting of…

Thanks, Greg. I like to start off with some comments on our exploration strategy and portfolio and then focus on our Ghana assets before handing over to Paul for an exploration update. Strategically, Kosmos is focused on progressively growing shareholder value by making world-class oil discoveries of unlocking new super major scale petroleum systems. With this in mind we've been actively expanding our portfolio of exploration opportunities to deliver an annual multi-valve drilling campaign going forward, beginning later this year. Over the past 12 months, we’ve dramatically changed the growth opportunity for Kosmos, more than tripling our gross acreage held through focus on a number of potential petroleum systems in Northern West Africa, as well as along the northeast equatorial margin of South America. A couple of highlights during the second quarter include the capture of a significant acreage position offshore Mauritania, and our execution of an agreement with Chevron to bring them into our offshore Suriname position. And we continue to see additional opportunities that will provide significant growth potential for Kosmos in the future. We’re also highly focused on enhancing the value of our legacy Ghana asset, by growing existing production, bringing on additional projects to deliver new revenue streams and by exploring for new hydrocarbon discoveries in the resource rich Tano Basin. Much progress has been made in each of these parts of our business. Starting with our existing production at Jubilee, this world-class field continues its excellent performance. The reservoirs are responding extremely to water flood and gas injection with strong pressure support demonstrating good reservoir and fluid continuity, connectivity and communication. Approximately 40 million barrels of oil have now been produced. Importantly, we’ve made substantial progress in resolving the well productivity issues that have impacted on our original Phase 1 wells. We have now performed…

Thanks, Brian. As we've mentioned, in Ghana, our exploration efforts are focused on drilling out the remaining resource potential in the Deepwater Tano Block, between now and the end of the exploration period early next year. We got off to a good start in our 2012 campaign with a new field discovery at Wawa where we encountered 33 meters of oil and gas condensate play. Located in the Northern, previously undrilled portion of the block, this well encountered good quality oil between 38 and 44 degree API and API and Turonian-age channel updip of the Enyenra field. We are currently integrating the well information into our mapping to determine an optimal appraisable strategy, defined all those potential future tie-in to the TEN development and has opened up a new trapping stairway. In the next month or so, we will spud our second exploration well for the year to test the Okure prospect, this was formerly named Tweneboa Deep. This Turonian-age file is located beneath the Enyenra field and is to some extent de-risked as we prepare encounter in the exploration field of Enyenra 2 well is interpreted to have been on the flank of this Okurean reservoir fairway. Our upcoming well is designed to test these thicker portion of the fairway. This is a very exciting, and sizeable prospect which we interpret to help multi-100 million barrel equivalent potential. We expect results early in the fourth quarter and this will be followed by our sub-exploration prospect, the Sapele prospect, which is seismic attribute supported likely 75 million barrels feature located down-dip of the Mahogany and Jubilee fields and located in similar age sands. Results are anticipated for this well towards the later part of the year. With these attractive opportunities on the horizon, set against the backdrop of previous success…

Thank you. (Operator Instructions) Our first question comes from Ryan Todd, with Deutsche Bank. Please proceed with your question. Ryan Todd – Deutsche Bank: Thanks gentlemen. A couple of questions on Jubilee, you referenced how the asset stimulated wells have been coming on very successfully. Can you talk about generally what rates you are seeing on average in the wells coming back and from the earlier asset stimulate wells, which I think you said you've got about four months of production? Are you starting to see any signs of buildup of the finds again or what are you seeing from that point of view?

Let me answer them Ryan, I think Darrell is offline. In terms of the asset stimulation program, obviously, it's been extremely successful over the weekend, since our release. Production is now at about 88,000 barrels a day, so that’s just 1,000 barrel a day short of the peak production on the field thus far. So, obviously the program has been very successful. We've only complete – we only acidized five of the nine producers so far, and in terms of production, we have – what we've said is we've restored the PIs to same level some time, in some cases even better than the original PI, which will give you an indication that production on each of the wells is what we would anticipate from those PIs. In terms of the one continuing or known is how long or how often might we need to be doing these assets stimulations and the information so far is encouraging given the several of these wells have been – at least one of them have been on stream for about 120 days since the first simulation. And of course, we're not at steady-state production yet so any changes in production rates are not simply going to be related to the well, the wellbore issues, but also what's happening in the reservoirs well, but generally speaking rates are holding very steady on a relative basis to the original initial production after coming on stream following the production enhancement program, if that helps.

Yeah. I'll jump in too, Brian. My phone went dead for a minute there, but yeah absolutely there has been no decline seen on the five that are being stimulated so far. Ryan Todd – Deutsche Bank: That’s great. Thanks and on the – you said that you'd have three of the Phase 1A wells on by year-end and the other two producers would come on in the first half of 2013, is that right?

Yeah we said – It’s Brian again Ryan, we said we'd drill three of the Phase 1A wells, which obviously we benefited from the learnings of the Phase I drilling and completion, those wells are – so the wells are high angle and the third is actually a horizontal. So, the KH on those wells is some of the best KHs we’ve obviously seen in the field as a result of the design. We will now be bringing them on stream with more optimal we believe completion designs again, pick it out from the learnings that we had on Phase 1. The current plan subject to any operational delays is to have two of those three on stream and producing by the end of the year, with the third one in the early part of 2013. Ryan Todd – Deutsche Bank: Okay. And so, from a production plateau point of view you think, is first half of 2013 a reasonable expectation in terms of hitting 120.

Yeah, I mean obviously ourselves and Tullo in fact have given out guidance in the recent past. I don’t think we would want to change that guidance at this point and that guidance includes reaching a plateau sometime in the early part of next year, but we’re close to 90,000 barrels a day today without additional activity yet done, so that should give you some sense of where we are at.

Our next question comes from Al Stanton with RBC. Please proceed with your question. Al Stanton – RBC : Yes, good morning folks. It’s just a question about Teak and Mahogany area, you talked about it the high-back to Jubilee that kind of left me feeling that the field is smaller or the complex is fairly smaller and they will be developed perhaps later than we previously anticipated. I’d appreciate your best guess on resources and startup dates for those two fields? Brian F. Maxted – CEO: Yes, it’s Brian again here. Let me say a few things and then I can pass on to Darrell and he can add on. Obviously these discoveries are still very much at the appraisal delineation stage. We've drilled several appraisal wells recently, we're currently testing the Akasa well, all of which is designed to try and understand what the likely resource base is. Given it's just not about barrels, it's actually about value and what's the right value decision to take in terms of a potential development plan for these barrels. And so we're very much looking at maximizing returns on the development, which is part of the equation of I bet being a likely tie back to Jubilee. And if it is tied back to Jubilee than the resource base will be integrated alongside the Jubilee resources and we will optimally develop the entire resource base within that context. So, it's not necessarily safe to assume that production in a tie back case will be way out into the future because it might well not be, because I think part of the appraisal program for some of these discoveries will actually be long-term tests not just simple DSTs. Darrell do you want to add-on to that?

Yeah, the only thing I would say is we're still in the thrills of the appraisal program we're testing the Akasa-1, so it would be too early to put any volumes and resource base to it. Al Stanton – RBC : So should I now assume that Jubilee, Mahogany and Teak are all produced over a platform with plus or minus capacity of 120,000 barrels a day?

I think again it's too early to say at this point and until we both within the company we finished our appraisal program and integrated the results, and as the partnership and alongside GMPC and the ministry until we've done all of that and figure out what the right way forward is that, I don't think we'd be comfortable in making any statements on that. Al Stanton – RBC: Can I just close with one final question then Tullo recently said that TEN was 360 million barrels of oil equivalent. Are you a buyer or seller at that level?

The resource range for TEN, again Tullo quoted a range in there and I think the partnership as a whole is broadly in line with that range. It is a wide range, primarily driven by what recovery factors are going to be on the resources in place. And obviously that won't be known until we've got these fields on stream and we can better estimate how these discoveries are performing at the production stage. So, I would say that we are aligned with the range that the operators have given out. Al Stanton – RBC: Thanks guys.

Our next question comes from John Herrlin with Societe Generale. Please proceed with your question. John Herrlin – Societe Generale: Yeah, hi, two quick ones for me. With Morocco you said you were shooting seismic, what license?

Hi, John. Good to hear you again. In Morocco, we've got three blocks there at the moment, which is a very significant acreage position about 25,000 square kilometers. I'm sure, you know this is probably one of the last pre-salt frontiers in the South Atlantic margin, at least to our knowledge. So, we are pretty excited about the deep potential here. We have completed in the early part of the year a 3D program over the Essaouira and Foum Assaka licenses and processing as you know in these pre-salt situations takes a while, but we do have the fast-track volume in and we've been interpret in that, and that's the basis for some of Paul's comments in terms of the prospectivity being encouraging, but the final processing in fact won't be available until the early part of next year, but initial indications are extremely encouraging from a tracking standpoint and from other aspects of the play concepts that we're pursuing. John Herrlin – Societe Generale: So, you're going to stick to those first and then get to the other ones later, like the cap one?

Yeah. The other block that we have there is Tarhazoute in that salt basin, that’s another large license, and we haven't established any plans on acquiring seismic over there yet, we’re currently reinterpreting the existing dataset that exits over that area. John Herrlin – Societe Generale : Okay, great. With Suriname, will you be heads-up with or will Chevron be heads-up with you on an expansion rate basis going forward once they close or will you be recouping anything that you are spending on the seismic currently?

Yeah. Normally details of private transactions remain private in respect. John Herrlin – Societe Generale: It’s worth a shot.

We didn't, not surprising, but with respect to Chevron, we will not disclose that. Obviously, we're delighted to have Chevron alongside us. They bring a tremendous, as you know development to production capability to the table. They are very respectable of our exploration capability as well. Suriname is straight down the middle of a fairway from a strategic standpoint for us being downdip of a giant oil accumulation that somehow made its way 200 kilometers away from the source kitchen. So we’re very, very excited about Suriname, particularly given the success that Tullo and Shell and Total have had both at South and French Guiana. And that seismic survey is about to start actually both on locations.

(Operator Instructions) Our next question comes from Ed Westlake, with Credit Suisse. Please proceed with your question. Ed Westlake – Credit Suisse : Good morning everyone.

Good morning Ed. Ed Westlake – Credit Suisse : Just a quick question on OpEx per barrel for the field, obviously with the acid stimulation the OpEx has gone up, how long do you think that’s going to be – that higher OpEx is going to be part of the results?

Darrell, do you want to take that question.

Ed, the question on sustainability on each treatment is still an unknown, so whether we absolutely have to repeat or not we’ll actually find that out as we go along on a production mode. Right now we’re thinking that it could be a one-time event from an acid simulation standpoint, it could be related back to drilling and completion fluids, so again lot unknowns here, we can bring some guidance later on, on whether that's sustainable or not. Ed Westlake – Credit Suisse : Approximately.

Ed, from a short term guides perspective we’re seeing production expenses of around $9 a barrel, excluding workovers, as you saw in the second quarter. Second quarter workover costs were about $10 million to production expense, we see that workover cost in the third quarter going up significantly just based upon timing of realization of those costs and then dropping significantly in the fourth quarter. Again, based upon the timing of the workovers and the liftings. Ed Westlake – Credit Suisse: Yes. So, we should think about it in absolute terms and then divide it by the barrels you're producing and run it that way?

I think you should look at the run rate by barrel and then you should look at the workovers more as a one-off by quarter, and that was about $10 million in the second quarter. It will be significantly higher in the third quarter and then it should drop in the fourth quarter. Ed Westlake – Credit Suisse: And then have we got any estimation yet on the CapEx for the TEN project, a range?

No, we're still relatively early in the stages of planning that development and at this point, I think it wouldn't be appropriate to quote that Ed. Ed Westlake – Credit Suisse: But presumably on the per barrel basis, obviously, costs have gone up since Jubilee and it's also a slightly more complicated development given its gas condensate is a higher ratio than it was at Jubilee, is that a fair assessment?

Well, if the first phase that development is hung on the oil lag at Ntomme and the Enyenra oil discoveries. So, those gas volumes are not going to be a part of the original development, but directionally you're correct that you can expect them to be a little bit higher then Jubilee.

All right. And then you've mentioned twice I think that the initial expectations for the processing of the seismic in Morocco look good. When do you think you will get to a definitive answer or view on the pre-drill that you have in Morocco say for 2013?

Some time the second quarter or so quarter, early third quarter next year, and we're trying to setup the program to spud in Morocco by sometime late next year. So, I would hope that we would be pretty clear on our exploration program later than the second quarter next year or so. The final data sets won't be until the beginning of – until the early part of next year. So, we wont make a final decision on how many wells and what prospects they are going to be testing after that point obviously.

Our next question comes from Doug Leggate with Bank of America. Please proceed with your questions. Doug Leggate – Bank of America/Merrill Lynch: Thanks good morning everybody. Thanks for taking my questions. Brian, if you could follow-up on the emerging plays, where would you expect your working interest levels to stand? I mean in other words Morocco and Mauritania in particular. Should we expect that you will be taking those interests down a bit as you get closer to the drill point and if so, what would you be comfortable with and I have a follow-up please.

Yeah. It’s a great question Doug and it’s something that as we look at capital allocation portfolio management. It is something that’s on their mind. One of the challenges that we’ve got is that in executing on our exploration strategy we have taken advantage of first mover situations as we’ve been able to get very acreage positions to capture as much of the petroleum systems, potential petroleum systems if possible and give us play diversity and prospect dependency etcetera. So, but what that brings with it, of course is they are large areas and the seismic stage, the costs of large acquisition program is going to be in a much more significant in units passed. So, one of the challenges we are looking at is how do we therefore think about partners, do we think about partners later in the game and more conventionally after we've defined the prospectively and format of the drilling stage or do we bring partners in earlier. And you’ll probably see a mix of those strategies in. In Surinam, we decided to bring a partner in earlier, although we still got 50% of that block and so that provides us with further options down the road to dilute a little, but if we think that's appropriate. And that will very much depend on how much prospectively we see and how confident we are in that prospectively. But this is a team game exploration. We've got a great deal of confidence in our own capabilities, but we also respect the abilities of potential co-ventures as well, and so you can expect us to anticipate that we will be partnering on most if not all of our projects. Doug Leggate – Bank of America/Merrill Lynch: Great, thanks. My follow-up is really following up from a question earlier, when we go back and look a year or so ago at the sort of prospect backlog and the way you had viewed some of the Teak and so on and West Cape Three Points, just listening to you today I'm wondering if your sort of relative enthusiasm there has changed or was there something you saw in Teak-4A that has changed your view or can you just elaborate a little bit as to why you might not want to move, we might not see you move a little quicker on the other development or not? I will leave at that. Thanks.

Well, obviously, we're looking at returns for this business and now returns are through exploration success. So, when we look at the capital expenditures on the business, we're very much focused at ensuring that we deliver maximum returns for our shareholders. TEN is clearly a very sensible development and there is going to be substantial capital outlay on that development ultimately. The MTAB area as you know we've always considered it to be different from Jubilee. It's multiple pools and stacked reservoirs not always coinciding with each other, but offset is also a range of hydrocarbon types from dryer gas through to rich gas through to conventional oil, and so it's a much more complicated development, and so I think in terms of timing, in our mind, it's always ranked third behind Jubilee in the TEN area. I don't think that's the case, and I don't think we've, we're any less enthusiastic about it. I think it's just a question of how do we position it within our portfolio and think about in terms of capital allocation relative to some of the other great opportunities that we've got in the business?

Our next question comes from Shola Labinjo with Tudor Pickering. Please proceed with your question. Shola Labinjo – Tudor Pickering: Hi gentlemen, good morning. I just wanted to clarify something, on the MTAB area, is there a deadline for making a decision with regards to development, and the second thing was in the scenario that you do tie back and the MTAB cluster to say Jubilee and is it reasonable to assume that your production at Jubilee will be higher than the current projected plateau?

Well, let me take the second part of the question first. The nameplate capacity on the Jubilee FPSO is 120,000 barrels a day. We haven't focused on it thus far, but the opportunity may exist for increasing that potentially, I think we've talked about that in the not too distant past, but our first priority is ensuring that we've got the productive capacity within the Jubilee field to deliver the 115,000, 120,000 barrels a day capacity in FPSO now. So, that's the first priority, but in terms of how we tie in, how we might tie in Teak and these other discoveries, it will very much on what the appraisal requirements demand, particularly of long-term testing as we think about phasing these developments and again learning from the early stages of initial tiebacks, trying to understand how much oil is recoverable and the flow rates of the different wells before proceeding with a full development of each of these fields. The timeline is currently something that’s under negotiation. As you're probably aware, within the petroleum agreements there is a set timeline for each discovery. We are trying to integrate all of those with the government and we are in discussions at the moment and are papering it up some basic agreements to try and integrate the discovery areas into one single development area, so that we can take one integrated development decision sometime later next year.

Our next question is a follow-up from John Herrlin with Societe Generale. Please proceed with your question. John Herrlin – Societe Generale: Yes, thank you. Regarding Jubilee and the scaling, could you give kind of a simplified rationale for why you think the scaling was localized?

Yeah Darrell, do you want to take that one.

Yeah. There is actually two issues that kind of indicate to us that the scaling is localized, and Brian mentioned earlier, within several feed of the wellbore, it's a size of the treatments we executed. They are all very modest at the frontends of the treatment. So, we see a majority of the effect with very modest volumes injected during the treatment itself. We've also collected samples of scale from the workover themselves and we are taking them apart in the lab and clearly it is a scale and trying to understand the precipitation environment that actually occurs to actually precipitate that scale. The other thing I'll say is during the drilling of the Phase 1A wells, we have taken pressures in the Phase 1 reservoirs and we find this consistent pressure effect from the water flood and gas injection across the field. So, that gives us confidence again, but the reservoir is reacting well to the water and gas flood, and it's not across the field issue from productivity standpoint. John Herrlin – Societe Generale: Great, thank you.

At this time, I would like to turn the call back over to Mr. Whitmarsh for closing comments.

All right, thanks operator and thanks to all of you for joining us today. Should you have any follow-up questions, please don't hesitate to give me a call. Thanks.

This concludes today's teleconference. You may disconnect your lines at this time and thank you for your participation.