Neal Shah – Vice President of Finance and Treasurer Andrew Inglis – Chairman and Chief Executive Officer Tom Chambers – Chief Financial Officer Brian Maxted – Chief Exploration Officer.

Bob Morris – Citi Ed Westlake – Credit Suisse Richard Tullis – Capital One Southcoast Anish Kapadia – Tudor Pickering, Holt and Company Neil Mehta – Goldman Sachs Pavel Molchanov – Raymond James & Associates Nikola Kouzmanov – Jefferies Al Stanton – RBC Capital Markets.

Good day everyone. Welcome to Kosmos Energy's First Quarter 2017 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 all of you for joining us today. This morning, we issued our releases regarding our first quarter earnings as well as the Yakaar-1 well results, which are available on the Investors page of the kosmosenergy.com website. We anticipate filing our 10-Q for the first quarter of 2017 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 our 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, 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 everyone. Kosmos is off to a strong start in 2017 and we have been diligently executing our plans to achieve the financial and operational objectives we set out at the beginning of the year. In summary, strengthen our financial position and deliver explorations success.

During the first quarter, we continued to generate free cash flow and delivered on our promise to reduce leverage, paying down $150 million of debt.

We're on track to generate $250 million of free cash flow in 2017 at just $50 per barrel, we remain one of the few E&P companies generating significant free cash flow, keeping Kosmos in a solid financial position. Operationally our work in Mauritania and Senegal is off to a strong, building on the positive momentum created by the BP transaction.

I work grows on the development of Tortue is making good progress, enjoying the course that we achieved several important milestone. In late March, we started our second phase of exploration drilling ahead of schedule on what is one of the highest impact exploration programs in the industry over the next 18 months.

With a positive result in Yakaar we announced this morning, we've maintained our 100% exploration success rate and are now six for six in the basin. Importantly, we are at the front-end of an exciting multi well, multi basin and exploration program.

As I go to my remarks today, I’ll provide an update on our Ghana operation and then discuss our progress in Mauritania and Senegal. At point, I’ll hand the call over to Brian, who will provide additional details on the Yakaar-1 well and its positive implication for the rest of the basin.

Lastly, Tom will review the financial results of the quarter and our solid financial position. Turning to Ghana, which underpins our near-term production and free cash flow growth. At Jubilee revised offloading procedures continue to work as planned and our insurance coverages are effectively mitigating the financial impact of this year.

The FPSO was temporarily spread moored at its current heading in late February, which has removed the need for tugboats that were previously on station to provide heading control. During the first quarter growth, sales production averaged approximately 82,500 barrels of oil per day under the revised operating procedures.

The ultimate long-term solution remains under evaluation by the partnership. At TEN production averaged approximately 50,000 barrels of oil per day over the first quarter is on track to meet the operators 2017 guidance.

High production level have been achieved for periods throughout the quarter, as the partnership continues to optimize facility throughput and oil production. I'll now turn to Mauritania and Senegal operations where we continue to have exploration success and where we remained focused on advancing the Tortue gas development.

In late March, we began a multi-well exploration program that will have some of the largest prospects banks identified by the industry in the last several years. We’re pleased to announce that our first well in the series Yakaar-1 has made a major gas discover.

Reaffirming our view that the basin holds significant prospectivity and will continue to grow. While Brian will review the specifics relating to the well, there are several important takeaways I want to highlight.

Firstly, approximate Pmean 20 Tcf of gas discovered between Yakaar and Teranga, create the opportunity for a second cost competitive LNG hub in Senegal in addition to the Tortue development. Second, Yakaar-1 further derisked the key play element of the basin for fan fairway demonstrate the play contact works.

Although the industry perception was that degradation of reservoir might be expected as we journey further outboard, to think highly porous and permeable reservoirs encountered at Yakaar prove otherwise.

In addition the proven effectiveness of the seal and trap provides an important positive read-through for our prospectivity in the basin, the bulk of which resides in similar basin for fan setting. Third our view of the basin underpinned by geologic model remained sound.

What we found in Yakaar was a gas with similar to what we encountered at Tortue and Teranga and within the pre-drill uncertainty range based on preliminary analysis. Key to this was a higher thermal gradient we encountered at the Yakaar-1 location, which we believe is due to increased eating in the Yakaar area.

Given the size of our entire position, there will be a range of outcomes across the acreage, but we remain confident there is a combination of oil, liquids and gas to be found on our blocks with a focus on liquids and oil in our Northern Mauritania acreage.

Fourth, our seismic and AVO tools continue to accurately predict reservoir and hydrocarbon as demonstrated by 100% success rate. As we continue our second phase of exploration drilling, this gives us additional confidence around our remaining prospectivity and we expect to maintain a high success rate as a result of our well calibrated tools.

Today and as I told you, the Kosmos/BP partnership remains focused on delivering a low cost LNG project with FID expected in 2018 and first gas in 2021.

We continue to expect Tortue to be the first development project, given we have completed appraisal drilling, the project planning is well advanced and a development concept is already been agreed by the partnership.

The development concept accelerates first gas production and its scalable providing the opportunity to add capacity as demand for LNG grows. During the first quarter, we achieved several key milestones that are prerequisite to progressing towards FID.

The initial development concept envisioned by Kosmos for Tortue, which we achieve to deliver a full cycle breakeven for less than $5 per Mcf is now being validated by BP.

The partnership is also initiated other workflows such as metocean studies as well as geotechnical and geophysical work along the proposed pipeline route from the field to initialize location, whether midstream liquefaction facilities are planned. The design of and the planning for the Tortue drill stem test or DST is complete.

We expect to mobilize the rigs Tortue in the coming weeks. With this work in advanced stage, we expect the decision on a midstream solution in the middle of this year.

The partnership also continues to meet regularly with the host government and respective NOCs of Mauritania and Senegal to progress the intergovernmental cooperation agreements or ICA and the unitization agreement. We expect formal speed work to begin later this year, post the DST and the approval of the ICA by both governments.

After the first quarter ended the partnership structure was further simplified, when BP purchased the ownership share of our minority non-operated in Senegal. This transaction leaves the Kosmos/BP partnership even more strategic in line on the vision for gas development and exploration throughout the basin.

I'll now turn the call over to Brian discuss the result of the Yakaar-1 well and our upcoming exploration program.

Brian?.

Thanks, Andy. As Andy mentioned our second phase exploration program off-shore Mauritania and Senegal, which is designed to define and test the detached basin floor fan fairways of the airport protection petroleum system is progressing well.

Indeed Kosmos together with our partner BP is leading the industry and exploring this emerging deepwater theme along the Atlantic margins, so obviously an giant and supergiant prospects. Acquisition of our 3D seismic surveys is now complete and the data at various stages of processing.

In March, we spud the Yakaar-1 the first in a series of four independent wells that we plan to drill through the first quarter of 2018. I’ll first discuss the Yakaar-1 results, as one of the recent 3D seismic interpretation findings.

I’ll then discuss their exploration implications specifically and respectively in regard to the further derisking and increasing hydrocarbon potential of the basin floor fan fairways, including further north in Senegal, a long trend in Mauritania.

As a reminder, Yakaar-1 was designed test the lake Cretaceous space in floor fan approximately 50 kilometers west of the Teranga-1 gas discovery.

The fan comprises a series of extensive amalgamated channelized sending any reservoir systems that will seal in formationally and trap those as very graphically structurally as well as charge from a deeper build Cretaceous Neocomian-Valanginian source. As Andy mentioned Yakaar is a significant gas discovery.

The well encountered a gross 120 meter or 394 feet hydrocarbon column, which includes 45 meters or 148 feet of net pay. The reservoir comprises three stacked high quality channel sands with excellent porosity and permeability. Gas water contact was encountered in the lower zone.

The reservoirs which are ample supported extend over a very large area, approximately 280 square kilometer in size. Most likely Pmean resource is estimated at 15 Tcf, which volumetrically met the pre-drill expectation. Indeed the Yakaar-1 is understood to be the largest hydrocarbon find in the world to date in 2017.

Preliminary estimates based on the fluid pressure grades and a right size sample measurements, suggest the gas or the CGR or condensate gas ratio in the Tortue to Teranga range.

As noted earlier, Teranga-1, the Yakaar-1 well has discovered a Pmean of approximately 20 Tcf of gas in the KR [ph] performing block in Northern Senegal and this volume provides the opportunity for a second major independent LNG project in the country. We together with BP will now begin work on an appraisal plan for the Yakaar discovery.

As you may recall our pre-drill hydrocarbon charge model predicted a higher chance of liquids at Yakaar.

However, as Andy mentioned the well encountered a substantially higher geothermal grade than anticipated, which we now make believe maybe due to increased heating associated with the adjacent Dakar across the fracture zone or a Cape Verde swell as is evidenced by the preponderance of sales intrusions in this part of the basin.

This heating has caused the primary and deeper Valanginian cogging source. Within the journey of the Yakaar-1 trapped to be gas rather than oil, I’m not sure.

Any oil or liquids generated with frac to gas a deck and therefore with little or no contribution from the shallow Albian or CT sources, which will mature in this faster basin, the result is a gas with a lower liquid content.

That said and although we can expect the charge model to continue to be refined locally as new geological information becomes available, we consider it still to be fundamentally sound. Importantly, we now believe that higher geothermal grade is encountering Yakaar-1 will result in the northern part of Senegal, having a higher propensity for gas.

However, we are of the view that the geothermal gradient produces north from the factory zone to Mauritania. This is supported by the 10% encountered during clearly in board to the north inward to the north, including well being in adjacent to our Mauritania acreage.

Modeling the same trend in thermal gradient reduction towards the airport areas, so the north in Mauritania, then the Valanginian-Neocomian into the source, may not be exposed to temperatures required to crack oil to gas. Allowing for a higher liquid content in the base of floor plan prospects over the north in Mauritania.

Based on this we remain resolute in our belief in the oil and liquids and potential, the Cretaceous petroleum system, particularly in Mauritania, with the vast majority approximately 75% of our many prospects resigned.

This is due to the modeling of a less mature deeper, Valanginian to Neocomian source or coupled with a progressively greater contribution from and mixing with the younger Albian and CT sources in board.

As a sixth exploration in an appraisal well offshore Mauritania Senegal, the Yakaar-1 discovery maintains 100% success rate, confirming the predictive powers of 3D seismic view of maybe another tool.

Importantly, also further derisks from a place standpoint, the ample based on fairways, during our first exploration campaign where reservoir presence, thickness and quality as well as, our debt trap effectiveness including seal and pin shaft.

The Yakaar-1 well together with the 3D seismic calibration, it provides how to a large extent it used all of this play concerns from outboard basin floor fan fairways that are focused on that second phase exploration drilling program.

In addition to further derisking of the outboard basin floor fan fairways we believe that hydrocarbon potential can be much could be much larger than previously thought. Acquisition of our new 3D seismic, which target outboard Mauritania including of Block C8, C13 and C6 and C12, as I mentioned earlier is now complete.

These early process volumes an interpretation products are becoming available. As expected these data of confirming the lease and prospects identified previously on the regional 2D seismic ad in many cases these prospects are significantly larger than originally thought due inpart the greater resolution provided by the 3D seismic versus the 2D.

Furthermore you prospects continue to be identified. A good example of one such prospect is Hippocampe in the northern part of Block C8 offshore Mauritania.

The head of count prospect comprises a series of very thick extensive stack basin floor fans of Cenomanian and Albian age trapped in a combined structural stratographic closure and charged by the mixing of hydrocarbons from Valanginian to Neocomian and potentially Albian sources.

Both reservoir targets are very strong seismic attribute support the hydrocarbons including calibration AVO. If a camp has a premium resource estimate of over 2 billion barrels of oil equivalent. With respect to the forward outlook achieve the rig schedule as planned, the next operation will be the Tortue Field drill stem test.

This is expected to extend through early August. Subsequent to this, given our objective in finding oil and/or liquids, we will shift our exploration focus to Mauritania for the charge related factors discussed earlier.

In this regard, the two reasons, we are considering testing the hit the time [ph] immediately following on the DST, rather than directly on as previously planned. Firstly, Requin requires more time to fully define the material drilling. Secondly, because of the more optimal position and potential size of the Hippocampe prospects.

We will then complete the full well second phase exploration drilling program with Lamantin and Requin Tigre. However as always drilling order is subject to change based among other factors on exploration drilling outcomes and ongoing subsurface technical work.

I’d now like to provide a brief update on the rest of our exploration portfolio, where work is ongoing particularly in Suriname and São Tomé to material both are is which we regard as oil provinces for the drill-ready stage.

At a time when conventional exploration particularly deepwater, as well as, oil and gas discoveries are at an all time historic low, Kosmos in typical contrarian counter-cyclical fashion remains focused on opening the next petroleum system.

In this regard, we continue to be one of the most active explorers today, including in terms of our 3D seismic and drilling. We are in the process of shooting over 30,000 square kilometers of 3D this year. This represents over 20% of contracted deepwater global 3D acquisition.

Offshore Suriname we are currently processing the new 3D seismic acquired earlier this year of Block 42 and part of Block 45 in support of going up to two wells in Suriname in 2018.

Early volumes and interpretation products of this new 3D seismic are being received and just as we are seeing in Mauritania and Senegal, this is confirming the multi-billion barrel potential, we previously identified on regional activity.

Importantly and very encouragingly based on recent offset drilling including both successful, the Sinopec discovery along trend in Guyana and the unsuccessful, the Kolibrie dry hole Blocks in Suriname, which by the way are results we both predicted.

We are now able to positively and negatively calibrate the 3D seismic attributes including AVO, with these outcomes further derisking our key prospects. These include Aurora in Block 42, Anapai in Block 45, both of which are just very strong and now calibrated seismic AVO support for the presence of hydrocarbons.

In sales São Tomé, are approximately 16,000 square kilometer 3D area, which is the largest in Kosmos’ history and one of the largest ever conducted by an operator offshore West Africa is more than 50% complete and is expected to finish next quarter.

Moreover as one of the few active explorers, we're also learning a new ideas are being developed to generate industry leading exploration contexts and themes.

These create competitive advantage and allow us to execute our proven concentrated portfolio arrive with short exploration strategy in frontier emerging basins and in so doing replenish and hydrate our portfolio through active new venture initiatives.

So in closing we are very excited about how we are organically building the company through deepwater exploration.

We continue to significantly grow discovered hydrocarbon resource base offshore Mauritania and Senegal with 100% success rate and the future potential in this very large Cretaceous petroleum system continues to increase with new 3D seismic and well results.

Furthermore, in our efforts towards the new petroleum system, the new 3D seismic calibrated by recent offset drilling results continue to further derisk the prospect invention in Suriname, which really represents a proven play extension to the recent industry success in Guyana. Or provide drilling opportunities in 2018/2019.

In summary, at Kosmos the prospects that are preparing to drill and the debt of the portfolio has never been better. I’ll now turn the call over to Tom to discuss our financial position and our first quarter results..

Thank you Brian and good morning everyone. A positive free cash flow trend continues into 2017 and Kosmos remains focused on improving our already solid balance sheet and maintaining our liquidity.

At the beginning of the year, we announced our plan to generate approximately $250 million of free cash flow based on a $50 Brent price and to you use these funds to pay down debt and build liquidity. We're delivering on that promise having paid down $150 million of debt through the end of March and a further $50 million to the end of April.

And are well on our track to reduce our overall net to debt to approximately $900 million by the end of the year. At the end of the quarter we have $1.3 billion in total corporate liquidity, including capacity on our RBL and RCF facilities, as well as available cash.

During the quarter, we completed the semiannual redetermination of our borrowing base, which as expected resulted in a decrease of approximately $150 million to $1.3 billion. The new borrowing base which is effective April 1, reduces total liquidity to $1.2 billion.

The reduction in RBL capacity is driven by the remaining production of the lone life under the facility, but is more than sufficient for us to run the business. While at the same time, reducing undrawn commitment fees and associated interest expense.

That said we plan to extend our facility and add back that liquidity prior to March of 2018, the period in which amortization of the current facility commences. Now I’ll turn to the results for the quarter. We finished the quarter with two crude oil liftings both from Jubilee in line with our guidance given on the year-end call.

This generated first quarter 2017 oil revenues of $103 million, excluding $11 million of derivative settlements. When you add a revenue to our sell hedges, it reflects the realized price of approximately $58.12 per barrel in the first quarter.

First quarter revenues were up compared to the same quarter in 2016 as a result of higher realized oil prices, as well as, reduced production related downtime at Jubilee. During the quarter, we also received $48.5 million of net LOPI proceeds in line with guidance.

For the first quarter, we generated a net loss of $29 million of $0.07 per diluted share. Adjusting for the impact of one-time items that affect comparability including a $38 million mark-to-market hedging gain the company generated a net loss of $43 million or $0.11 per diluted share.

On the cost side, operating expense for the first quarter was $20 million or $10.06 per barrel versus $29 million or $15.50 per barrel in the first quarter of 2016.

For the quarter, this included approximately $16 million in regular operating expense and $9 million of costs attributed to the revised operating procedures offset by $5 million in insurance recoveries.

Exploration expense $106 million for the first quarter included one-time rig related expenses of approximately $90 million, which includes the costs associated with the stacking of the Atwood Achiever and the catchup payment associated with the cancellation of the Atwood Achiever contract extension.

In addition, exploration expense included $16 million of ongoing seismic and geological and geophysical costs. General and administrative expenses were $16 million during the first quarter, slightly down compared to the same period in 2016. The result of lower non-cash stock-based compensation and carried costs as a result of the BP transaction.

Depletion and depreciation expense for the quarter was $35 million or $17.70 per barrel, a slight increase from the prior year period. The result of a higher depletion rate arising from a decrease in Jubilee Field proved reserves in the fourth quarter of 2016.

Compared to the fourth quarter DD&A decreased by almost $7.50 per barrel primarily attributable to lifting only cargoes from Jubilee in the first quarter, which has a lower depletion rate than the TEN field. Taxes were $22 million or approximately $11 per barrel with almost 100% on a differed basis.

We continue to maintain our strong hedge position and currently our hedge has totaled approximately 11 million barrels with approximately 5 million barrels hedged in 2017 with an average floor price of $59 per barrel. And approximately 6 million barrels hedged in 2018 with an average floor price of $53 per barrel.

The company's robust hedging program remains a key component of our strategy to protect our cash flows, balance sheet and liquidity. Before I turn to guidance, there's one housekeeping note I'd like to address.

As a part of the first quarter 2017 transaction in Senegal with BP we assigned our interest in our petroleum contracts in Senegal to our affiliate company Kosmos BP Senegal Limited or KBSL, a corporate joint venture entity in which we own a 50.01% interest. Our investment in KBSL qualifies for the equity method of accounting.

From a practical standpoint, on our balance sheet you will see a reduction in our property and equipment line. And the addition of a new equity method investment asset in the other asset section of the balance sheet. This reflects our cost basis in the joint venture. There is no near term impact to our income statement.

Now I’ll turn over to our guidance for the rest of the year. Our 2017 production guidance of 11 cargoes net to Kosmos including eight from Jubilee and three from TEN remains unchanged. For each of these remaining quarters in 2017 we anticipate lifting two cargoes from Jubilee and one from TEN.

Cargo sizes are expected to be approximately 950,000 barrels. Also on the revenue side, we still anticipate receiving net LOPI proceeds of approximately $70 million during the first half of 2017. Based on our current production forecast, $49 million of which has already been received in the first quarter.

With regard to our previous $175 million net capital program announced earlier this year, we have now decreased our 2017 budget to approximately $150 million after refining the cost estimates for our work program for the year. $75 million is earmarked for Ghana.

The majority of which is expected to be spent on Jubilee and $75 million is earmarked for planned exploration activities including new ventures, seismic acquisition and geological and geophysical technical fees. Our remaining guidance on operating costs, depreciation, taxes and G&A have not changed.

As we execute our strategy, we are committed to maintaining the strength of our balance sheet and creating value for our shareholders through this cycle. Kosmos remains in a solid financial position and we will continue to focus on the execution of our plan for the remainder of the year.

That concludes our prepared remarks, now operator we’d like to open the call for questions..

[Operator Instructions] Our first question comes a line of Bob Morris with Citi. Please state your question..

Thank you. Congratulation, Andy, Brian and team on Yakaar discovery. As pleased to see that you’re going to move next after the drill stem test to, what is purely black oil prospect.

But as you come back and look at the Requin prospects there, you've already discovered about 20 Tcf of gas, you highlighted the reasons why you have a lower condensate to gas ratio there.

But two parts to my question, one at what point do you say look we've already discovered enough gas and as we look at all the LNG projects coming on in the world when is enough gas and do we continue that there may be shift to oil prospects as we identify those, post Hippocampe prospect.

And then two, I thought I recall you last quarter saying you needed CGR ratio of about 50 barrels per million cubic foot to be economic. So, I guess my question now is with where his CGR is today.

What would be the breakeven natural gas price so to speak to move forward with development of these projects or for future projects if you do make more gas discoveries here?.

Yeah, I’ll take the second one first, Bob and then Brian will come back to the exploration program and our objective of targeting liquids as we get all. I think in terms of Yakaar, I think you should see it as a second LNG hub in Senegal.

Yakaar with Teranga is probably around 20 Tcf of resource and as you say it’s sufficient to underpin a world scale LNG project. So I think it is an LNG stream with the condensate flow rather than being a liquids recycling project.

We see similar economics with Tortue versus and a Teranga, a Yakaar I think to be cost competitive today, a $5 per Mcf, FOB is the target. Clearly there’s a lot more work to be done on the Yakaar and Teranga to level that. But as we look at the scale of the resource that there is there, it’s actually advantage from the scale perspective.

It has similar reservoirs to Tortue and therefore comes with high deliverability wells. So further appraisal at the Yakaar required now, but fundamentally the target there in terms of being a cost competitive use source is no different.

So that answers, I think your second question and if I just go to Brian for the first question, which was about what are your plans targeting liquids and oil as go north in Mauritania?.

Yeah, thanks, Andy. Good morning Bob. I think the first point to note is that we’re still very, very early on in this exploration campaign and to open this frontier base enough. This is 2,100 Gulf Mexico block, so it's a very big area. But as we drill wells, we now about six in the ground.

We’re beginning to slowly understand the area and the first point I would make is to your point to be honest, is that northern Senegal clearly is a giant gas resource area for us. We've now made, you include Tortue three discoveries, out of three in Northern Senegal in the two blocks.

And Requin Tigre, which is a 60 Tcf prospect that's been further derisked by Yakaar-1 significantly, remains undrilled. So, a giant gas resource in that area, but to your point, we are focused on funding oil and liquids. And that's one of the reasons from a play standpoint that we’re moving further north.

I think we started to understand the petroleum system in good detail in Northern Senegal. We still have very little understanding in northern Mauritania where we've got limited number of penetrations. So, Hippocampe it’s located in the northern part of Block C8, it’s actually 225 kilometers away from Yakaar.

It gives you a sense of the scale of the space.

And if you’re putting a well down there it's going to help us better understand the presence of source rocks, the quality, their maturity, their timing of migration et cetera, which will start to allow it to get a really good handle on how the petroleum system is working up there and more important and as importantly.

The nature of the contribution from the two shallow resource rocks, the Albian and the CT, which we haven't yet tested because in the wells that we drilled, the CT and Albian has always been immature or at best very marginal mature for the Albian.

So, that's one reason, this mixing of the shall hydrocarbons with the deeper hydrocarbons we think is going to give us a good chance of finding liquids to the north. Deeper count though won’t be definitive, it's one of a number of prospects in northern Mauritania. We’ve previously talked about Lamantin been our best chance for oil.

That area in general northern C8, C6, C12, we believe it's got a good opportunity to find liquids and oil and the explorations program is going to shift to that area for the first test we believe would hit account at this point..

Great now it makes sense and again congratulations, just very quickly, but the first LNG train down south coming on 2021 what would be the date or timing second LNG train?.

Well, I think it's a little early to say, Bob. But I think it’s sort of several years later. I just because they probably to work, who would be required So, I think it's probably in middle of the next decade..

Okay. Great. Thanks a lot and we’ll seen you on Wednesday in Boston..

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

Yes, good morning and congrats on the discovery.

Just on Hippocampe really small question, start with on timing, obviously you’ve done the DST, when do you think you’d be able to get on to be drill ready for that?.

Yeah some time around, late third quarter, August timeframe at the moment is the thinking..

For spudding?.

Yeah, spudding, yeah, yeah. A little early or mid third or fourth quarter when we get down..

Right. And then, if maybe one for Tom on financial capacity, and obviously you’ve got the liquidity, you've got cash on the balance sheet, the CapEx this year is low and you’ve got the carry. But success breeds spending, which is a good thing, but you’re going to be spending across Mauritania, Senegal plus São Tomé, plus Suriname.

So, maybe just a talk of plus obviously at some point starting to put money into a development less the carry of the LNG system.

So, I don’t know if you at the point got a sort of a range of capital spend that you might see in say, 2019 or maybe some general comments about managing liquidity?.

That’s a good question, Ed. It’s a little bit too early to talk about capital spend.

We’ve just had the first well at Yakaar-1 down and we’ve got three more to go this year and then Suriname in 2018, so suffice it to say though that we’re obviously looking forward and then doing some forward planning on the ability to continue to develop these successes. But a little too early right now to disclose any detailed plans..

Yeah Ed, what I’d add is that clearly we have the BP transaction, we support DD&A expand in 2017 and a good piece of 2018 depending on the follow-on exploration success we will have in Mauritania and Senegal. So, and then of course the development study, as development is slow too, it’s sort of around $2 billion through to first gas.

So, the carry is 533, so therefore, we are well supported in that in terms of the development. So, I think the good news is of course, though, we’ve build the raise from balance sheet ahead of success, then we actually did the BP deal to ensure that at a sort of 30% operating interest we could carry on with the program.

So, I feel good about how the strength of the balance sheet through 2017 and 2018. The ability for us to be fully, apart 30% through Tortue. Then, obviously we have options and the further success on how we would manage that in 2019. But I see this as an opportunity not a problem..

Helpful clarification, and just one small one. Do you think Yakaar, Teranga will be suitable for the same sort of development idea where you do a near shore sort of floating LNG system. I don’t know what the shore line looks like down at that point. I mean, obviously, it’s close to Dakar, which might be good for power stations..

Yeah, what I’d say, again, early days. I think the thing that I would add probably in contextual sense is that, as Brian said, we kind of announce the blocks in Senegal and Saint Louis and Cayar, I think to be gas.

And similar to Tortue, similar to Teranga, similar to Yakaar, that’s clearly more gas exploration to be done, which would be the giant Requin MT growth for our prospect. So, I think what you're going to see is we're going to come to that well, is the last well in our four well contain, which we’ll drill sort of, early 2018 I think.

I think when you got out that well down, you'll be able to look at the total resource there and it may result in a sort of different long-term approach, which may be an onshore scheme actually. Why you got early gas established the market through the Tortue development and then you come back to a larger scheme, that’s scalable.

So, I think its early days, but I think what we have to think about really with the government of Senegal is that we have a large resource there and how do we most effectively develop that both the sort of near term objective as early gas, which is to Tortue versus a long-term objective about a potentially sort of world scale resource and what the right development scheme for that..

Congratulation. I caught about in time..

Yeah, you did. Thanks, Ed..

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

Thanks. Good morning to everyone congratulations as well. Looking at the liquids component in Yakaar.

Andy could you review the potential approach be it related to that from the BP form-out agreement and how should we look at that piece of the puzzle?.

Well, Richard, I think is a little early, okay. We know to be clear, we have great preliminary result from NBTs. So, until we get the actual lab results then I think it would be wrong to speculate, so I will have a confirmed actual CGR later. I believe that it's in the range of what we’ve experienced today, i.e. no different.

And then I think when we have that, we can then model it and give you the flow-through. Look, we going to condensate stream from Tortue, that clearly be a condensate stream from the development of Yakaar and Teranga and that will be contribute, there will be a contribution from the royalty that we have under the BP agreement.

But to quantify it today, I think is a little early, I think you need to give us a bit more time to work that..

No, that’s fair. I appreciate that.

Once the if those decision is announced, when could the group resume drilling at TEN and possibly even look to raise the production outlook from there?.

Well, I think Richard you'll see the group actually getting back to drilling fairly quickly. So, I think we’re obviously making plans around that eventuality now. But as you know the rig market is quite accessible today in terms the ability to get rates. So, I think you'll find it moving quite quickly..

Okay.

And then just lastly, how long do you expect the Tortue drilled stem test to take?.

We have it in the program at the moment, sort of being around 75 day program, it’s quite longer than the current well programs, we tell that its about 60 days for each of the wells in the program around 75 days for the drill stem test..

Okay. Well, thanks very much. That’s all for me..

Thank you. Our next question comes from the line of Anish Kapadia with Tudor Pickering, Holt and Company. Please state your question..

First question is really on the kind of state of the market. We saw recently Exxon and Mozambique, they implied gross value for books, so they went into a very first $11 billion for an LNG development.

So, just trying to seeing, how do you see the effective landscape in Senegal and Mauritania how that changed over roughly kind of last 12 months? And how it actually changed since the BP deal?.

Well, look, Anish, I think what our business model is about, we go in the frontier basin is early. They were before the industry spotted it. So they get rich positions and Brian described to you the size of the acreage position we have.

Clearly with a successes we've had it's become actually very competitive and we’ve recently seen an announcement where Total have gained the block in Senegal. The acreage is now, the basin is now being derisked and then that clearly makes it more competitive.

So, we welcome new entrants, which is great, we have the second super major in Senegal, as well as, BP which I think illustrates the quality of the of the acreage of the industry sees that. I would anticipate similar things occurring in Mauritania, the good news for the Kosmos of course, is that we were in there first.

We've got the great position and we captured what we believe is the core of the basin. But I do think your observation, the flow of IOCs coming is a demonstration the quality of the acreage..

Thanks and second question on Suriname. Say it sounds like from the comments earlier on the call, encouraged by both of recent well results, both positive and the negative one. It sounds to me like your prospects grilled ready and alignment.

So, I was just wondering, what was, and I suppose what’s the kind bottleneck or the hold up in terms of you accelerating drilling on your prospects in Suriname..

Yeah, again, great question I'll hand it over to Brian..

Yeah, hi, Anish. Yeah, it’s not quite already is the answer. We have the very early, processing products, interpretation products from the 3D. But as we’ve mentioned on these calls, in recent quarters we’re really encouraged because if we unto gets better on 3D and that’s not actually what we’re seeing.

The AVO volumes actually I've just very recently come in in-house. They themselves incredibly encouraging as well, but it's all got to be put together and the prospects of mature take much of the rest of this year to do that. We were very encouraged by the offset drilling.

We all went down dip all of the channel system that stepped it there by Kolibrie we’re at the base of the slope, and where our long trend directly from the recent Exxon Mobil discoveries in the same kind of fairway.

So, with those two calibrations that we can compare against the AVO that we're seeing and on our key prospects that's what gives us the, I guess, is the added confidence that what we're dealing with here are very strongly supported seismically, supported AVO prospects.

In terms of the rest the timing, in Suriname, we have one block with Chevron at 50/50 and we have a second block with Chevron and Hess where we’re a third. So, the challenge for us beyond the definition of the prospectivity is to bring the alignment of the partnership. Show that we can make sure these prospects stand today on the shelve for too long.

But get drilled obviously, they’re very strategic to Kosmos, where quickly in an oil province is Suriname. That's obviously important to us so, and given the scale of the prospects, which are multi hundred million barrel prospects we are very excited by what we’re seeing..

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

Hi good morning team. The first question is just around Jubilee. Can you just talk about your production expectations for Jubilee for the balance of this year and then into 2018 as well..

Yes good morning Neil. We’re targeting production there it was around 58,000 barrels a day, eight [ph] cargoes..

I know they are obviously issues last year, but can we just talk about how the ramp that’s going in term of getting the asset back to full capacity?.

Is that Jubilee okay..

Yes Jubilee..

In Jubilee, we've actually progressed the repair of the spread mooring of the turret with the spread mooring. We now have the tugs that we're holding it on station have now departed, so we have the vessels turn more. That obviously provides stability in the current in the configuration. We still are using the shuttle tankers to off load the crude.

And we’re seeing an improvement there for in the operating performance we sort of underpin the number that I gave you..

That’s great. And congrats again. 6 for 6 [ph] is great and rare in exploration. But I want to go back to I guess the first question that was asked that just up the global gas macro and just how are you thinking about that piece of the business that the market appears to be well supplied for the foreseeable future.

And so how do you think about this discovery, that Yakaar discovery and the context of a market where there is a lot of supply out there?.

Yes look at, I mean it’s very interesting. I’d say two things really. The first is the world is looking for a lighter hydrocarbon and we can see all the super majors lightening their barrel. BP have an objective, Total has a similar objective, Exxon has a similar objective.

You see now Exxon actually make string of gas acquisitions, P&G now in Mozambique. So I actually think gas is valued today and it’s valued for the long-term. And what we’re seeing is the quality gas is what actually distinguishes one gas resource from another. And so you are right plenty the gas around, as growing gas demand.

The gas that will get to market is the low cost gas. And we believe both in Tortue, and now in Yakaar and Teranga we have gas that is very cost competitive. It’s frontend of the cost cure.

And that’s the important point here is that in the quality of the reservoirs that we have, the scale of production that are going to come from those wells are very innovative development solution, that’s cost effective because this is at the right at the front of the cost curve.

And we have a development partner in BP now that can absolutely develop and deliver that and it has the marketing skills to make that that gas gets to market. They were the buyer of the of the energy.

So you put all that together and you are very positive about the gas story, but it’s about the quality of the resource, the simplicity of the partnerships, the right skills and development and the right marketing. And I think we have a partnership and the resource that absolutely has all of the attributes..

That’s great. The last question from me is around hedging.

The curve obviously has come down in the back end of 2018 and 2019 but is your approach to hedging to take more for pro rata approach? Or you just sort of hedge into the curve or will you take a more tactical approach to hedging? Just can you talk about the strategy around blocking and barrel?.

I’ll answer that. Over business is worth $50 a barrel. And what we’re doing is making sure that we’re hedged to ensure that we can execute give that outcome. And so in essence we are hedging a significant proportion of our barrels to ensure that we have the flow at $50 and we’ll continue to do that..

That’s great. Thanks for the time. Congrats again..

Right thank you..

Thank you. Our next question comes from Pavel Molchanov with Raymond James & Associates. Please state your question..

Thanks for taking the question guys. You’ve given some indicative economics for the first phase of the LNG project, you said, I think, sub-$5 kind of breakeven.

What assumptions for fiscal terms does that assume? And maybe you can’t be very specific, but I suppose have you finalized with both the Senegal side and the Mauritania side what the fiscal terms on the LNG development look like?.

Yes Pavel. I think the great news with both of the PACs that we in both countries that have an anticipated gas than have the fiscal terms of gas..

Okay, understood. Then a small housekeeping item, exploration expense in Q1 $100 million, obviously relatively high number, by historical standards.

What’s kind of the run rate that you would anticipate for the rest of the year given your lower CapEx in particular?.

Yes Tom do you want to do that?.

Can you just kind of remind – I’m sorry Pavel can you repeat the question for me real quick?.

Yes, sure, exploration expense in Q1 $100 million which is relatively high quarterly number.

I'm guessing it's not going to stay that high for the rest of year, but any thoughts on what you would anticipate for Q2, Q3, Q4?.

Yes Q2, Q3, Q4 is kind of as we’ve guided it will be – we’ll have some seismic expense in some typical G&G expense. So that will be in the $20 million range. The first quarter was a big one with the rig stacking and the rig cancelation catch up payments, so those are behind us now and so it should be just normal G&G expense going forward..

Right, appreciate it guys..

I’d like to follow-up on that. Pavel, I mean, from a exploration point, given the six for six on the exploration field at the moment [indiscernible] we are doing it on the seismic. And we’re obviously a bit on G&G as well. But that said, most of our major seismic programs are in place this year and early next.

But $100 million a year is about what we are trying to run this business at for the exploration expense, or exploration spend, notwithstanding [indiscernible]..

Thank you. Our next question comes from the line of Nikola Kouzmanov with Jefferies. Please state your question..

Good morning gentlemen. In preparations on Yakaar, this morning. Two questions on that, I suppose, and a question on Jubilee. I know you've already referred some of it.

On Yakaar, in timing around appraisal and if you're going to be looking to sort of delineate the gas discovery, we’re going to look for potentially more liquid zone within that 220 area of discovery? And then if it's an onshore development supposed to be big development, do you expect the economic threshold of 50 CGR to decrease from the price that I’m not thinking just in terms of Yakaar, but also Requin-Tigre? And then on Jubilee, the operator talked about you are talking about a 12-week shutdown for the final spread mooring but that's going to take place in 2017.

How does this impact your guidance on the eight cargoes and if there is any impact actually? Thank you..

design one, build many. We're driving through standardization. We're driving cost effectiveness into a small scheme.

I think the approach to the onshore if we do an onshore development, it will be very much aligned around that thinking, where we need to ensure we're standardized, we're not stick building, and we develop something which has scale and efficiency.

So I think, again, I believe we have something which is cost-competitive really because of the quality of the reservoir, the big gas rates, et cetera. And then finally, on Jubilee, I think its early days. We've clearly done the work to stabilize the turret by removing the tugs and doing the mooring.

There's further work to be done now, which the partnership is conducting as to whether the vessel needs to be rotated and when. And that work is ongoing, but we feel that our view of 8 cargoes is our best view of the future..

Okay thank you. Thank you very much..

Alright, great. Thanks Niki..

Thank you. And your last question comes from the line of Al Stanton with RBC Capital Markets. Please state your question..

Good afternoon. I'll be quick actually. So just two questions on the exploration campaign. First of all, 75 days for a well test.

I mean, what should we see as a good result for Tortue drill center?.

I think the first result in test is sort of twofold. What we're trying to do is actually get some liquids, some gas to surface, so that we know exactly the fluid composition we're dealing with. We need to have the basis of design for the LNG facilities. So in essence, we're looking at fluid sampling.

And then the second thing we're looking at is just well deliverability so that we can optimize the well design. But I don't think there's a big piece of information to come from the reservoir. It's really underpinning the basis of design to ensure that we've got the right fluid characteristics, and we've got the right well designed..

And then is there a bond burning rate that you would require?.

No I think these are very productive wells Al. We’ve talked about wells that are very high rate. And so what we're doing is ultimately ensuring we've got the right well design in terms of completion type rather than fundamentally saying we need a particular rig..

And then finally, you talking about Requin-Tigre extending into January.

So is that a hint of a rig extension or second phase of drilling with a different rig?.

Well the Requin-Tigre extending into January..

Okay..

And our rig contract ends in November..

Yes..

I can’t speculate beyond that. Yes..

Yes I will then okay..

That will be inappropriate to do that..

Okay thank you..

Alright thanks Al..

Thank you. There are no further questions at the this time. I would 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..

Ladies and gentlemen, this concludes today's teleconference. You may disconnect your lines at this time. And thank you for your participation..