Neal Shah - VP of Finance and Treasurer Andrew Inglis - Chairman and CEO Thomas Chambers - CFO Brian Maxted - Chief Exploration Officer.

Edward Westlake - Credit Suisse John Herrlin - Societe Generale Manish Kapadia - Tudor Pickering Holt Petr Grishchenko - Imperial Capital Al Stanton - RBC Pavel Molchanov - Raymond James.

Good day, everyone. Welcome to Kosmos Energy's First Quarter 2016 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 first quarter earnings release, which is available on the Investors page of the kosmosenergy.com website.

We've also published a presentation this morning giving an update on our Mauritania & Senegal exploration program, which is available on the kosmosenergy.com website as well. We anticipate filing our 10-Q 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. 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 ensure that we get to everyone on the call. If there are questions that we aren't able to get to within our one-hour 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 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 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. Before we dive into the details of our first quarter results, I want to step back for a minute and talk about the big picture. Throughout, the history of Kosmos, we remained disciplined in the execution of our strategy.

This focus has led to Kosmos opening, two world-class petroleum systems over the past 10 years, drilling only six frontier basin and opening wells at 1 and 3 success rate much better than the industry.

With our four recent follow-on successes offshore Mauritania & Senegal, it's becoming clear that this is a basin with significant hydrocarbon potential. We've already discovered more resource at a much larger working interest than we discovered in Ghana and we've only just started.

Our exploration portfolio continues to be rich in opportunity and we are entering an exciting phase in the company's history. And as a result of our financial prudence and disciplined approach to capital allocation. We are well-positioned to capitalize on the opportunities ahead of us.

The heart of our success is a dedicated group of people among the best in the business remained fully committed to our bright future. We've accomplished a great deal. But there is much more for us to do. I'm confident that our approach and work plan will create lasting value.

As I go through our remarks today, I'll start with an update of our Ghana operations. Brian and I will then discuss progress in our second inning portfolio in Mauritania & Senegal, where we announced our fifth successful well at Teranga-1 this morning and are quickly moving the gas discovered in the basin towards commercialization.

Then Brian will provide an update on our third inning portfolio before Tom reviews our strong financial position and results for the quarter. Now turning to Ghana. In our fourth quarter call in February, identified a potential issue with a Jubilee FPSOs turret bearing.

As a precautionary measure, we implemented additional operating procedures to limit the rotation of the vessel at that time.

Since that call further technical investigation confirmed that the turret bearing is no longer able to rotate as originally designed and as a results provides operating procedures were implemented, which allows the continued production on our long-term solution as identified and implemented.

Revised offtake procedure due to dynamically position shuttle tanker to offload from the FPSO and transfer to a Suezmax storage tanker before the oil is offloaded to the buyer's vessel and transported to market. I can confirm the production resumed on May the 3rd and we are now ramping up oil production levels and gas exports.

While this solution should allow for production to continue in the near-term, a long-term permanent solution is required. The Jubilee partnership has established a project team to study the root cause and determine the best path forward. A number of remediation options exist and we expect to make a decision over the next few months.

Kosmos does not expect these issues to have a significant long-term financial impact on the company due to continued production from the field and the appropriate insurance coverages we have in place.

The partnership level, Tullow has procured hull and machinery insurance for the joint venture, which ensures against damage to the FPSO and covers operating expenses in capital cost associated with this damage.

Kosmos also have his own loss of production income insurance or LOPI, which covers a loss of production revenue after a 60-day waiting period. Our production shortfall calculates the low count [ph] threshold is insured at a price of approximately $62 per barrel for 365 days.

However, near-term cash flows could be impacted by the timing of reimbursements. As there are number of moving parts in the interim, we expect to provide you with an updated full year 2016 production guidance once the long-term solution is selected.

So in summary, we've implemented procedures in the short-term to allow production offloading and export to continue. We're working diligently on our long-term solutions, which we expect to update you on in the next few months and we have the necessary insurance coverage in place to help mitigate the financial impact of the issue.

Moving to the TEN project, our second major oil development in Ghana. The project is now more than 90% complete and remains on budget and on time with first oil expected in the third quarter of 2016. The FPSO sales from Singapore in January and arrived on location in March.

Field hookup activities have begun and investments now being connected to the subsidy infrastructure by rises and then binnacles [ph]. The commissioning of these systems is underway. Additionally, the completion of the development wells is on schedule with seven wells completed to-date.

The project continues to progress well and we are pleased with this advancement. We'll now shift from our Ghana operations to discuss our second inning progress in Mauritania and Senegal starting with a successful well at Teranga, which we announced this morning.

Brian?.

Thanks, Andy. As I make my remarks, I'll be talking through the presentation provided on the website entitled Mauritania and Senegal exploration update. Turning first to slide two, in just over a year since we announced the Tortue well, opened up the Cretaceous petroleum system offshore Mauritania and Senegal.

Since that time, it made tremendous progress in further unlocking its hydrocarbon potential. Indeed, although exploration is still at an early stage results to-date, have already confirmed the province has is a world scaled gas resource and substantial follow-on potential for gas and oil.

Moreover, extrapolation of these results project the petroleum system to be one of the large - open along the Atlantic margins in the last 15 years. Let me remind everyone that our new ventures identification and access initiatives over the last few years have captured the vast majority of this prolific petroleum system.

And then now nearly 40,000 square kilometer acreage position, which is equivalent to roughly 1,700 government scale blocks. This is also equivalent to approximately 10 times the size of our acreage position we initially had in Ghana, but here, our working interest is significantly higher. It's an average 75% and we also hold operatorship.

The principal benefit of this is the control that provides in designing and managing the exploration strategy, including timing and sequencing of seismic and wells and the pace of spend. Completed 3-D seismic coverage, although significant is limited to less than half of the area under license offshore Mauritania and Senegal.

And we've only drilled four exploration wells. However, the 100% drilling success rates as well as the size of the discoveries and the defined exploration potential demonstrate that this is a super-major scale of hydrocarbon province and that the resource base is likely to continue to grow.

On the three inboard structural trends drilled so far, we believe we have discovered a resource base with the Pmean of 25 Tcf. When combined with the follow-on on-trend and calibrated potential we estimate we have a total gas resource base of over 50 Tcf.

All the wells we have drilled and have all been located along the inboard trend of the petroleum system in both Mauritania and Senegal. We've learned a great deal about this prudent petroleum system from a play standpoint. The first takeaways that the multiple prolific hydrocarbon column exists over our acreage.

The deeper most Apto-Barremian is now understood to be regionally the dominant source rock. We believe this has charged the Tortue and Marsouin as well as Teranga discoveries on the inboard structural trends at Mauritania and Senegal respectively, where it is gas mature.

We interpret the source systems to be on onshore outboard given the temperature information we have acquired. We've also drilled through the source rock in the shallow Cenomanian and Albian sequences. With the data acquired we consider these Cenomanian and Albian sequences to be all mature of a part of our acreage in Senegal and Mauritania.

Secondly, we have two high quality reservoir sequences in the low Cenomanian and Albian, which have been deposited by the Senegal and New York Shaft [ph] river systems, as we shall discuss again later. We believe that these are commercial in scale being reasonably extensive, thick and high quality Deepwater channel sands.

Thirdly, we've demonstrated the 3D Seismic and AVO attributes, which are now well calibrated by drilling, can be reliably used as an exploration tool to identify reservoir hydrocarbon fluids, although we are unable to discriminate between oil and gas plays at this time based on geophysics.

On this basis, we believe there is significant exploration potential including for both oil and gas on our licenses beyond the estimated 25 to 50 Tcf oil discovered and demonstrated. Indeed, we have four additional structural trends on our acreage that remain on tests.

Turning now to slide three, we show the results of Teranga-1, which is our fourth successful exploration well offshore Mauritania and Senegal over the course of the last 12 months.

The well has made another significant gas discovery maintained at 100% exploration success rate and derisked follow on potentially, which we believe is likely gas along the inboard Senegal trend.

This discovered a Pmean resource, gas resource of 5 Tcf having encountered 31 meters of net gas pane [ph] in a single hydrocarbon column, which resides within a good quality reservoir of low Cenomanian and NH [ph]. This channel system extends with AVO support approximately 30 kilometers down depth to the western limit of the existing 3D Seismic.

The next slide on page four summarizes from an exploration standpoint what we have done so far, what we know today and what it means.

Four exploration wells drilled to-date have been designed to test three structural trends including one in each of the three fairway which constitutes the inboard Senegal river reservoir system in the Southern Mauritania and Northern Senegal.

Specifically, these includes Tortue and Guembeul on the central fairway, Marsouin in the northern fairway and Teranga on the southern fairway. As previously discussed, we now know based on the results of the wells coupled with our 3D seismic and number of things.

Firstly, we believe the dominant source rock is from a deeper charge, which we currently interpret to be Apto-Barremian and that is gas mature inboard.

We know that together these four wells have discovered approximately 25 Tcf of gas and we estimate the total of more than 50 Tcf potential including adjacent prospects comprising well delineated and calibrated channel sand.

Prior to during Teranga-1, we believe that prospect had a reasonable chance to finding all based on the postulated presence, quality and maturity for working out the source kitchens located directly below the lower Cenomanian reservoir target.

The key risk to phase was considered to be the contribution of an oil charge from the Albian resource relative to a deep gas charge from the underlying Apto-Barremian.

It's important to note that we deliberately chose to accelerate Teranga-1 well before now drilling force, as it not only allowed us to test the key prospect on a separate independent trend, but provided us an opportunity to acquire additional technical information and enabled further well to seismic calibration.

Together these pieces of information would be critical to optimizing our next phase of drilling. While rock and fluid samples and analysis from Teranga-1 are not yet available given the well resources is speculated that the Apto-Barremian gas charge strongly prevailed at this prospect location.

While inherently in gross terms, a hydrocarbon charge model remains intact, and indeed indirect measurements while drilling and logging suggest the Cenomanian and Albian source kitchens are both presents and working.

Our focus going forward will be in further refining the model in order to better predict hydrocarbon phase with the play fairway in prospect scale. Specifically, our efforts will focus on more deeply understanding sourced to reservoir plumbing including migration pathways and timing.

Secondly, we know that this inboard Senegal river reservoir system is about 200 kilometers inland and the primary target of Cenomanian frequents extends and can be correlated across this distance.

This confirms to us that this reservoir is recently present, continuous, thick and high quality with the central Tortue fairway been the overall sweet spot.

This is important as the primary reason to generally, more generally for exploration failure in Deepwater to lack of reservoir or reservoir quality, and this risk is much less of a concern for us.

And thirdly, we know that the combination structural stratigraphic traps which fall on the prospects on the structural trends have been both Senegal of the inboard Senegal river systems as well as others consistent with work. To conclude, I want to turn to the last slide. Going forward, our plan has two primary goals.

Firstly, to develop the large gas resource that we've discovered. And secondly to define and test the other independent trends, which have significant potential including for oil both in Northern Mauritania and in the outboard of the Mauritania and Senegal. We have multiple 3D seismic surveys in various stages of acquisition processing.

In addition to the final processing of existing 3D seismic inboard Senegal during the first quarter this year we acquired 3D seismic outboard at Senegal and we plan to acquire additional 3D seismic outboard Mauritania in the third quarter of ‘16.

Prospect interpretation and mapping of these dataset through the remainder of the year incorporated with the player valuation of hydrocarbon source systems and charge mechanisms discussed previously will together enable us to develop an integrated VOD [ph] exploration potential at this Cretaceous petroleum system by the first quarter of 2017.

Based on this, we’ll formulate an exploration strategy and drilling program that is designed just falling a lot of the outboard Cretaceous petroleum system offshore Mauritania and Senegal in 2017 and ‘18. I’ll now turn the call back to Andy to discuss our activity on the gas monetization and the Tortue project..

In terms of moving forward with the inboard gas resource development, we believe Tortue would be the foundational project. We’ve been clear since the discovery well that commercializes resource, we would need to deliver 15 Tcf for high quality gas resource, as the government agrees on the gas development plant and finalize the development strategy.

You may consider progress across all three objectives in just 12 months since the initial Tortue-1 discovery. In Q1, we announced the successful results of the Ahmeyim-2 appraisal well offshore of Mauritania. This was the third well drilled on the Tortue West structure and together with Guembeul-1 it validates an LNG scale resource.

In aggregate Guembeul and Ahmeyim-2 have defined the Tortue West field limits extending the productive field area and significantly derisk reservoir continuity and connectivity. As a result, these wells have increased our Pmean extra months of gross discovery resource for Tortue West for 15 Tcf.

And we did base with one last well that initially planned. Beyond proving that the resource exceeds the minimum threshold we have growing confidence in the competitiveness of the project. The Tortue to be commercial today we believe it has to be competitive with the lowest cost LNG supply which is currently the U.S. Gulf Coast.

The scale and quality of discovery resource are major drivers are I believe that Tortue can be a competitive source of LNG. The wells we have drilled today demonstrate that we have a high quality gas and excellent reservoir quality. We have not [indiscernible] CO2 or H2S in the gas.

Furthermore, Tortue is a lean gas with low levels of liquids which should provide the options to provide the gas directly to shore a distance of only around a 130 kilometers with no Deepwater infrastructure required and minimal gas processing.

In addition, the well has proved the existence of excellent quality reservoir in both the Cenomanian and deeper Albian zones which should result in high well deliverability.

We believe that each well would be capable of delivering production rates of between a 150 million to 200 million cubic feet gas per day, reducing a number of development wells acquired. Both of these elements are critical delivering our low cost development enabling the project to move forward.

Given these attributes, we think the Tortue development can be one of the most competitive LNG projects in the world with an estimated upstream cost of approximately $2 per Mcf.

This combined with a competitive low cost FLNG mixed stream solution should provide the ability to deliver gas on a FOB basis at less than $5 per Mcf, which should place Tortue with the low end of the cost curve. Above the ground, we continue to make good progress and are very encouraged by engagement with both Mauritania and Senegal.

Both the government and national oil companies have been supportive of the project and taken a practical approach regarding the development of the shared resource.

Probably this year we entered into an MOU with national oil companies which outlined the principles of an inter-governmental co-operation agreement or ICI for the joint development across board of resource.

These efforts continue to gain momentum and discussions concerning unitization of the resource recently began modeled on the FIG [ph] agreement between the UK and Norway, which has been successful in the North Sea. We expect to finalize the ICI in the second half of this year, which will mark a major milestone in the project.

With all parties motivated and focused on delivering a competitive project, we believe that we are well-positioned to provide early first gas and maximize value for all stakeholders. The last key objective, we’re working to address is the development strategy for Tortue.

This time we're in serious discussions with a number of interested development partners who wish to work with Mauritania and Senegal including both large IOCs and contract developers.

With gas landscape changing rapidly, the industry is evolving to create new paradigms to fund and develop high-quality resource; given the various potential options we are evaluating them in parallel with an expectation to make a decision on the optimal structure later this year.

So in summary, we’re excited about momentum the Tortue project has created as a result of the quality of the discovery and its resulting cost competitiveness. I’d now like to turn the call back to Brian to talk about our exploration portfolio beyond Mauritania and Senegal, our third inning..

Thanks, Andy. I would now like to take a moment to remind you that, although we have opened a world class [Indiscernible] offshore Mauritania and Senegal. Kosmos remains committed to high grade in our exploration portfolio to open the next petroleum system.

With regard to existing assets, we are prioritizing a maturing petroleum those opportunities which offer the best chance for refining oil. In this context, we’ve recently completed farm out agreement with HAS [ph] covering up block 42 position offshore [indiscernible]. Block 42 is adjacent to the recent leased discovery located offshore Guyana.

We’re planning to schedule 6,500 square kilometer 3D seismic survey over this area commencing in the third quarter. This additional data should allow us to high-grade the prospectivity for near-term drilling expected in 2017 and 2018. Given the industry success in Guyana, Suriname remains top ranked opportunity in our portfolio.

And the recent agreement with HAS [ph] executed against the tough industry backdrop validates the quality of this opportunity. And we expected new ventures, we firmly believe this is the optimal time to build and high-grade our exploration portfolio kind of cyclically compared to the industry.

Consistent with our strategy, we're being selective and pursuing opportunities that are behind potential good fiscal terms, low firm commitments and are competitive in today’s price environment.

During January and February, we continue to build our position offshore Cenomanian by farming into blocks 5 and 12 in two separate transactions, which added almost 10,000 square kilometers of high quality acreage.

As a result of these deals, our aggregate acreage position offshore Cenomanian has grown to approximately 25,000 square kilometers across four contiguous blocks that enable us to explore the outboard part of the petroleum system, the members of our team [indiscernible] late 1990s in Ecuador.

With that, I’ll now turn the call over to Tom, who will update you on the financials..

Thank you, Brain. Before turning to the results of the quarter. I would like cover our financial position. Kosmos liquidity remained strong and we are committed to maintaining our history of financial prudence and protecting our balance sheet.

We have maintained our balance sheet strength, despite the prolonged market downturn and the quarter end, Kosmas had total corporate liquidity of $1.5 billion, including $877 million of undrawn availability on our reserve based lending facility or RBL, $400 million of undrawn availability on a revolving credit facility and $213 million of available cash.

During the quarter, we concluded our semi-annual bank predetermination on our RBL, which as expected did not result in a material change in our borrowing base. The borrowing base decreased by less than 5% or just under $74 million to approximately $1.427 billion driven primarily by a decrease in bank price debts.

This modest decrease in our borrowing base is a testament to the quality of our assets. Furthermore, we believe we’ll be able to maintain our borrowing base in the second half of 2016, following startup of the 10 field as a value of those barrels have not been fully captured in our existing borrowing base, but has expected to post first oil.

Hedging plays a key role in supporting our CapEx program by allowing us to protect the Ghana cash flows despite low oil prices.

We continue to maintain our strong hedge position in a quarter end, our commodity hedges had a mark-to-market value of approximately $185 million In early April, we executed a hedge for an additional 2 million barrels of oil for calendar year 2017, bringing our total oil hedges to 13.4 million barrels with approximately 4.5 million barrels remaining in 2016, 8 million barrels hedged in 2017 and just under 1 million barrels hedged to 2017.

This robust hedging program remains a core part of our strategy to maintain a strong balance sheet and protect our cash flows and liquidity. And we planned to continue to add protection on a regular basis. Now, I'll turn to our financial results.

We finished the quarter with 2 crude oil lifting generating oil revenues of $62 million, excluding $57 million of derivative settlements. When you add our revenue to our settled hedges, it results in a realized price of approximately $62.64 per barrel for the first quarter of 2016.

At the end of the quarter, the company was in over lift position of approximately 107,000 barrels more than our entitlement. For the quarter, we generated a net loss of $59 million or $0.15 per diluted share.

Adjusting for the impact of one-time items that effect comparability and company generated a net loss of $15 million or $0.04 per diluted share for the quarter. On the cost side, operating expense in the first quarter was $29 million or $15.50 per barrel sold versus $32 million or $16.90 per barrel sold in the first quarter of 2015.

The decrease in operating cost during the first quarter was primarily related to a reduction in non-routine workover activity that occurred in 2015 which more than offset the increase in operating cost related to our over lift position, the planned two-week shutdown and the FPSO turret bearing issue.

Exploration expense of $24 million for the quarter was largely related to our ongoing 3D seismic processing and interpretation in the onboard Senegal area. As a reminder, first quarter 2015 included $84 million of unsuccessful well cost.

General and administrative costs for the quarter including non-cash equity based compensation came in at $18 million. The sequential decrease compared to the fourth quarter of 2015 was driven by decrease of equity based compensation and lower cash expenses.

First quarter DD&A was approximately $31 million or $16.49 per barrel compared to $37 million or $19.48 per barrel in the first quarter of 2015. The decrease was based on a lower deflection rate in the quarter the result of an increased improved results associated with the Jubilee field in the fourth quarter of 2015.

The effective tax rate for the quarter was a 3% benefit.

The effective rate was impacted by lower oil prices, losses primarily related to exploration expenses incurred in jurisdictions in which we are not subject to taxes as well as losses in jurisdictions in which we have valuation allowances against our deferred tax assets and therefore do not realize any tax benefits.

At this time, I'd like to transition my comments to expectations for 2016. Second quarter production is forecast to be below expectations due to expected increase downtime associated with the implementation of revised operating procedures for offloading and export from the Jubilee FPSO.

As a result, we currently anticipate having one lifting from Jubilee in the second quarter.

Consistent with the Jubilee field operator, we expect to provide an update on our full year 2016 production guidance once the revised operating procedures for Jubilee have been fully implemented and the long-term solution for the turret issue has been selection.

However, Kosmos does not expect this issue to have a significant long-term financial impact due to continued production from the field and appropriate insurance coverages in place.

If there is have prolonged impact of Jubilee production we will expect any loss of production income insurance proceeds to be reflected in the other income item on our income statement, when it is received.

On the cost side, at Jubilee, we expect operating expense will increase temporarily by $3 million to $4 million per month net to Kosmos due to the revised operating procedures. We ultimately expect our insurance coverage to reimburse these costs but the exact timing of reimbursement is not currently no.

However, when the related insurance proceeds are received, they will be reflected as a reduction to our operating expense. While first quarter G&A was significantly lower than our normal run rate, we still expect G&A cost for the year to be modestly lower than full year 2015.

Therefore, going forward, we anticipate the quarterly G&A run rate in terms of combined cash G&A and equity based compensation expense to be more in line with the fourth quarter of 2015. And with that, that concludes my remarks. And operator, we'd like to open the call for questions..

Thank you. At this time, we'll be conducting a question-and-answer session. [Operator Instructions]. Our first question comes from Ed Westlake with Credit Suisse. Please proceed with your question..

Yes, good morning. I guess, quick question just on the phase in, I guess Mauritania as you look aboard Marsouin. I mean what gives you perhaps confidence but as you go further out may be oil potential.

Hi, good morning. I would pass over to Brian..

Hey, good morning. I think there is a couple of things to know. I think one is, as I mentioned in the prepared notes, the Albian major in source kitchen was being tested by the Teranga-1 well deliberately not just to test the prospect, trying the prospect, but to gain information on those source systems.

And while we were drilling the wells, it was clear to us that those source systems are both present inboard, in the southern part - in the northern part of Senegal, at least we also predict in the northern part of Mauritania too.

And those have liquid potential, and indeed we have - we covered liquids in the well from the Albian source rock below the [indiscernible]. So, we know that these source rocks are actually working inboard.

And then from the temperature information that we've got, we are predicting that this deeper Apto-Barremian source is potentially all mature in the outboard sector. So it's a - the inherent charge model in our minds remains intact.

What we've always known is, given that we're dealing with multiple oil and gas source rocks, the migration pathways are going to be key here. And we've always understood that it's going to be in the shallower reservoir target, it's going to be, how do this deeper gas charge inboard compete with the shallower oil source rocks where they all mature.

And then the Teranga trend or at least the Teranga prospect, it looks like the Apto-Barremian won in this case.

We don’t fully understand why at this point, but what we do know is that we have a lot of trapping geometries, a lot of trapping situations in different reservoir systems, but in the inboard and outboard, which gives us the diversity of play and prospect time to fully test the oil charge model in this basin..

The separate question [indiscernible] related to Suriname, just surprised given the industry excitements that you were looking to farm down, I know there is always a view of risk mitigation ahead of any well, but it would seem that Block 42 would be quite perspective so just to maybe some color as to why you made that decision?.

Brian..

Yeah, Ed a couple of things. One of course HAS [ph] are actually in at least in the discovery..

Yeah..

And so, bringing in a partner who has got both familiarities with the play, where it's proven was obviously advantageous to us. We have a significant position in Suriname.

And from a capital allocation standpoint, it made sense for us to dilute them to, what is still a very material position of about a third alongside Chevron and it has to be set within the context to some of the other opportunities that we got and both within the portfolio and within new ventures as we try to manage our work prevalent budgets, manage our balance sheet and allocate capital across the portfolio on all of the strategic opportunities that we see out there.

So it was - it was portfolio drivers for as well as specific Block drivers..

But maybe to say in other word, it wasn't lack of confidence in the Block, it was the value that has to bring to the potential - choosing the first target on the [indiscernible]..

No, the reason we were able to farm it out in the first place is because actually the Block from an interpretation standpoint, the Block is looking them more attractive than it's ever looked, which is always of an easier in hindsight when you have a discovery next door. It was that prospectivity that has so..

Okay, great. Thanks very much..

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

Hi. Taking another tactic, I guess with the new discovery with Brian.

I've got a question for you regarding geothermal graded, do you think inboard you're just going to be too hot, so you'll tend to be more guess prone and outboard and you had a greater potential for oil and then you mentioned that your seismic AVO work does not differentiate, do you ever think you'll get to the point where you could see oil versus gas..

Thanks, John. Great questions, I mean two things. We're obviously gaining a lot of regional thermal graded information as we drilled these wells and now we drill more [indiscernible] in Teranga 200 kilometers, 130 miles apart.

And the hotter temperature grades inboard being slightly hotter is a good thing and a bad thing, right? It's a good thing and that it makes the shallower source kitchens switched on over a wider area, which is kind of what we want. On the other hand, it varies the deeper source rock even deeper.

But extrapolating away from the data points that we have which really quite consistent and point to relatively simple thermal model for the basin.

It's fair to extrapolate outboard that we can expect to see given the debt for burial of the deeper source rock that it will move into an oil mature window in the outboard area and we are reasonably confident that will happen and of course we got a DSDP well which is further outboard of the well which outboard of our blocks, which gives us some [indiscernible] thermal grade across that the outboard area.

In terms of your question about prediction of phase from AVO and related geophysical tools and of course it's the holy grail of exploration and as we get more and more calibrated I think there is a reasonable chance that we will be able ultimately differentiate.

Obviously, there is a number of drivers of the AVO and not just the AVO signature, not just phase and it's dealing with reservoirs quality and methodology in particular as that influences the different kind of AVO responses and trying to pull out the oil versus gas response and we haven't drilled enough wells at different depths different reservoirs qualities yet to be able to isolate geophysical responses to predict better oil and gas.

But ultimately I think we will get there, we just haven't drilled enough wells yet and it's one of the points that we made in the notes, where only four exploration wells into a giant petroleum system. It's still very, very early days and - but ultimately, I think it will have a better chance of doing that..

Agreed. Thanks. My next question is for Andy. You found a lot of gas, the street is very bearish on LNG and all that.

How are you finding a conversation with companies that are willing to discuss LNG development?.

I think John you have to differentiate sort of today from tomorrow. And I think the conversations we're having with the bigger companies. And I think they see this as differentiated resource given as I said in my remarks. It's the quality of the reservoir it's the productivity of the wells.

So it's not Deepwater gas, we needed to think about it being gas plus 130 kilometers from the shore. And therefore it can be below up with that Deepwater infrastructure. All of those I think things make it what we believe as a competitive source of gas. And of course it got legs, so it's a considerable resource here.

So I think there is a conversation really as about how you get started, I think we'll get started with the smaller scale development. We're looking at steams that are probably module at 2 million tonnes per annum.

And I think as you look at the market beyond 2020, we certainly believe there is the potential for that gas to seeking a good buyer as considerable churn in the contracts in Europe which are replace closely to Europe. And so it can't compete, but ultimately it is about the price point.

If you can price it a point where it's competitive versus the US Gulf Coast, then it is an important resource of gas. And that's where we believe we are today, we done enough work to do that. So going back to your question, what are the big companies looking at it, they see there is a large source of gas.

They see that there is a source of gas that has a considerable life. And they see it is being competitive. I think the entry strategy to the market will be small and then multiple trends to follow..

Great. Thank you..

Our next question comes from Manish Kapadia with Tudor Pickering Holt. Please proceed with your question..

Hi. First question on the Teranga well. Just one another follow up on that. Can you say something in a bit more detail on the reservoir quality on Teranga. And what the implications in terms of at the area of the basin. And potentially going further outboard if there is the risk that at the reservoir quality for the periods..

Can you get it Brian?.

Yeah. I mean - if you will. The reservoir here was a fairly little bit deeper, few 100 meters deeper than below the mud lines than Tortue. So as expected, across this was slightly below Tortue, but still in the 15% to 20% range with good permeabilities.

So we still believe that these are commercial scale, highly productive reservoirs within the low Cenomanian. We never did have an Albian target here [indiscernible] show to you. As you go outboard, the overburden i.e. the thickness of Cenomanian between the seabed and at the top of the reservoir actually decreases.

So reservoir quality what we don't expect to be a problem. And I'd be very surprised if with the fact that we see one of the reasons that we believe that one of the other reasons we believe is because the we know that from the drilling that we done today being calibrated in the AVO.

The AVO only works where we got good quality reservoir and that is high carbon barring. It doesn't work where we don't have good quality reservoir or no reservoir.

So in fact that we can see AVO supporting prospects in the outboard gives us confidence based on calibration that we not only have hydrocarbons outboard but we have decent quality reservoir as well.

Does that answer your question?.

Yeah, thank you. Yes, that does. And then the question on the Guyana's region. Just wondering how come you haven't taken any acreage to-date in Guyana, does it seems like there is plenty of opportunities to get into blocks in Guyana in the fiscal terms also paid back to them in Suriname.

Just wondering why, the opportunities say for has been passed up and also in your own other acreage in Suriname. Just what you see with regards to Liza or you've heard on Liza, where you're seeing on the other block and how that kind of ties into your desire to drill at the [indiscernible] prospect.

Is it that are you seeing kind of better stuff elsewhere to be prioritize the drilling of that prospect. Thank you..

Yeah good questions. Look, I mean Suriname has been a focus area for us for several years well before the Liza discovery obviously. It was a play that we’d recognized of course, because we saw the same stratigraphic potential in Block 42.

We’ve done a tremendous amount of petroleum system analysis and regional work throughout Guyana and Suriname and as it’s always the case in these basin that the real sweet spots are focused in certain areas.

We believe the Exon and their partners in Guyana are focused on the right trend and we believe that at 42 and 45 blocks are focused on similar sweet spot trends. And therefore, once we’ve looked at a lot of other things we’ve not seen anything that we believe and to the play diversity or the prospectivity of the acreage we’ve got.

In Suriname block, what we like about our position is the 42 offers an extension of the proven Liza fairway and we have partial 3D over that block, which has defined substantial AVO supported potential in some similar features.

And then in 45, as he correctly mentioned, we’ve got the [indiscernible] play, which is different structural play, but nearly cretaceous play, it is also AVO supported and so we've got at least two play types to test in those two blocks, one of which have got proven to the North.

So, we're actually very excited about our Suriname acreage, will there be opportunity to expand the position down the road? Probably.

But as you know we're highly selective in our new venture process and we just haven't seen anything that competes with either of the blocks that we already have in in Surinam or other parts of our portfolio to want to go and pick them up..

Thanks so much, Brian..

Okay..

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

Versus potential looks like?.

Go on, Brian..

Well, I mean the first step as I mentioned just to Manish at the moment ago, we have 3D seismic over Block 45 and we have partial 3D seismic over Block 42 so the first task is to go in and acquire a new 3D over the rest of the Block 42, which above the Guyana border and the Exon acreage. And that’s what has it coming into fund.

And that will shoot in August timeframe. So from there it’s typically a 12 to 18 months’ timeline to prepare for drilling.

So late ‘17, ‘18 drilling is what we’d anticipate for Suriname, might be very surprising if it doesn’t get to the drilling stage, the prospectivity that’s already defined on the 3D both in 45 and in 42 is substantial and I can’t see us walking away from either of those two blocks without drilling them.

And I think [indiscernible] are similarly excited as similarly about 42 where they’re using their insights can visualize the similar prospectivity along trend from now into Liza discovery so it is billion barrel, if you want the number it’s a billion-barrel scale potential. And that’s how long at least - similar size commensurate with Liza..

And then the next question might be a little early, because it’s still six months to go, but obviously elections in Ghana in November, is there any prospect in your mind of a change in fiscal policy depending how particularly the presidential election turns out?.

Yeah hi, Pavel. I'll take that one. Look, Ghana has a long tradition of a democratic process. I think their elections will proceed on that basis I think it’s impossible to tell what the outcome will be. What I am confident about is that Ghana as a country recognizes that it’s the frontend of its journey to open up its offshore acreage.

It’s working hard to attract new entrance. It had success recently with NI and the NI discovery and that project moving forward.

And they wanted to do more and I think they understand that fiscal stability is a key part of that particularly given the competition for capital now amongst the nations of the world as they put their exploration acreage out to bid.

So, I have had experience, no conversation that would suggest that they are intended to change the fiscal terms and I think almost the reverse several of the countries we are in today are examining their fiscal terms to ensure that they are competitive..

Appreciate your color on that. Thank you..

Great. Thanks..

Our next question comes from Petr Grishchenko with Imperial Capital. Please proceed with your question..

Hi, guys. Thanks for taking my question. I guess on the cash flow side; I was wondering on the CapEx you guys iterated 650 million span for '16. But looking at Tullow Oil the operator obviously they are talking about the cutting CapEx targets.

So how should we think about that?.

I think Petr it depends on where you started. I think we had a good estimate when we started, it wasn't sort of padded.

I think that we continue to spend absolutely in lined with our 650 forecast clear little more in the ratable basis in the first quarter, because we got our full exploration program in the first quarter and a full quarter of 10 capital spend, as we go into the second half we are clearly stacking the rig this quarter.

The second quarter and then with the start of 10 in the third quarter CapEx runs down. But what you'll see is a quarter-on-quarter reduction of capital our capital through the year 650 remains a good estimate..

Got it and I probably missed that, but you talked about the exploration spending guidance for '16?.

The exploration spending guidance....

We gave is the last number we provided is basically $450 million to $250 million of that in Mauritania & Senegal and then 200 on sort of other exploration which include sort of the rig expense..

Perfect. And the last if I may little bit on insurance side. How should we think about potential claims and hear that right you said you have insurance for 365 days working production post 60-day window at $65 per barrel..

Yeah, 62 I think..

Is there any limit on volumes?.

The volume is set by the prior period.

So we take time the volume from the - how many days?.

180 days..

180 days’ prior period..

I guess what I'm trying to say and why wouldn't you just take the whole 365 days to kind of working days and sort of collect the previous year..

Petr, I think what we need to do is look at what the right approach, I think the right approach is absolutely we need to find a permanent solution for the problem, that's what the partnership is aimed to doing and clearly we need to do it in the way which causes least disruption to production both from an oil and the gas perspective and that's what we are trying to do.

We describe to the insurance cover we have which is robust and what we need to do now as a partnership is with the regard to all stakeholders make sure that we are getting a permanent solution which is obviously the intent to fix the problem for the long-term. But ensure we do it with the least disruption to both production and both oil and gas..

Great. Thanks a lot for the color..

Great. Thanks, Petr..

Our next question comes from Al Stanton with RBC capital market. Please proceed with your question..

Good morning. Two questions if I may, a very quick one to start with and then slightly longer one. Just on that question about production.

Do you believe with a shuttle tanker and do you think you can get production back up to 100,000 barrels a day or do you think the shuttling back and forward is a potential bottleneck?.

It's early days we have walked for the 6 days into the startup. All I would say is that things are going well. I think we are ramping up towards that 100,000 barrels a day and I think physically it's absolutely possible. I think the only thing that we don't yet know what the impact will be in, I think that could be some weather impacts.

But I think absolutely it is possible to get up to 100,000 barrels a day..

Cool. Thank you. And then can we just touch on the plan for the gas in Senegal and Mauritania, you seem to have a fast track plan for commercialization, but at much slower more considered plan for the exploration and appraisal campaign.

I was wondering how you marry them up while getting maximum value? How do you get somebody to pay for the exploration upside, if they coming in to develop a gas project?.

Well, there are actually many commercial structures and you know one can just envisage a structure which does exactly what you say. So I think you know, the barrier is not the inability to bring those two things together. I think the importance for us is finding the right partner for the long-term.

There actually has an alignment around an early development of the gas, but actually cost competitive development of that gas, while continuing to exploring the basin which as Brian has described today, we believe has both oil and gas potential. We clearly have a world class gas field in Tortue, which we believe its market is cost competitive today.

And there, we believe there is rate through early development of that. And I think we need to take the right pace to the overall exploration of the basin, which you consider the scale of it, we only have really four wells and actually have only tested three trends and that continues to be considerable potential.

The partner that actually shared that long-term strategy, I think is absolutely to go and those are the conversations that we’re having with the companies.

Right, okay. Thank you..

Great, thanks..

[Operator Instructions]. Our next question comes from Rafael Gutaj [ph] with Bank of America Merrill Lynch. Please proceed with your question..

Hi, there. Yes, thanks for taking my question. So, two questions mainly just around Jubilee Insurance. So the first one just on your business interruption insurance.

So, when should we expect to get the all clear from your insurance company? Is that the four, after you, you hit the 60-day kind of threshold in early June and is the root cause analysis similar there to what you have to go through with Hull and Machinery insurance? And then secondly just given that some of your stay like and government may not have revenue insurance; how could that influence your timing approach to long-term solutions to find the FPSO? Thanks very much..

Hi, Rafael. What I’d say is the last question first and then Tom will just talk to you around the time sequencing. Like you know, as I said to Petr, I think this is an engineering problem. There is an engineering solutions. What we need to do is find the right solution that insures we have a permanent fix of the problem.

That’s where we’re focused on today. I think there could be a variety of option that could actually do that. So, thereafter what we have to do there is that back and find out what’s the best solution for all the stakeholders and clearly minimizing the impact on oil and gas production is part of that.

So I think, their first job is technical, we need to come up with the right technical solution that fixes the problem and that’s what we’re aimed at today. And then I think, there clearly will be conversations around the best route forward and it's too early to predict the way in which that will go.

But, all that said, we have very robust insurance policies in place which cover all the eventuality. So, Tom in terms of the first question on the timing..

In terms of the timing, we have 60-day waiting period. Once that 60-day waiting period is over, it’s a matter of the fact that we had an actual fiscal event. Then we have had a fiscal event and then it’s a matter of calculating the actual loss to production based on where the production is at the time that we come out of the waiting period.

So, it’s pretty prescriptive formula. It's pretty straight forward. Thar doesn’t need to be any other determination of root cause analysis on the LOPI insurance..

Okay, got it. So it sounds just like, it’s quite formulaic and there isn’t really much risk of kind of dispute was insured on continuity, business continuity insurance..

Correct..

All right. Yes. Okay, thanks..

All right. Thanks, Rafael..

Since there are no further questions at this time, I'd 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..