Kosmos' CEO Discusses Q2 2012 Results - Earnings Call Transcript

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 |  About: Kosmos Energy (KOS)
by: SA Transcripts

Kosmos Energy Ltd. (NYSE:KOS)

Q2 2012 Earnings Call

August 6, 2012 11:00 am ET

Executives

Brad Whitmarsh – Investor Relations

W. Greg Dunlevy – Executive Vice President and Chief Financial Officer

Brian F. Maxted – Chief Executive Officer

Paul Dailly – Senior Vice President, Exploration

Darrell McKenna – Chief Operating Officer

Analysts

Ryan Todd – Deutsche Bank

Al Stanton – RBC

John Herrlin – Societe Generale

Ed Westlake – Credit Suisse

Doug Leggate – Bank of America/Merrill Lynch

Shola Labinjo – Tudor Pickering

John Herrlin – Societe Generale

Operator

Good day everyone. Welcome to Kosmos Energy's Second Quarter 2012 Conference Call. Just a reminder, today's call is being recorded.

At this time, let me turn the call over to Brad Whitmarsh, Vice President of Investor Relations at Kosmos Energy.

Brad Whitmarsh

Thanks operator and thanks to all of you for joining us today. This morning, we issued our second quarter earnings release, including an update on Jubilee and our 2012 capital program. The release is currently available on our website, which is also where you can find our 10-Q expected to be filed with the SEC later today. Joining me on the call with our prepared comments are Brian Maxted, CEO; Greg Dunlevy, Executive VP and CFO; and Paul Dailly, Senior VP of Exploration.

Darrell McKenna our Chief Operating Officer is out of the office today, but he will be joining us for the question-and-answer session, which will follow our prepared remarks. During the Q&A session, I would ask that you keep your questions to one primary and one follow-up so that we can get to all who are on the call today.

Before we get started, I'd like to mention that this conference call includes certain forward-looking statements, based on our current expectations. The risks associated with forward-looking statements have been outlined in the earnings release and in our SEC filings. We may also refer to certain non-GAAP financial measures in our discussion.

Management believes such measures are important in looking at the Company's historical and future performance and these are commonly referred to metrics in the industry. These measures are provided in addition to and should be read in conjunction with the information contained in our financial statements, prepared in accordance with GAAP included in our SEC filings.

At this time, I like to turn the call over to Greg for a review of our quarterly results.

W. Greg Dunlevy

Thanks Brad and good morning everyone. I will first provide a brief review of our financial results for the second quarter before reviewing our updated guidance items. I will then hand the call over to Brian and Paul to review our production, development, and exploration programs.

Overall our results for the second quarter were generally consistent with prior expectations. We had one Jubilee sales lifting during the quarter net to us of approximately 1 million barrels of crude. This generated total revenues of nearly $113 million for Kosmos, with the lifting price at premium of $0.77 per barrel above the Brent settlement price.

With regard to our net production versus sales during the second quarter this year, we under lifted by approximately 240,000 barrels and our cumulative under lift position was around 500,000 barrels at quarter end.

Our third sales lifting for the year occurred in later July for nearly 1 million barrels and it will price slightly above August monthly Brent settlement average. On the cost side, our product expense for the second quarter 2012 included 10 million associated with the enhancement program for Phase 1 wells at Jubilee.

Excluding these work over cost, the average production cost was a little over $9 per barrel. Exploration expense was $17 million for the period, being primarily composed of some seismic, G&G studies and the second quarter costs associated with the Teak-4A well.

General and administrative costs were slightly lighter than expected at $35 million for the quarter with 50% non-cash long-term equity compensation expense consistent with prior periods. Tax expense was $22.5 million for the quarter with about two-thirds of this attributable to our Ghana operations. We also incurred additional book tax expense as a result of a change in our deferred tax asset position related to the vesting of stock awards under our long-term equity compensation program.

Combined we reported a $0.07 loss per basic and diluted common share for the second quarter of this year. Cash and cash equivalents remain robust at approximately $630 million on June 30, 2012 and debt was unchanged from prior levels. Our overall financial position, combined with growing near-term cash flows from Jubilee have us well positioned to continue executing our meaningful development in exploration programs.

Capital expenditure for the second quarter were approximately $120 million, bringing the total for the first half to $250 million. In this morning's earnings, we updated our capital spending outlook for the year, which is now estimated to be $500 million. This is a $100 million increase from our original guidance, reflecting lower spending in Ghana and higher spending in accelerating our exploration of base in opening petroleum systems in new areas.

At Jubilee, the success of our acid stimulation program has replaced the need for drilling sidetracks. In addition, we have reduced the extent of our appraisal activities for the discoveries in the West Cape Three Points blocks, as we continue to assess the most optimal development options for the discovered resources there. As part of our continuing portfolio expansion, we've slightly increased our overall exploration capital spend with funds allocated this year to the seismic programs in Morocco, Surinam and Mauritania, as well as to our new business opportunities.

Full year 2012 production at Jubilee is estimated to average between 70,000, 80,000 barrels of oil per day gross, including the three Kosmos listings that have occurred to-date, we anticipate a total of six liftings for the year with our next lifting scheduled at the beginning of the fourth quarter. I want to provide a couple of updates to our outlook on cost for the remainder of the year.

Production expense including workovers in the third quarter is expected to be up from the second quarter amount, largely driven by greater asset stimulation costs and detailed diagnostic work that has been ongoing as part of the enhancement program. For exploration expense, we are anticipating about $70 million of non-well associated costs in the second half of the year, which includes a large 3D programs in Surinam expected to start this month and a 2D shoot in Mauritania plant in the fourth quarter.

G&A should be relatively consistent with what it has averaged for the first half of the year. Included in our 10-Q filing is an update on our hedge position, which reflects additional crude oil hedges covering a portion of our production in the second half of this year and in 2013.

We've taken the opportunity to lock in some downside protection in advance of upcoming capital commitments over the TEN development and I expect we will continue to look to further enhance this position as the opportunity avails itself.

Now, let me the turn the call over to Brian.

Brian F. Maxted

Thanks, Greg. I like to start off with some comments on our exploration strategy and portfolio and then focus on our Ghana assets before handing over to Paul for an exploration update. Strategically, Kosmos is focused on progressively growing shareholder value by making world-class oil discoveries of unlocking new super major scale petroleum systems. With this in mind we've been actively expanding our portfolio of exploration opportunities to deliver an annual multi-valve drilling campaign going forward, beginning later this year.

Over the past 12 months, we’ve dramatically changed the growth opportunity for Kosmos, more than tripling our gross acreage held through focus on a number of potential petroleum systems in Northern West Africa, as well as along the northeast equatorial margin of South America.

A couple of highlights during the second quarter include the capture of a significant acreage position offshore Mauritania, and our execution of an agreement with Chevron to bring them into our offshore Suriname position. And we continue to see additional opportunities that will provide significant growth potential for Kosmos in the future.

We’re also highly focused on enhancing the value of our legacy Ghana asset, by growing existing production, bringing on additional projects to deliver new revenue streams and by exploring for new hydrocarbon discoveries in the resource rich Tano Basin. Much progress has been made in each of these parts of our business. Starting with our existing production at Jubilee, this world-class field continues its excellent performance. The reservoirs are responding extremely to water flood and gas injection with strong pressure support demonstrating good reservoir and fluid continuity, connectivity and communication.

Approximately 40 million barrels of oil have now been produced. Importantly, we’ve made substantial progress in resolving the well productivity issues that have impacted on our original Phase 1 wells. We have now performed 5 acid stimulation treatments and the results of the program have been very encouraging, with each of it treated wells demonstrating impressive and progressive improvement.

Indeed, we’re successfully recovering well productivity to near original levels and in some cases beyond. Compared to pretreatment levels, the increase in productivity index a measure of production at similar drawdown differential has been quite dramatic. Our productivity index increases in the first four treatments ranging from five to over 40 times pre-treatment levels, which demonstrates the significant impact we've made with the program.

In addition productivity levels in the treated wells have remained relatively stable with the earliest of these now having the own stream for over four months. Our technical teams have done a magnificent job of isolating the productive issues and identifying the optimal solvents and chemicals to resolve for our restriction. Very extensive diagnostic work is being performed, including detailed production logging, as well as flow testing of isolated infills before and after each stage of application and we have recovered samples from wellbore and thoroughly analyzed in the lab.

All of this work has been part of the learning effort we have undertaken to optimize the flow field developments of both Jubilee and of our other discoveries in Ghana. Although there might be other contributing factors, we believe the productivity loss to be associated primarily with a build-up of calcium deposit scales in the very near wellbore area. Small volumes of mutual solvents and acid have proven highly successful in dissolving the scale and restoring productivity, which further confirms this restriction is localized and easily treatable.

We estimate that applied treatment volumes need only contactor radius of few feet beyond the wellbore to resolve the issue, confirming our early beliefs that the well productivity declines are not reservoir related. Production today is at its highest level in 2012 at 83,000 barrels of oil per day with one well still ramping up following a recent stimulus treatment. This equates to a 35% increase from the second quarter of 2012 average.

In addition while in the midst of a Phase 1 enhancement program we've also been advancing the Phase 1A developments. We have drilled half of the Phase 1A wells to total that including three new production wells and one water injection well. Two of the three production wells were drilled as high-angle wells with the third being drilled as a horizontal producer.

Drilling of these wells was designed to maximize exposure of the reservoir and increase the productive interval. Results have been excellent, with each well displaying very high productive capacity. In addition, we've seen good and in some cases best than expected pressure communication of these wells with our existing Phase 1 wells.

In applying our Phase 1 development, learnings to future phases of development, we are implementing modified completion designs on the Phase 1A producers, including perforated stand-alone screens and open-hole gravel pack completions. Following some plant BOP maintenance work that is ongoing, we'll soon begin completion operations on the Phase 1A wells.

In total there will be five new producer wells from Phase 1A with two anticipated to be on line by the end of 2012, and the remaining three to come on line in 2013. With the success of the Phase 1 production enhancement where we have treated five of the nine produces, along with the new production from Phase 1A, we anticipate exiting 2012 in highest production points in the field's history, ramping further to facility capacity in early 2013.

The next major project for Kosmos is the TEN development from the Deepwater Tano Block, which is progressing towards POD submission before the end of the year. During the second quarter, we finalized the flow test of the oil leg Ntomme-2 with over 20,000 barrels of oil per day from multiple zones.

Along the successful appraisal and testing program we are in the final stages of the design process for TEN, focusing on optimizing the scope and facing of the development, associated production profile, and the capital investment requirements.

The oil discoveries at Enyenra and Ntomme underpin the developments, and the FPSO is being sized to handle additional follow-on successes as phase tie-ins at a later date such as the recent discovery at Wawa or other potential funds that may come from the remaining exploration program, which includes two meaningful near term prospects to be drilled by the end of the year.

The TEN project is expected to provide the next outlet for the Kosmos in terms of production and cash flow beyond that ramp up to plateau at Jubilee. On the West Cape Three Points block, we have a drill stem test underway at the Akasa well. This will give us incremental information to better refine the resources discovered and the potential productivity of this reservoir.

As we have continued to refine the resources and assess the development potential of our discoveries at Teak, Mahogany and Akasa, the optimal development is rightly to be tie-back to the Jubilee FPSO. We're executing in all areas of our business, growing production and cash flow at Jubilee, progressing the developments of other fields, continuing to identify new discoveries through a meaningful exploration program.

I will now turn this over to Paul for a more thorough review of our exploration portfolio.

Paul Dailly

Thanks, Brian. As we've mentioned, in Ghana, our exploration efforts are focused on drilling out the remaining resource potential in the Deepwater Tano Block, between now and the end of the exploration period early next year. We got off to a good start in our 2012 campaign with a new field discovery at Wawa where we encountered 33 meters of oil and gas condensate play.

Located in the Northern, previously undrilled portion of the block, this well encountered good quality oil between 38 and 44 degree API and API and Turonian-age channel updip of the Enyenra field. We are currently integrating the well information into our mapping to determine an optimal appraisable strategy, defined all those potential future tie-in to the TEN development and has opened up a new trapping stairway.

In the next month or so, we will spud our second exploration well for the year to test the Okure prospect, this was formerly named Tweneboa Deep. This Turonian-age file is located beneath the Enyenra field and is to some extent de-risked as we prepare encounter in the exploration field of Enyenra 2 well is interpreted to have been on the flank of this Okurean reservoir fairway.

Our upcoming well is designed to test these thicker portion of the fairway. This is a very exciting, and sizeable prospect which we interpret to help multi-100 million barrel equivalent potential.

We expect results early in the fourth quarter and this will be followed by our sub-exploration prospect, the Sapele prospect, which is seismic attribute supported likely 75 million barrels feature located down-dip of the Mahogany and Jubilee fields and located in similar age sands. Results are anticipated for this well towards the later part of the year.

With these attractive opportunities on the horizon, set against the backdrop of previous success we are well positioned to enhance the resource space for potential future development in Ghana. Elsewhere, we continue our efforts to open up new petroleum systems and replicate our success, including identifying and capturing new exploration ventures and maturing existing blocks to the drilling stage.

Our petroleum systems analysis based strategy involves number of tactics to access strategic opportunities. These include expanding our core theme, the implication of structural stratigraphic plate of West Africa, for example in offshore Mauritania, as well as new themes such as the North West Africa pre-salt play offshore Morocco and new geographies like Suriname along the transfer margin of Latin America.

The intent of our exploration initiatives is to provide the Company exposure to multiple potentially petroleum system opening wells each year going forward. In this regard Cameroon is most advanced. Preparations are ongoing for our first operated well there the Sipo-1 well, which is expected to spud late this year.

This well will take the most likely size of 150 million barrel prospect in a tertiary aged compressional thrust structure in our onshore Indian River block. This is located along terrain from offshore producing fields. We recently contracted (Helios Lake) for this well and the results are slated to be in the early part 2015.

Elsewhere in our existing portfolio we're targeting first drilling in our offshore Morocco acreage likely in the latter part of 2013. Here we're continuing to process and interpret our recent 3D program and preliminary interpretation in showing encouraging prospectivity. Offshore Surinam, subject to final closing conditions Chevron will join us in our deepwater Blocks 42 and 45 where we originally contracted a 3D seismic vessel to acquire approx 3,800 square kilometers of data with the acquisition expected to start this month and last through the remainder of the year. Chevron brings a lot of value to our opportunity in offshore Surinam and we look forward to working with them to progress towards initial drilling potentially in 2013.

Offshore Mauritania Blocks C8, C12, and C13 have now been formally gazetted by the government and we are quickly moving forward to secure sizing vessels to acquire data later this year. These blocks represent a huge add to our portfolio in a proven hydrocarbon province down dip from existing production. Alongside efforts to mature our current exploration assets to the drilling stage, our new business initiatives are continuing in order to build the balance concentrated portfolio with the right risk reward potential to deliver new Ghana size success.

The sale and expecting time for Kosmos, as we are making great progress in Jubilee, preparing for our second offshore development and have meaningful exploration drilling before the end of the year, while continuing to build substantial future opportunities in a number of new hydrocarbon basis.

Operator, we like to open the call for questions at this time.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) Our first question comes from Ryan Todd, with Deutsche Bank. Please proceed with your question.

Ryan Todd – Deutsche Bank

Thanks gentlemen. A couple of questions on Jubilee, you referenced how the asset stimulated wells have been coming on very successfully. Can you talk about generally what rates you are seeing on average in the wells coming back and from the earlier asset stimulate wells, which I think you said you've got about four months of production? Are you starting to see any signs of buildup of the finds again or what are you seeing from that point of view?

Brian F. Maxted

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

W. Greg Dunlevy

Yeah. I'll jump in too, Brian. My phone went dead for a minute there, but yeah absolutely there has been no decline seen on the five that are being stimulated so far.

Ryan Todd – Deutsche Bank

That’s great. Thanks and on the – you said that you'd have three of the Phase 1A wells on by year-end and the other two producers would come on in the first half of 2013, is that right?

Brian F. Maxted

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

Ryan Todd – Deutsche Bank

Okay. And so, from a production plateau point of view you think, is first half of 2013 a reasonable expectation in terms of hitting 120.

Brian F. Maxted

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

Operator

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

Al Stanton – RBC

Yes, good morning folks. It’s just a question about Teak and Mahogany area, you talked about it the high-back to Jubilee that kind of left me feeling that the field is smaller or the complex is fairly smaller and they will be developed perhaps later than we previously anticipated. I’d appreciate your best guess on resources and startup dates for those two fields?

Brian F. Maxted – CEO

Yes, it’s Brian again here. Let me say a few things and then I can pass on to Darrell and he can add on. Obviously these discoveries are still very much at the appraisal delineation stage. We've drilled several appraisal wells recently, we're currently testing the Akasa well, all of which is designed to try and understand what the likely resource base is. Given it's just not about barrels, it's actually about value and what's the right value decision to take in terms of a potential development plan for these barrels. And so we're very much looking at maximizing returns on the development, which is part of the equation of I bet being a likely tie back to Jubilee. And if it is tied back to Jubilee than the resource base will be integrated alongside the Jubilee resources and we will optimally develop the entire resource base within that context. So, it's not necessarily safe to assume that production in a tie back case will be way out into the future because it might well not be, because I think part of the appraisal program for some of these discoveries will actually be long-term tests not just simple DSTs. Darrell do you want to add-on to that?

Darrell McKenna

Yeah, the only thing I would say is we're still in the thrills of the appraisal program we're testing the Akasa-1, so it would be too early to put any volumes and resource base to it.

Al Stanton – RBC

So should I now assume that Jubilee, Mahogany and Teak are all produced over a platform with plus or minus capacity of 120,000 barrels a day?

W. Greg Dunlevy

I think again it's too early to say at this point and until we both within the company we finished our appraisal program and integrated the results, and as the partnership and alongside GMPC and the ministry until we've done all of that and figure out what the right way forward is that, I don't think we'd be comfortable in making any statements on that.

Al Stanton – RBC

Can I just close with one final question then Tullo recently said that TEN was 360 million barrels of oil equivalent. Are you a buyer or seller at that level?

W. Greg Dunlevy

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

Al Stanton – RBC

Thanks guys.

Operator

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

John Herrlin – Societe Generale

Yeah, hi, two quick ones for me. With Morocco you said you were shooting seismic, what license?

W. Greg Dunlevy

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

John Herrlin – Societe Generale

So, you're going to stick to those first and then get to the other ones later, like the cap one?

Darrell McKenna

Yeah. The other block that we have there is Tarhazoute in that salt basin, that’s another large license, and we haven't established any plans on acquiring seismic over there yet, we’re currently reinterpreting the existing dataset that exits over that area.

John Herrlin – Societe Generale

Okay, great. With Suriname, will you be heads-up with or will Chevron be heads-up with you on an expansion rate basis going forward once they close or will you be recouping anything that you are spending on the seismic currently?

Brian F. Maxted

Yeah. Normally details of private transactions remain private in respect.

John Herrlin – Societe Generale

It’s worth a shot.

Brian F. Maxted

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

Operator

(Operator Instructions) Our next question comes from Ed Westlake, with Credit Suisse. Please proceed with your question.

Ed Westlake – Credit Suisse

Good morning everyone.

Brian F. Maxted

Good morning Ed.

Ed Westlake – Credit Suisse

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

W. Greg Dunlevy

Darrell, do you want to take that question.

Darrell McKenna

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

Ed Westlake – Credit Suisse

Approximately.

W. Greg Dunlevy

Ed, from a short term guides perspective we’re seeing production expenses of around $9 a barrel, excluding workovers, as you saw in the second quarter. Second quarter workover costs were about $10 million to production expense, we see that workover cost in the third quarter going up significantly just based upon timing of realization of those costs and then dropping significantly in the fourth quarter. Again, based upon the timing of the workovers and the liftings.

Ed Westlake – Credit Suisse

Yes. So, we should think about it in absolute terms and then divide it by the barrels you're producing and run it that way?

Paul Dailly

I think you should look at the run rate by barrel and then you should look at the workovers more as a one-off by quarter, and that was about $10 million in the second quarter. It will be significantly higher in the third quarter and then it should drop in the fourth quarter.

Ed Westlake – Credit Suisse

And then have we got any estimation yet on the CapEx for the TEN project, a range?

Brian F. Maxted

No, we're still relatively early in the stages of planning that development and at this point, I think it wouldn't be appropriate to quote that Ed.

Ed Westlake – Credit Suisse

But presumably on the per barrel basis, obviously, costs have gone up since Jubilee and it's also a slightly more complicated development given its gas condensate is a higher ratio than it was at Jubilee, is that a fair assessment?

Brian F. Maxted

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

Ed Westlake - Credit Suisse

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

Brian F. Maxted

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

Operator

Our next question comes from Doug Leggate with Bank of America. Please proceed with your questions.

Doug Leggate – Bank of America/Merrill Lynch

Thanks good morning everybody. Thanks for taking my questions. Brian, if you could follow-up on the emerging plays, where would you expect your working interest levels to stand? I mean in other words Morocco and Mauritania in particular. Should we expect that you will be taking those interests down a bit as you get closer to the drill point and if so, what would you be comfortable with and I have a follow-up please.

Brian F. Maxted

Yeah. It’s a great question Doug and it’s something that as we look at capital allocation portfolio management. It is something that’s on their mind. One of the challenges that we’ve got is that in executing on our exploration strategy we have taken advantage of first mover situations as we’ve been able to get very acreage positions to capture as much of the petroleum systems, potential petroleum systems if possible and give us play diversity and prospect dependency etcetera. So, but what that brings with it, of course is they are large areas and the seismic stage, the costs of large acquisition program is going to be in a much more significant in units passed. So, one of the challenges we are looking at is how do we therefore think about partners, do we think about partners later in the game and more conventionally after we've defined the prospectively and format of the drilling stage or do we bring partners in earlier. And you’ll probably see a mix of those strategies in. In Surinam, we decided to bring a partner in earlier, although we still got 50% of that block and so that provides us with further options down the road to dilute a little, but if we think that's appropriate. And that will very much depend on how much prospectively we see and how confident we are in that prospectively. But this is a team game exploration. We've got a great deal of confidence in our own capabilities, but we also respect the abilities of potential co-ventures as well, and so you can expect us to anticipate that we will be partnering on most if not all of our projects.

Doug Leggate – Bank of America/Merrill Lynch

Great, thanks. My follow-up is really following up from a question earlier, when we go back and look a year or so ago at the sort of prospect backlog and the way you had viewed some of the Teak and so on and West Cape Three Points, just listening to you today I'm wondering if your sort of relative enthusiasm there has changed or was there something you saw in Teak-4A that has changed your view or can you just elaborate a little bit as to why you might not want to move, we might not see you move a little quicker on the other development or not? I will leave at that. Thanks.

Brian F. Maxted

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

Operator

Our next question comes from Shola Labinjo with Tudor Pickering. Please proceed with your question.

Shola Labinjo – Tudor Pickering

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

Brian F. Maxted

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

Operator

Our next question is a follow-up from John Herrlin with Societe Generale. Please proceed with your question.

John Herrlin – Societe Generale

Yes, thank you. Regarding Jubilee and the scaling, could you give kind of a simplified rationale for why you think the scaling was localized?

Brian F. Maxted

Yeah Darrell, do you want to take that one.

Darrell McKenna

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

John Herrlin – Societe Generale

Great, thank you.

Operator

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

Brad Whitmarsh

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

Operator

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

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