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 – Investor Relations
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 – Executive Vice President and Chief Financial Officer
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 – Chief Executive Officer
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 – Senior Vice President, Exploration
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 – Chief Executive Officer
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 – Executive Vice President and Chief Financial Officer
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 – Chief Executive Officer
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 – Chief Executive Officer
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 – Chief Operating Officer
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 – Executive Vice President and Chief Financial Officer
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 – Executive Vice President and Chief Financial Officer
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 – Executive Vice President and Chief Financial Officer
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 – Chief Operating Officer
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 – Chief Executive Officer
Yeah. Normally details of private transactions remain private in respect.
John Herrlin – Societe Generale
It’s worth a shot.
Brian F. Maxted – Chief Executive Officer
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 – Chief Executive Officer
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 – Executive Vice President and Chief Financial Officer
Darrell, do you want to take that question.
Darrell McKenna – Chief Operating Officer
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 – Executive Vice President and Chief Financial Officer
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 – Senior Vice President, Exploration
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 – Chief Executive Officer
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 – Chief Executive Officer
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 – Chief Executive Officer
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 – Chief Executive Officer
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 – Chief Executive Officer
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 – Chief Executive Officer
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 – Chief Executive Officer
Yeah Darrell, do you want to take that one.
Darrell McKenna – Chief Operating Officer
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 – Investor Relations
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.
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
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