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Executives

Frank Chapman - Chief Executive, Executive Director, Chairman of Exploration & Appraisal Committee, Chairman of Group Executive Committee, Member of Chairmans Committee, Member of Portfolio Development Committee, Member of Sustainability Committee, Member of Finance Committee and Member of Investment Committee

Fabio Barbosa - Chief Financial Officer, Executive Director, Member of Group Executive Committee, Member of Chairmans Committee and Member of Finance Committee

Chris Lloyd - Head of Investor Relations

Analysts

Oswald Clint - Sanford C. Bernstein & Co., Inc.

Paul Spedding - HSBC

Hootan Yazhari - BofA Merrill Lynch

Jon Rigby - UBS Investment Bank

Anish Kapadia - Tudor, Pickering, Holt & Co. Securities, Inc.

Jean-Luc Romain - CM-CIC Securities

Irene Himona - Societe Generale Cross Asset Research

Lucy Haskins - Barclays Capital

BG Group plc (OTCQX:BRGYY) Q2 2011 Earnings Call July 26, 2011 7:00 AM ET

Operator

Good afternoon, and welcome to the BG Group Second Quarter 2011 Results Conference Call. [Operator Instructions] And just to remind you, this conference call is being recorded. Today, I'm very pleased to present Sir Frank Chapman, Chief Executive; Fabio Barbosa, Chief Financial Officer; and Chris Lloyd, Head of Investor Relations. Chris, please begin your meeting.

Chris Lloyd

Thank you. [indiscernible] results. During the course of this conference call, our Chief Executive, Sir Frank Chapman; and our Chief Financial Officer, Fabio Barbosa, will take you through the quarter's key business highlights and then Sir Frank and Fabio will take your questions.

During the call, we'll be focusing on our business performance results as highlighted in our results statement. We'll also be making various forward-looking statements. Factors that could cause our actual results to differ materially from the results we currently expect are identified in detail in BG Group's annual report accounts for 2010. Thank you, and now over to Sir Frank.

Frank Chapman

Good afternoon, ladies and gentlemen. You'll have seen our results statement by now, and I'm pleased to report that we have made good progress in delivering our growth plans across the global portfolio. I'll take you through the key developments now before handing over to Fabio to take us through the financials in more detail.

I'll start with Brazil where we recently announced a material reserves and resources upgrade across our pre-salt Santos Basin interest. Mean total reserves and resources are now estimated at some 6 billion barrels oil equivalent net to BG Group, with an upside potential of 8 billion BOE net.

Most notably, 95% of this total is accounted for in the Lula, Guará, Cernambi, Iara and Carioca fields. Importantly, we expect virtually all of this resource to be recovered using the same surface facilities we envisaged in our field development plans prior to the resource upgrade. This means we expect a substantially higher unit value for the incremental resources announced in June, resulting in significant unit cost reductions and higher unit value for the increased total resource base.

The major upgrade doubled our previous best estimate of 3 billion BOE net given in February 2010, and was based upon a wealth of drilling, appraisal, testing and other new data, not least dynamic data gathered from producing almost 16 million barrels of oil from the Extended Well Tests on Guará, Lula Sul, Lula Northeast and from the first permanent FPSO on Lula. This data has shown much higher well deliverability and greater reservoir connectivity, which will allow increased recovery per well.

Accordingly, we now expect an earlier ramp-up to plateau production from fewer wells. The doubling of recovery from 3 billion to 6 billion BOE over the same 27-year license period will be achieved by a combination of: firstly, more rapid buildup to plateau as fewer wells are required to reach FPSO capacity; secondly, higher utilization and the debottlenecking of the aggregate installed FPSO capacity, meaning higher aggregate plateau production; and thirdly, more sustained production performance, meaning wells are expected to flow at higher rates for longer.

In addition to this improved performance, we have also seen significant improvement on unit cost expectations. Our experience with FPSO tendering, construction and operation, coupled with a substantial improvement in drilling performance, gives us greater confidence in achieving further reductions in cost over future phases.

As stated earlier and as a consequence of all this new information and experience, we expect a substantially higher unit value for the incremental resources announced in June, resulting in significant unit cost reductions and higher unit value for the increased total resource base.

And the significant progress being made in Brazil is mirrored elsewhere across the portfolio. In Australia, momentum continues with $1.8 billion invested in the first half of this year, and we now have over 3,500 people deployed across the operations. The progress made includes the completion of site preparation works and costing of first structural concrete at the LNG site. All 540 kilometers of the 42-inch pipe have been delivered, and the first stage projects for water treatment facilities have been completed.

The extensive flooding experienced in Queensland earlier this year has impacted upstream drilling progress. However, we have a recovery plan in place, including, amongst other things, the mobilization of an additional 12 drilling rigs, and plans for first LNG in 2014 are thus unchanged.

In the U.S., development progress continued, and the 200th operated horizontal well in the Haynesville was drilled and brought into production. Elsewhere, we assumed operatorship for Blocks 1, 3 and 4 offshore Tanzania in readiness for the next stage of exploration and appraisal work scheduled for later this year. And in Kenya, we signed Production Sharing Contracts for 2 new exploration blocks where BG Group will also be operator. And now, I'd like to hand you over to Fabio for a more detailed look at the financials.

Fabio Barbosa

Thank you, Frank, and good afternoon, ladies and gentlemen. I will start as usual with the E&P segment. Unless otherwise indicated, all of my comments relate to the second quarter rather than the half year.

Revenues increased 35% in the quarter to $2.8 billion. This reflects the benefits of a 3% increase in production volumes and higher commodity prices. E&P total operating profit of $1.4 billion was 90% higher than last year as a result of the increase in revenues combined with the lower exploration charge. Higher production volumes in the quarter were principally driven by the production buildup in the United States, Brazil and at Hasdrubal in Tunisia. Whilst there continued to be sporadic disruption from social unrest in Egypt and Tunisia, it had a relatively small impact on production in the second quarter.

In the U.K. North Sea, the Everest, Lomond and Erskine fields progressively returned to production following the shutdown in the first quarter, and further progress was made on Buzzard, which we expect to return to full capacity during the third quarter. Also during the third quarter, we'll be carrying out planned maintenance of a number of platforms, including Armada. As part of this shutdown, we intend to complete the tie in of the North West Seymour and Gaupe.

We continue to expect modest production growth for the group in 2011, ahead of the strong ramp-up in volumes from 2012 through to 2020. Our results also reflected the strong market fundamentals. BG's average realized gas price increased by 23% year-on-year to $0.428 per produced therm, showing the effects of higher market prices, together with favorable changes in the production mix.

By the same token, our average realized oil and liquid prices increased by 55% and 48%, respectively. Unit operating expenditure rose to $8.93 per barrel of oil equivalent. The increase compared to last year reflects the impact of higher commodity prices on both tariff and royalty costs, adverse foreign exchange movements and changes in the production mix, including higher-than-portfolio average cost associated with the production start-up activities in Brazil.

As I mentioned, in the first quarter, at an oil price of around $100 per barrel, we would expect operating costs for the full year to be between $8.50 and $9 per barrel of oil equivalent.

Exploration charge of $120 million in the quarter was $246 million lower than last year as a result of lower well write-offs. As before, we expect our gross exploration expenditure for the full year to be around $1.4 billion, excluding acquisitions, with around half of this being expensed.

In our LNG segment. Total operating profit for the second quarter was $553 million, 2% higher than last year. This result was ahead of our expectations due to a change in the phasing of trades for the year. Shipping and marketing operating profit was 3% higher at $494 million, reflecting an increased number of global divergence.

During the quarter, we diverted 84% of our LNG cargoes to global markets outside of the United States compared with 60% in 2010. Our share of operating profit from liquefaction activities in the second quarter of $81 million was in line with last year. For the LNG segment as a whole, we continue to expect 2011 operating profit for the full year to be at the upper end of the $1.9 billion to $2.2 billion range as previously announced.

Turning now to Transmission and Distribution. Revenues were up 18% in the second quarter, reflecting a 3% increase in volumes and favorable foreign exchange movements at Comgás in Brazil combined with higher prices at Gujarat Gas in India. However, total operating profit in the same period fell by 9% to $167 million.

This was a result of the timing effect of gas cost recovery in Comgas where $44 million were passed back to customers in the quarter, compared with a net recovery of gas costs of $28 million in the second quarter of 2010. The closing balance to be passed back to customers at the end of the quarter was $78 million. We now expect substantially all of this to be passed back by the end of 2011. Excluding this timing effect, total operating profit at Comgas increased by 29%, reflecting favorable sales mix, foreign exchange movements and improving demand, predominantly in the industrial segment.

For the group as a whole, operating profit of $2.2 billion was 42% higher than last year. Earnings per share increased by 27% to $0.331 per share, reflecting the increase in operating profit, partly offset by higher finance costs and higher effective tax rate.

Net finance cost for the quarter amounted to $59 million, and for the full year, they are expected to be around $260 million, excluding the impact of foreign exchange movements. In line with my comments in May, the group's underlying effective tax rate for the full year, excluding the $195 million one-off charge recognized in the first quarter, is expected to be around 45%. The increase over last year is primarily a result of a change in the U.K. North Sea taxation announced in March. We expect the group's effective tax rate to be around 43% to 44% in the near term and trend downwards thereafter as more of the group's profits are generated from outside the U.K. North Sea.

Cash generated by operations in the second quarter increased by 11% to $2.6 billion as a result of higher profits and, as anticipated, the partial reversal of prior period margin costs on the group's hedged LNG contracts. Cash outflow associated with the remaining margin cost will be reversed in future periods as the underlying LNG contracts settle.

As you are aware, the group is undertaking an extensive investment program to deliver its growth. Capital investment in the quarter of 2.4 -- $2.5 billion included acquisitions of $113 million related to the purchase of further shale gas acreage in the United States. After adjusting for $1.2 billion of acquisition cost in the same period last year, our organic investment increased by 58%, expense focused on the group's major projects in Australia, Brazil and United States. At reference conditions, our expected full year capital investment remains at around $10 billion.

We ended the quarter with cash of $2.2 billion. Our net debt was $9.5 billion with an average maturity of around 8 years, and the gearing ratio was 24%. During the second quarter, the group signed a corporation agreement with Bank of China that enhances the existing close working relationship between the 2 organizations and also allows for up to $1.5 billion of new funding alternatives. In addition, the group's committed facilities, which remain undrawn, have been increased to $5.5 billion with extended maturities of between 2012 and 2016.

Reflecting the group's financial performance and in line with our established policy, the board has approved an interim dividend of $0.108 per share, which is half of the 2010 full year dividend. As previously announced, the dividend will be paid in Sterling, using the average exchange rate over the past 3 days. This amounts to 6.63 pence per share. That concludes my remarks, and now, Frank and I will be pleased to take your questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Paul Spedding at HSBC.

Paul Spedding - HSBC

With a quick question on what you feel you can do to get an increased output from the existing -- also the -- and presuming the FPSO fleet is on order. You were talking about debottlenecking. I just wondered if you could give us a feel for what you might be able to increase the capacity of the FPSOs by through proved efficiencies and debottlenecking?

Frank Chapman

Yes, debottlenecking, I mean, I couldn't give you a firm number on this. But what I could say is it is not untypical to achieve more than 10% additional throughput, and in cases, as much as 20%. I mean we're looking at -- if we looked across our portfolio today, I think it'd be fair to say we certainly managed to achieve figures in that range from more mature facilities. You don't, of course, get this on day one. This does come after a number of years, and you have to then really identify which of the streams. Is it water? Is it gas? Is it CO2 separation? Is it oil? And where in the process, production process, the bottleneck exists. Making some assumption about additional throughput from debottlenecking would be appropriate given the fact that this is quite normal to achieve debottlenecking.

Operator

The next question comes from the line of Michael Alsford at Citi.

Michael Alsford

I've got 2 questions, please. Firstly, obviously, there's been a lot of disruption in the U.K. business due to unplanned maintenance. Could you maybe give an indication post the upgrade on Buzzard what the overall or total production capacity would be in the U.K. business going forward? And the second question is just around Brazil, clearly, some positive comments around the unit costs for the business going forwards. But could you maybe give a little bit more color as to how you got comfortable around the delivery risk and the execution risk from the local service contractors and what contingencies you may have in place to maybe mitigate those risks?

Frank Chapman

Michael, thank you for your questions. I mean, in terms of disruptions of business, of course, that has been an issue for us in the first quarter, particularly. As we've said in the release, the Everest, Lomond and Erskine fields have progressively returned to production this quarter. We've got some further work to do on Armada, particularly in relation to tie-ins in the third quarter and some more maintenance to do. But we should see all of our facilities back up to producing their maximum capacity as constrained by well deliverability in most cases. In the case of Buzzard, it's facilities capacity as we move into the third quarter, as we move through the third quarter. I'm not going to give you a specific number for the U.K., suffice it to say that overall production, as we've said, for the year, we expect there to be a modest growth in production this year before we start to see a succession of new projects coming on stream. I think that most of you will be aware that we've got quite major work going on apart from these things returning to production in the U.K. Major work going on in West Delta Deep, in Egypt with Phases 7 and 8a, which is going to drive increased production. We've got the U.S.A. ramp-up, which you've seen evidence of in this quarter's results. We're going to see a full year from Lula at an increased production level as new wells come in. We will have Jasmine coming on stream at the end of next year. We've got Bongkot South, which is making good progress, and new production facilities in Bolivia. So there's quite a range of things to set alongside the return to, let me say, more normal operating conditions in the U.K. And this suite of changes and new projects are the ones that are going to be driving the profile. So overall, the picture we gave at the beginning of this year and as we updated at the end of the first quarter, we said transition year for 2011 and then double-digit from '12 onwards, that's still a picture that we're very comfortable with.

Michael Alsford

And the question on the contingencies around Brazil and how you got comfortable with, I guess, execution risks from the local service contractors there?

Frank Chapman

Yes, the -- I mean, basically, if you think about what we've managed to achieve in less than 5 years since the first discovery, there is no doubt that we are managing to get on with things. I mean, we have 11 FPSOs on order. We're about to order 2 more. And we have the first unit in production. We've drilled quite a lot of wells and serviced those operations with Brazilian-based services. And on the whole, I would say I'm really very pleased indeed with the progress we're making. I think Petrobras is delivering quite an accelerated program, with 2.3 million barrels of production capacity already in train, as it were. And the schedule for FPSOs 2 and 3 are absolutely on schedule at the moment, very pleased in the progress they're making. And even the 8-holes program, which is a much earlier stage, is a little behind with engineering, but in terms of the overall manufacturing process, very happy with the preparations being made there. So the confidence grows from actually observing things going on, physical work happening, schedules being adhered to, services being provided, and most of all, Petrobras showing its determination and commitment to absolutely getting the maximum possible out of these discoveries.

Operator

We now go onto the line of Jon Rigby at UBS.

Jon Rigby - UBS Investment Bank

Just also to focus on Brazil, if I can. Can we just dig a little deeper into the comments you make about the FPSOs basically producing out your increased reserve number and the increased efficiency on the wells. So if I understand you, can we assume that the FPSO portion, the service portion of the CapEx you're envisaging across the life of Santos essentially doesn't change for the increased production. And then on the, I guess, the second-largest bit of CapEx slug, we obviously -- I assume you're assuming some increase in well stock because of the increased reserves. But can you also characterize what kind of efficiency you'd expect in terms of the sort of wells per ultimate reserve recovery across the life of the field? What I'm trying to get at is with all these moving parts what the improvement in CapEx per produced barrel ends up being, if possible?

Frank Chapman

Yes, I mean, let's -- well, first off, I think it's a reasonable assumption to say there's no increase in the CapEx. And I think that, that also extends to the well stock. I don't think we will. I mean, essentially, what you got to think about here is 5 fields, which, prior to these increases, were developed through a number of FPSOs positioned aerially over these discoveries. And then what we've had is a number of improvements such as better reservoir properties, especially in the flanks of Lula, lots more. Very much improvements in Iara, for example. We've had better reservoir connectivity, continuity, deeper oil-water contact. In Lula, we're now going to apply water-alternating gas enhanced recovery techniques from Phase 1. So when you put all these things together, what actually happens is that, that aerial coverage of FPSOs that we have in each of the fields simply is able to access with the same number of wells more resource. So you've got sort of 3 phases if, you like. You've got the first phase, which says actually, I need, say for example, 10 wells in this area, but I can actually get to plateau with 4 or 5 wells in the beginning. So it means that you get to your plateau earlier, although ultimately, you'll probably need the same number of wells that you had originally in your plan. When you've got your suite of -- your fleet, I should say, of FPSOs, you can imagine that if you install one in year 1 and then another one in year 7, it's quite conceivable in the old plan that the Unit 1 is off plateau before 7 comes on stream. Now because we've got a lot more, our reserves, to develop, it is a fact that you will have a higher utilization of the aggregate installed capacity such that Unit 1 may have a longer plateau and therefore be delivering higher production when that unit 7 comes on stream. Added to which, of course, we've always said and this applies anyway, debottlenecking capacity will be there. And then once, of course, this is on stream, you will see a higher aggregate plateau production. And you will see an extension of that plateau because the wells will produce more for longer. And in this way, it is our intention and it is also our belief that we will recover all of this additional production, substantially all of it, at least the same proportion that we had envisaged, in the field development plan that was in place prior to the resource upgrade.

Jon Rigby - UBS Investment Bank

I.e., produce the same proportion now before the license finishes?

Frank Chapman

Yes. I mean -- and by the way, the sort of license finishing is, in a way, a sort of artificial endpoint because it would be, I think -- we have, in the agreements, rights to apply for an extension. And the IMP have rights to extend or not extend. But so far down the production curve, it would be quite odd for the IMP to say to us, "By the way, take away all your production kit," which, at the end of the producing life, we are required to take out of the country, "take it all away. We're going to get somebody else to develop the last barrels." That would seem to be a quite inefficient thing to do. And therefore, we have internally, although we've not included these assumptions in our plan at present, we believe, internally, that the probability of us getting an extension beyond the end of the current license period, we believe that probability is quite high. But of course, it's, at this stage, not the thing that's most -- uppermost in our minds. We're really interested in getting the FPSOs -- all of the FPSOs in place. So I think the idea that we would use the same fleet of FPSOs to produce all this extra volume wasn't sufficiently, clearly spelled out by us in the previous release, which led to some analysts believing that these reserves were present in new discoveries requiring a new set of infrastructure for their development. What we're attempting to do here is to make it much clearer that the unit value of these extra resources is actually not far less but rather far higher than the average unit value for the resources that existed prior to the upgrade.

Jon Rigby - UBS Investment Bank

Okay. Understood.

Operator

Our next question comes from the line of Lucy Haskins at Barclays Capital.

Lucy Haskins - Barclays Capital

When would we expect to see some production sort of granularity effectively come through in terms of the new resource numbers in Brazil? Is that something we will be waiting for until the February 2012 strategy update? Or are you hopeful that we'll have some incremental information once you've had the discussions with the consortium partners?

Frank Chapman

Yes, I mean, look, of course we want to put as much information as we are able to put into the market to aid understanding. I mean, considering that the resources have doubled since the beginning of last year, what we are dealing with here is, of course, a very rapid evolution of reservoir understanding. The dynamic data that we are observing now, in particular, has really confirmed what I would describe as our very best expectations. And I think that given the pace of change, it is inevitable that the partners' work is sort of never-ending. No soon we get one field development plan in place that we've got more information to discuss and to agree which reservoir parameters we're going to establish as the base case. Flowing from that, of course, we then need to optimize field development plans and flowing from that, in turn, comes the number of FPSOs and the plateau production rates. The other thing I would say is, of course, we often forget, when we're dealing with all of this, that rather than a single field, where we can have great clarity at an early stage of sanction of the development program, the unit costs, the production profiles and all of that, what we're actually dealing with here is multiple sort of giant or supergiant fields. And of course, it will take a little longer for all of that to settle. I think it is encouraging that all the partners are really focused on recovering all the economic reserves in the license period, just to be sure. I think it is reassuring that already 13 FPSOs with this, as I've mentioned before, 2.3 million barrels a day total capacity have been ordered or about to be ordered. And it is reassuring that there are almost certainly going to be more to follow. And we will enjoy updating the markets when we settle the plans more firmly with our partners. So I would hope certainly to be saying more to the market, at the latest, when we come around to February next year, and if not, sooner. In the meantime, the figures that we're giving you will help you to take your existing assumptions and extrapolate those across a larger resource base, which itself, the incremental volumes, which do not require any incremental CapEx. So I hope that helps you. I do understand your desire to have more specifics. And let me reassure you that when we're able to do that, we will certainly be doing it.

Operator

Our next question comes from the line of Irene Himona of Societe Generale.

Irene Himona - Societe Generale Cross Asset Research

I have 2 questions, please. So first on LNG, in Q2, I can see your diversions are 80% up materially versus last year. Could you talk a little bit about developments you have seen in the global LNG market in the second quarter following the Japanese crisis and Japanese situation? My second question on Brazil, I just wonder whether in the very, very recent Petrobras strategic or new strategic plans you can see any readthrough, you can see any broad recognition or confirmation by the operator of the statistics you are discussing this morning with us?

Frank Chapman

Yes, just on the statistics, on Brazil, I think it is fair to say that there is an increasing convergence amongst the partnership of views. I mean, if you've read the views of other members of the consortium, including Petrobras itself, the picture is generally one of increasing volumes, of lower unit CapEx as these in-large resources are beginning to be recognized. We are, of course, moving all of us at different speeds in this and with a different level of past experience with this type of reservoir. But the trend, of course, is similar in each case. And I believe that we are looking here at pretty high levels of convergence. The information that has been released recently by Petrobras, our analysis of their information shows that we're actually quite strongly aligned when it comes to 2015 production outlook. And when we move out to 2020, we're also quite strongly aligned, even though I expect these figures still further to increase. So I'm quite happy with the fact that all of the partnership is moving in the same direction, albeit that the rate of change, the pace of change, of knowledge and assimilation of that knowledge will vary from partner to partner. But on the whole, everyone sort of -- I think all the partnership members are smiling at the moment that we have here something very special. Fabio, you want to say something about diversion?

Fabio Barbosa

About LNG is basically the fact that we have a much stronger market in the Asia Pacific region and also in South America. And as you can see by our numbers, we managed to deliver in the first half of the year 23 cargoes in South America alone. That compares with 15 cargoes last year in the same period. Asia, of course, posting a very strong performance, and the U.S. really showing a weaker market than last year. So it's basically the result of the market fundamentals and the relative strength of the Asia Pacific market combined with the South American development.

Frank Chapman

Yes, if I could just add to that, Irene. I think that the situation in Japan has not really affected significantly our trading. So it will be something, which is not the cause of this year's overarching LNG performance but it will make -- that has made the environment in which we're working somewhat tighter. So it's an incremental contributor to performance rather than something, which shapes the overall annual performance. What is evident, however, is that the catastrophic situation that has occurred in Japan and the follow-on policies that are being implemented by various governments around the world who are now changing their plans not to use and not to use further nuclear, means that the overall picture is tightening. And it's causing, particularly Asia Pacific customers, to come back to the table somewhat earlier than hitherto planned in order to engage and start to consider their next tranches of long-term supply. So that is completely evident from the interaction that we're having with a broad spectrum of customers, particularly in Asia Pacific.

Operator

Our next question comes from the line of Oswald Clint at Sanford Bernstein.

Oswald Clint - Sanford C. Bernstein & Co., Inc.

Yes, the first question, just back on Brazil. I know you've mentioned the greater connectivity across the Lula structure before and today talking about that again in context of all of the reservoirs. Is this what you're saying that you do expect this grid connectivity across all of your -- the 5 discoveries that you're talking about? I just wanted to clarify that. And then secondly, maybe just over into Kazakhstan, I remember Ashley, I guess, was leading the negotiations with the government on Phase 3 in terms of recent discussions. Is that something still ongoing under Fabio? Or can we expect some update on Phase 3 on Karachaganak at some stage?

Frank Chapman

Yes, I mean connectivity, yes, we are seeing incredible level of connectivity. When you drill a well and you produce it over a long period and you believe that it can see more than 3 billion barrels of crude oil connected to that single wellbore, that is giving you an incredible level of connectivity. And what you see in the Lula Sul production wellbore, you see accurately reflected, mirrored in the P1 well, 3.5 kilometers, 4 kilometers distance, you can see the 2 pressure profiles moving absolutely lockstep. So I mean, this is really much better, in fact, than we ever could possibly have hoped for. And the level of understanding of this connectivity is, of course, greater in some areas than in others. We believe the basic features of this carbonate environment will be able -- will make themselves known to us as we drill more and more appraisal wells. So in other words, we think we're going to find this everywhere, and the evidence that we've got so far supports that. It's just that we have more evidence to date in certain structures such as Guará and Lula than we have, for example, in Iara where we've only drilled 2 wells. So I think very positive outlook in terms of connectivity. The volumes connected as observed in these wells during DSTs and long-term production tests are quite enormous, actually. In Kazakhstan, there, we have a continuing process. Actually, Almanza is still leading that process. I would say we have a constructive and very active dialogue. I mean, the meetings now have really turned up a notch in terms of their intensity. And they are amicable discussions that are going on, and I would expect that we should be able to conclude a broad-based agreement on all the issues between the 2 parties or the various parties in the course of 2011, at which point, we will be able to say more about the process for future phases at Karachaganak. We would not, of course, make any move on further investment decisions or further even engineering of solutions until we have cleared away all of the issues that exist today.

Operator

Our next question comes from the line of Hootan Yazhari Bank of America.

Hootan Yazhari - BofA Merrill Lynch

A couple of questions. I know you've been shying away from giving specifics on Brazil, but I'm going to draw the questioning towards that. Can you please give us some sort of indication of what sort of flow rates you're now looking at? I know Petrobras has been talking about flow rates of 20,000 to 25,000 barrels a day. What order of magnitude should we be looking at now? Any sort of guidance you could give there would be very helpful. The second question I had was regarding with the floating LNG side of the equation in Brazil. And if you could give us an update on what's been happening there and how things are looking on that front.

Frank Chapman

Yes, I think, basically, we have said in the past that certain wells -- and I'm thinking particularly of Guará and Cernambi, which is the northern part of -- what we thought was the northern part of Lula, now we believe there's a separate field, we say quite clearly that we believe these wells have an initial flow potential of 50,000 barrels a day. And so everything in the spectrum from 25,000 barrels a day through to 50,000 barrels a day is possible. There will, of course, be areas of the field that are developed later, which have lower flow rates than these. But we have extensive areas of the field, which we believe can produce rates in this range. These, of course, oil rates and then we have to add, of course, the additional gas production to those oil rates. On FLNG, we are studying, as a consortium, a number of uses for this gas. There are basically 4 uses for the gas. The first is obviously fuel gas, which is a relatively small proportion. The second use is for water-alternating gas injection as an enhanced recovery technique. Thirdly, we've got export via pipelines, and the first pipeline is about to be connected in the coming days. We should see the commissioning of this pipeline, which goes via Mexilhão to the shore. And then we've got other pipelines, which are under consideration. And then the fourth element is floating LNG. Now quite how -- which of these options we are going to emphasize in the development plan, and which of them comes first, and which follows, i.e., the order, the sequence, that is something that's under consideration by the partners presently. And we would hope that we will land decisions on the sequencing of the development of these options at the -- or certainly by the fourth quarter of this year.

Operator

Our next question comes from the line of Jean-Luc Romain of CM-CIC Securities.

Jean-Luc Romain - CM-CIC Securities

My question is on Brazil, as well. Could you update us on the further exploration at Brazil, work which is carried out or will be carried out and the overall discoveries, like in Corcovado, Abaré West, Deep West Marine and BMS-10, which represents only 5% offshore reserves and resources in Brazil but is around 300 million barrels of oil equivalent. Could you give us an update on the work programs there?

Frank Chapman

I mean, our emphasis at the moment, clearly, is on the 95% rather than the 5%. And there are -- there is further prospectivity. In BMS-10, for example, there's the Sagittario prospect, which is potentially quite significant, which we will drill, I want to say, the back end of this year. Having said that, these exploration programs themselves are actually giving way to higher-priority production activity. So this is a little fluid. But I think Sagittario is currently scheduled to be studied late part of this year. Apart from that, we are, I would say, focusing our major effort on the appraisal and development activities rather than going back, for example, to some of these other discoveries.

Operator

Our next question comes from the line of Anish Kapadia of TPH.

Anish Kapadia - Tudor, Pickering, Holt & Co. Securities, Inc.

Just sticking with the Brazil theme. Just more specifics, if you could. You gave last year an, kind of, implied EUR per well of about 100 million barrels. So just wondering what do you expect that to go to now and if you could update at all the $5 per barrel CapEx, $9 per barrel OpEx. And then just secondly, on the other fields where you've got around 300 million barrels, Corcovado, Macunaima, Parati, Abaré West, the aggregate number sounds quite low for those fields. So I was just wondering if you could explain has something changed on those? And should we assume that those are going to get developed in this decade?

Frank Chapman

On the recovery per well, as I've said to Lucy earlier on the call, we are in the process of a rapidly evolving picture here. We are going to take time to sit down and agree all of these development parameters, field development plans with our partners. And so for the moment, I don't want to give you a figure for the recovery per well now that we've got each well producing quite a lot more. I'm going to come back to this subject at a point in the future. For the moment however, I think it is quite straightforward for you to take the new much higher volumes and make some assumption about how the CapEx and OpEx figures undiscounted or even discounted comes from that because the profiles can be estimated here. But the CapEx and OpEx figures, on a unit basis, can be estimated. You're not really installing any more facilities and you're producing a lot more reserves, so you can certainly make an estimate of unit CapEx and OpEx. In terms of the 5%, I think it is fair to say that structures such as Abaré West and Parati are fairly -- relative to some of the other structures where we're talking multibillion barrel discoveries, these other structures are relatively small, and CapEx efficiency and economics will mean that their prioritization slides down the lead table of priorities. So I think that's a reasonable assumption, and we've tried to give guidance as to the materiality of those things by indicating that 95% of the resources are in the 5 big discoveries.

Anish Kapadia - Tudor, Pickering, Holt & Co. Securities, Inc.

Just a follow-up on that. The one that is kind of interesting to me was Corcovado because I know originally you were talking about that as a billion-barrel-plus structure. So can we take that as you taking the numbers down on Corcovado?

Frank Chapman

Yes, I mean, Corcovado, there are different -- differing views in the consortium regarding the type of play we're dealing with. It's a much older sediments that we're dealing with there. And common with Parati, it's a different type of play. So you're dealing there with a 40 API light crude in a volcanic-plastics type of environment. This is what we believe that we're dealing with, so geologically, a much deeper section. And we believe that, for the moment, we should certainly focus rather on the development of the 5 major discoveries rather than focusing more investment on appraisal of something which is a very different style of play altogether.

Operator

As there are no further questions, I will return the conference to you, Sir Frank, for any closing remarks.

Frank Chapman

Well, thank you very much, everyone, for your questions. If I may, to conclude our call today, we have continued to make good progress with our major growth projects, most notably in Brazil, where we have seen net reserves and resources doubling since 2010, huge additional volumes, which have a substantially higher unit value. So thank you for taking part in the conference call today. And I'd like to remind you that we'll be announcing our third quarter results on the 25th of October. So I want to say goodbye for now, and thank you very much.

Operator

This now concludes our conference call. Thank you all very much for attending. You may now disconnect your lines.

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