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Executives

Bruce Connery

Frank J. 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 De Oliveira Barbosa - Chief Financial Officer, Executive Director, Member of Group Executive Committee, Member of Chairmans Committee and Member of Finance Committee

Analysts

Theepan Jothilingam - Nomura Securities Co. Ltd., Research Division

Brendan Warn - Jefferies & Company, Inc., Research Division

Oswald Clint - Sanford C. Bernstein & Co., LLC., Research Division

Michael J. Alsford - Citigroup Inc, Research Division

Michele Della Vigna - Goldman Sachs Group Inc., Research Division

Hootan Yazhari - BofA Merrill Lynch, Research Division

Thomas Adolff - Crédit Suisse AG, Research Division

Irene Himona - Societe Generale Cross Asset Research

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

Jason Gammel - Macquarie Research

BG Group (OTCQX:BRGYY) Q2 2012 Earnings Call July 26, 2012 6:00 AM ET

Operator

Hello, and welcome to the BG Group Second Quarter Results Call. [Operator Instructions] Just to remind you, this call is being recorded. I'll now hand you over to Bruce Connery, Head of Investor Relations. Please begin.

Bruce Connery

Good morning, ladies and gentlemen, and welcome to BG Group's Second Quarter Results Conference Call. During the course of this call, our Chief Executive, Sir Frank Chapman; and our Chief Financial Officer, Fabio Barbosa, will take you through the quarter's key business highlights. 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 result statements. 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 and accounts for 2011. Thank you. And now over to Sir Frank.

Frank J. Chapman

Good morning, ladies and gentlemen. I'd like to begin by running through headline figures from our results today and briefly update you on the progress we're making on our key growth projects and other portfolio developments. I will then hand over to Fabio, who will take you through the key financial data in more detail.

Cash flow from operations grew by 21% to $3 billion in a quarter where total operating profit was down 8% at $2 billion. For the half year, cash flow from operations was up 32%, operating profit was 6% higher and earnings grew by 21%.

Now let me take you through some of the key project milestones and operational developments.

In Brazil, Petrobras, the operator of the big 5 discoveries, where we have very material interests, presented its latest business plan, which confirmed its commitment to the fast-track development of our joint interest in line with BG Group's own plans.

Earlier this month, the partners approved contracts worth $4.5 billion for the first 6 topside modules and integration packages for the Brazilian constructed FPSOs.

The BM-S-11 partners have also issued tenders for an additional chartered FPSO expected onstream in 2015. The second FPSO destined for installation on the Sapinhoá field in 2013 is 92% complete. The third FPSO to be installed on Lula North East also in 2013 is 85% complete and now in Brazil for topsides integration. And FPSOs 4 and 5 are on schedule at some 25% complete.

A substantial proportion of our first phase facilities is now under contract. And this, alongside continuing improvements to drilling durations, affirms our capital cost estimates for Brazil and our expectation of more than 600,000 BOE per day production, next to BG Group by 2020.

In Australia, we continue to make progress towards first LNG in 2014. We drilled around 80 wells in the quarter and continue to build an extensive inventory of drilling locations supporting upstream execution in the second half of the year.

Further, the Argyle field compression station is undergoing final commissioning. On the pipeline, the entire 200-kilometer gas collection header has been welded and is now being trenched, while clearance and grading of the 340-kilometer export pipeline is now some 40% complete, with pipe-joints being laid down along the route.

At the LNG plants on Curtis Island, tank and jetty construction progressed, and the first shipment of 6 production modules has departed from Thailand.

Turning now to the U.S. As a result of the -- a lower long-term Henry Hub price premise, we further reduced our rig count to 6. Our efforts in the U.S. are now focused on progressing our significant opportunities for the export of LNG from North America to BG Group's global customers.

Elsewhere, we saw progress on other important projects. In Egypt, Phase 8b of the West Delta Deep Marine development started gas production and new facilities at the Margarita and Bongkot South fields in Bolivia and Thailand continued their ramp-up.

In Kazakhstan, completion of the comprehensive agreement there paves the way to unlock the substantial remaining potential of the giant Karachaganak field.

Turning now to exploration and appraisal. Offshore Tanzania, we made a fifth consecutive discovery with the Mzia-1 well. This was our first success in the deeper Cretaceous section of the basin, opening an extensive new play fairway in our acreage.

Meanwhile, a new gas discovery was made in the Egypt El Burg concession and the fourth Bowen tight gas sands well reached TD in Australia and is under evaluation.

Alongside this, we saw a further successful appraisal in Brazil. Looking forward, the long-term shutdown at the Elgin/Franklin field, the deferral of Jasmine startup to 2013 and the scaling back of drilling operations in the U.S. are expected in aggregate to reduce year-end production by some 50,000 BOE per day.

Opportunities elsewhere in the portfolio are expected to offset some 40% of this impact. The net result is that we expect production at year end to be some 720,000 BOE per day. The full resumption of Elgin/Franklin production and the startup of Jasmine are expected during 2013.

And now, I'd like to hand you over to Fabio for a summary of the financials.

Fabio De Oliveira Barbosa

Thank you, Frank, and good morning, 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 by 6% in the quarter with $3 billion, reflecting a 4% increase in production volumes and favorable changes in the production mix. Third quarter operating profit of $1.3 billion was 11% lower than last year, as increasing revenues was more than offset by higher costs. Notably, the increased exploration charge of $203 million, which included $164 million charge for the Corcovado-1 in Brazil.

Costs were also affected by changes in the production mix that impacted both unit operating costs and the depreciation charge in the quarter.

In our LNG segment, total operating profit for the quarter was up 7% to $594 million, in line with our expected seasonal phasing. Once again, we benefited from strong demand from the group's LNG cargoes, especially from Japan, where cargo deliveries more than doubled in the quarter to 16. Overall, there were 7 fewer cargo deliveries than in the first quarter of 2012, to a large extent as a result of scheduled maintenance at EGLNG in April. We now expect total operating profit for the segment as a whole to be at the upper end of our $2.6 billion to $2.8 billion guidance for 2012.

For the group as a whole, total operating profit in the second quarter was down by 8% at $2 billion and earnings of $1.1 billion were 4% lower than last year. As you have seen, our total results also included a $1.3 billion noncash post-tax impairment charge recorded in the quarter against our shale gas business in the U.S.

This was the result of a lower long-term Henry Hub price premise at the level $4.25 per MMBtu from $5 previously.

The group's investment program continues, with organic capital investment on a cash basis in the quarter of $2.4 billion, once again, focused on our major projects in Australia and Brazil. This takes the total investment in the half year to some $4.9 billion and is consistent with our 2012 guidance of $11.5 billion at reference conditions. We have made additional progress in the group's funding plan to support execution of our investments. And during the quarter, we met important milestones in the portfolio rationalization program.

We reached a binding agreement for the sale of our interests in Comgás in Brazil, which is expected to be closed by the end of the year, subject to regulatory approval. This agreement alone will release around $2.7 billion of capital at prevailing exchange rates.

During the quarter, we also completed the sale of our interests in power plants in the Philippines for net cash proceeds of $360 million.

In June, the group issued 3 tranches of long-dated hybrid bonds totaling almost $2.1 billion. These bonds, which were sterling, euro and U.S. dollar denominated, expire in 2072 and were very well supported by investors as indicated by the large oversubscription in all tranches and the strong secondary trading.

Cash generated by operations in the quarter increased by 21% to $3.1 billion as a result of higher working capital cash inflow. And we ended out the quarter with cash of $5.3 billion and net debt of $10.2 billion. The average maturity of the group's gross borrowings increased to around 17 years following the hybrid bond issue, and the gearing ratio was further reduced to 24.9%.

In line with our established policy, the board has approved an interim dividend of $11.88 per share, which is half of the 2011 full year dividend. The dividend will be paid on September 7 in sterling, which amounts to 7.64p per share.

Thank you very much for your attention. That concludes my remarks. And now back to Frank.

Frank J. Chapman

Thank you, Fabio. And we'd now be very happy to take your questions. Please, could you state your name and company when asking a question.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from the line of Theepan Jothilingam of Nomura.

Theepan Jothilingam - Nomura Securities Co. Ltd., Research Division

Three questions, please. Firstly, just on production. Could you be a little bit more specific on the timing or what contribution we should assume from Jasmine and Elgin for 2013? And on production itself, I guess, could you just clarify perhaps where U.S. gas production is today and what the impact of your changes on assumptions are for the year 2015 target? Secondly, I think BG has been very clear that the single A rating's been important and there has been excellent progress on funding. I was just wondering, would you, perhaps, on the disposal side, consider selling parts of your LNG business? I'm sort of thinking about liquefaction assets and in the context that some of your peers are considering something similar as it reduces the leasing obligation around LNG? And then thirdly, a question perhaps for Frank, just around management succession. Could you talk a about -- a little bit more about the prices? Any timing on when a successor to yourself may be announced?

Frank J. Chapman

Okay. On production, let's take them in the order. On production, I think we said before that the contribution from Elgin/Franklin is around about 17,000 barrels a day. So currently, as we left the end of the Q2, we were doing a bit over 6 90. I think for the quarter it was -- for the month or something, it was close to 6 90. Maybe it touched more than 6 90. So if you put Elgin back in, just assume -- that's why I'm very clearly identified decrement, if you like. If you add back the 17, you're getting -- you're ignoring the U.S, you're getting over 700,000. So around 710,000, which is sort of like well underway between the 6 50 and 7 50, the original plan. And given that we said clearly, during our strategy presentation that this was second half of the year loaded as the new fields begun to ramp up. Then I would have said that, that progress represents good progress and would have been in line with what our expectations were. Jasmine was originally expected to come on late in the year anyway. And its contribution in our original plan was not plateau contribution, but part of the ramp-up. 2015 target, that's further out. We will come back to the subject. We'd happy to talk about that as is customary during February. Selling parts of the LNG business. We, of course, keep all of our assets under review, as you know. But it isn't really our practice to really speculate on the sale of any asset or any business segment. Clearly, that wouldn't be in our commercial interest to do that, and we generally don't tend to do that as you're aware. Management succession. I like to think that we are reasonably organized in terms of planning things. We managed to achieve an effective transition of the chief financial officer. Similarly, it went extremely well with the transition to our new Chairman. We have said we have a plan to -- an orderly plan to manage the transition to a new chief executive. My contract, as everyone, I think, is pretty much aware, automatically comes to an end of my 60th birthday, that's the 17th of June next year. If you want to send presents, I'll give you an address. But that's my 60th birthday. And we have a good plan to get ourselves to a good position in that timeframe. So I can't really say any more than that. I can't tell you about the succession process itself because I'm not responsible for it, clearly. But that -- hopefully, that will help a little bit with further clarity on the timeframes. Single A credit rating, Fabio.

Fabio De Oliveira Barbosa

I think we have made a very good progress in our funding plan and our gear is down now to 24.9. And this is very well understood by the markets. And the rating agents -- agencies, all of them confirmed in last June our mid-single A. So we are progressing according to plan and under no pressure to do anything different from what we announced and discussed with the markets.

Theepan Jothilingam - Nomura Securities Co. Ltd., Research Division

Okay. And can I just come back to production? I mean, as we sort of number crunch, when exactly should we assume that Jasmine and Elgin start to contribute in 2013?

Frank J. Chapman

Well, we actually think -- I mean, the situation we're in with Elgin is the works -- the situation out there is quite stable now. We're continuing to work both on Elgin wells. And also we're going to move on to have a closer look at any remedial work that we might have to do on Franklin as well. We obviously don't want to commit to a date because we don't want to -- we want to be sure that we have everything in place and that it is appropriate and ready to start up. We have regulatory processes we have to go through to get the signoff of the regulator. So it's a little tricky to say right now when this is going to be started up. But if this were progressing smoothly through all these stages and we saw production building up in the early parts of 2013, then that wouldn't be a surprise. But I don't want to give any dates. We're not the operator. And I think everyone has to realize we're doing the right thing here. We're going to do a good job on it. And there are quite a few regulatory hurdles to cross before everything comes back on stream. But I'm hopeful that we'll make progress in the early part of 2013. Jasmine, the operator -- just checking in a moment. Operators...

Unknown Executive

I've given the chart [indiscernible].

Frank J. Chapman

Yes, okay. I mean, it's second half of the year, basically. This has been quite a delay. And we will come back to you on this, Theepan, with the date when we've checked the operator's latest disclosure.

Operator

Our next question comes from the line of Brendan Warn of Jefferies.

Brendan Warn - Jefferies & Company, Inc., Research Division

It's Brendan Warn from Jefferies. Just a couple of questions. Just first one, I was hoping an accountant would ask this question rather than myself as an engineer. Just in terms of the noncash prospects impairment. If we look at your change of reference conditions, if I ask an assumption of a scenario, the reference conditions were to change again by another $1 per MMBtu. What sort of further write-down would we see? And then just second question, you're up to your sort of fourth test well in the Bowen Basin, the tight gas sands, if you can just give us any results or the evaluation results. Have you flow tested these wells yet?

Frank J. Chapman

Yes, Fabio, do you want to talk about the...

Fabio De Oliveira Barbosa

No, that's the impairment is not a linear exercise that will float according to the gas price. It depends on the quality of the acreage in different areas. And you cannot apply simply a rule of thumb there. So we read the exercise and considering all the formation that they have available currently and it's important to mention that we continue to explore some areas, particularly in the Marcellus. And this was the conclusion. But this is not a linear exercise that would just move the value of the asset according to the changing gas price.

Frank J. Chapman

I mean, just to give you a little bit of an insight here. Of course, this assumption of $4.25, instead of $5 flows out of actually a very substantial piece of work that we've done internally. Now we talk about our commercial capability and our knowledge of markets, and we do, of course, do a lot of proprietary analysis on supply/demand in markets which are important to us. And the answer to this slowdown this piece of work is that, actually, on balance, we think prices will be slightly lower than we thought some time ago. And as a consequences, a direct consequence, that flow through into a straightforward sort of accounting process, which delivers the impairment. The fact of the matter is, however, that nobody really knows what gas prices are going to do. We think that today's gas price is quite a lot lower than the -- will reach equilibrium. But whether it's actually reaches equilibrium at $3.75, $4.25 or $5, actually, nobody knows that. So we've taken a realistic view and we'll keep that under review from time to time to see how it evolves. I think that's all we can really say at this point. Of course, you know that BG's strategy has got 2 strands to it. It's got the strands to do with focusing on high-quality shale gas assets that we can deliver pipeline gas from. And alongside it, as we announced in February, we've now got an LNG export strand to the strategy. And these 2 opportunities working together are intended to allow BG to create value over a very wide range of Henry Hub prices. So at the moment, of course, we are putting a huge amount of effort into perfecting our LNG expert opportunities. And it feels good in these circumstances to be the first mover with the first contract of LNG, 5.5 million tons is going to come out of the U.S. So that's sort of where we are.

Brendan Warn - Jefferies & Company, Inc., Research Division

And on Bowen basin?

Frank J. Chapman

Bowen Basin. Yes, that's good. Now we've drilled 4 wells. What I can tell is that we've intersected a gas column in every one of those wells. The question is, what's the mobility like? So we finished the 4 wells with a particular spread. And now we're going back in the last half of the year to stimulate and perform many frac jobs on these 4 wells to see what the mobility of reservoir fluids is like. But anyway, first step, find the reservoir. Is it -- have we got sand? And is there gas in it? Answer, all 4 of them have managed to do that. Will the gas flow? We're going to do a bit more work before we can say that. So I'm very happy where we are today, actually.

Operator

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

Oswald Clint - Sanford C. Bernstein & Co., LLC., Research Division

I guess, yes, just the first question on the production again. Just on the extra 20,000 barrels a day coming through from other opportunities. I wondered if you could just say where that's coming from and the risks around that 20,000 barrel-per-day number towards the end of this year. Then, secondly, I'm just curious about your thoughts on your kind of market position, market share in Japan, if some of the nuclear reactors are potentially coming back on stream. You're putting 1/3 of your cargoes in there so far this year. But also, the Japanese increasing appetite to get new sources of LNG and different pricing mechanisms. I'd just be curious to hear your thoughts on that.

Frank J. Chapman

Okay. 20,000 barrels a day, I'm extremely pleased also for our staff to be able to report that the majority of that is coming out of the U.K. So we have started to see, notwithstanding the fact that Elgin/Franklin, obviously, is offline. The other assets in the North Sea. All the effort we've put into perfect improving performance there is starting to come through. So a good chunk of it is coming from the U.K. and that's actually quite nice to be able to sit here and say our efforts are being successful. Market share, I mean, the global LNG market, very complex. And when you see cargoes going to one destination, it may be only a few cents of difference sending them to that location rather than another. So I would not draw the conclusion that as nuclear comes back on stream in Japan, that there is going to be all of a sudden a big surplus of LNG. I don't think that's the case. More generally, I maintain the same view today that I presented in February that the market has tightened more quickly than we expected as would come out of this -- or as we're trying to come out of this crisis that started in '08 and '09. The market has got tighter more quickly than we expected, and that's why we're sitting here with series of hedges in place that sometimes we wonder if we -- well, we certainly prefer not have them at the moment. And we will becoming -- we'll be substantially unhedged as we go into next year as we said. So my general view at the market, it remains as it has been in the past, which is that it is set fair for -- to remain a good market for some time, and that we're going to benefit from having a fundamentally good market, number 1; number 2, shedding, as we go through this year to next year, our long-term hedges; and third -- and those 2 things together are providing short-term momentum to the LNG business. And the third dimension is a volume growth, which will come through the various projects we've explained. So those are the 3 things, 2 of them driving short term, 1 of them starting to give underlying earnings growth as the volumes step up. So I hope that helps, Oswald.

Operator

Our next question comes from the line of Michael Alsford of Citigroup.

Michael J. Alsford - Citigroup Inc, Research Division

I've got a couple of questions, if I can, on, firstly on to the divestment program. Could you give maybe an update as to I think progress around the Gujarat Gas and other assets you sort of highlighted as potential sale candidates such as the midstream assets in the U.S.? And I guess, also for me, around through the LNG business. Could you maybe give a bit of color as to what was the impact from simply the maintenance in the second quarter? And maybe what was the impact from, say, yes, the hedging and the pricing that you had obviously, in the second quarter that would be helpful.

Frank J. Chapman

Okay. Let me give the divestment to Fabio. But first, let me just found the LNG business. The impact of maintenance was principally in Equatorial Guinea where we saw 4 fewer cargoes as a consequence of that maintenance. On the whole, though, I would say that the LNG business is doing actually pretty much what we expected it to do. Halfway through the year, we're halfway towards the top number, 1.4 billion, halfway towards the upper end of the guidance range that we gave. So there's nothing really surprising in these numbers. And it's good, at this point in the cycle to be able to say, actually, we expect to be at the top end of the range rather than in the middle or rather than at the bottom. So there's nothing that is unusual or unexpected about the trajectory in our LNG business.

Fabio De Oliveira Barbosa

Michael, on the divestment, I think that the numbers show that we are clearly making a lot of progress there. We delivered the Philippines. And after signing the first transaction last year, we've managed to deliver this now. We signed agreements in our regas terminal in Chile. And of course, Comgás. So altogether, we already accomplished some 70% or so of our $5 billion target and in terms of capital release. Gujarat Gas and TGGT, the process on the TGGT we started with a discussion led by our partner there. And it wasn't concluded in a satisfactory way. We still -- we are still assessing our options there for the asset. And our intention is unchanged. As for the Gujarat Gas, we, as you know, it's a public process. We had -- we received a lot of expressions of interest. The process is now a little bit slower than we would like. But we keep exploring our options and alternatives, discussing with potential players and potential investors. And as you can appreciate, this is part of our strategic decision to exit in the long run the Transmission and Distribution business and we'll continue to pursue a target.

Operator

Our next question comes from the line of Michele Della Vigna of Goldman Sachs.

Michele Della Vigna - Goldman Sachs Group Inc., Research Division

I had 2 quick questions. The first one really to the gearing. It was good news to see down to 25%. I was wondering if you could give us a guidance of where you expect it at year end. And then the second question relates to LNG volumes. I was wondering, as we look to 2013, '14, '15, do you see the risk of volumes in Egypt and Equatorial Guinea coming down due to a mix of higher domestic demand? And what is a struggling supply?

Fabio De Oliveira Barbosa

Well, on gearing, we got the 24.9. And we haven't provided any guidance for the year. But I would mention that in this number, we are not including any impact of, for instance, the proceeds coming from the Comgás sale which I expect to come until the end of the year. But other than that, I would ask the -- invite you to look at your numbers and try to figure it out.

Frank J. Chapman

Well, Michele, on the AGLNG, I don't have any issues there with respect to domestic demand affecting export volumes. AGLNG -- sorry, that was EGLNG. EGLNG, I'm quite comfortable that we've got sufficient results to balance the plans that we've got, as well as the local demand in the market locally. There are a lot of changes taking place, including economic changes, such as the removal of subsidization being moot at this stage, not, not implemented, but this is quite an essential feature of the restructuring of the economy, which itself will have an impact as subsidies come off on the price of gas. And therefore, will have an impact on demand. So these things, I think, are quite complex. And I think probably, as we start to think about the effects that this might have on later years, '14 and '15, they probably better come back and have a look at that as we sit down to get in February and talk about our strategy. But for the moment, I don't have any deep concerns about that issue.

Operator

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

Hootan Yazhari - BofA Merrill Lynch, Research Division

I have 2 questions on the operations, really, going forward from here. First of all, I wanted to see if you could give us any more color on how effective all the maintenance that you've been conducting on your North Sea assets has been and whether we can see further potential upside surprise from production there. And maybe some guidance on how much maintenance we should be expecting for the rest of this year in your North Sea assets? And secondly, now with Lula 1 ramped up to full production of 100,000 a day, I just wanted to get your thoughts on what we should be expecting in terms of profitability there? Is there going to a step change from what we've seen in the past there? And any other gleanings that you might want to share with us now that we're full speed there?

Frank J. Chapman

Well, obviously, that's good, Hootan. I'd like to speak to you this morning. Outside from the North Sea, I mean, I can tell you that assets, for example, like Armada, had made a big journey from quite low production efficiency a couple of years back to actually very respectable and soon to become actually quite high production efficiencies. And we're trying to work the same formula on platforms that we more recently became operator of, such as specifically Lomond and Everest. So all of that work in terms of the improvements on the one hand and production efficiency, versus on the other hand, the longer shutdowns that we're having to do to continue progress with improvements there, all of that is factored into our estimate of year-end exit rate. So I don't really want to start digging into the individual assets. I would say that we're making investments over there. We're putting a lot of effort into that, and the things going in the right traction. And indeed, when we've had this missing production from Elgin/Franklin, the recovery, the offset has come from other North Sea fields, which is good. I wouldn't take it further than that at this stage. Let's see how this develops. We've got more shutdown work, for example, this year on Lomond later in the year. We've got some shut down work on Everest to do. So that -- I think it's fair to assume the situation is getting better. But it's all factored in to the 7 20. On profitability, clearly, the margins on Lula and in Brazil, in general are stronger than some of our other assets in the portfolio. And hopefully, we'll start to see that coming through. Certainly, as the overall production builds, it will make a significant difference to our unit profitability. But again, I wouldn't say anything more specific than that at the moment. The very good thing that's happened during the last quarter is the publication of Petrobras' new business plan. And although there is at the highest level, quite a dramatic change in what they're intending to deliver. When you disaggregate that picture and focus down on the pre-salt, then it is very good to see their clear, unequivocal confirmation that they are focusing their efforts on fast tracking the very properties in which we are the partner in order to deliver these fields, in line, actually, with BG's plans that we presented to you in February. And that sort of gives us a lot of confidence about the future plans. And bringing this back to your question, the reason they're doing that is because here is where the highest unit profitability rests. And therefore, there's a very good reason for Petrobras to be strongly aligned with BG and ensuring that these fields are brought on stream as quickly as possible.

Operator

Our next question comes from the line of Thomas Adolff of Crédit Suisse.

Thomas Adolff - Crédit Suisse AG, Research Division

Firstly, just on exploration. Can you give a bit more color on your discovery in Egypt and otherwise also the political situation there? And also, what sort of prospectivity you see in your offshore acreage in Kenya? Is it gas you're targeting or is it the extension of the Bower [ph] trend, and also, generally about your strategy to broaden your exploration Hopper. And just on the financials or just to clarify, does your reported net debt already de-consolidates the Comgás net debt? And also, can you give a bit more color on your working capital movements during the quarter? And just finally, from a few quick ones on Brazil. On the Cabiunas pipeline, is the construction expected to start this year? And when do you expect this to be completed and operational? And do we have to worry about any sort of environmental permits? And finally, just a question on the Replicant FPSOs. When I spoke to Petrobras, they did mention that there were a 1-year delay to the first year FPSO. So obviously, partially offset by an additional unit. Can you confirm that, please?

Frank J. Chapman

That's a long list of questions there. And some of them, I think -- Fabio, you have a go.

Fabio De Oliveira Barbosa

Yes, just the Comgás. You are right, we've consolidated net debt Comgás. So this is reflected in our numbers. However, we haven't adjust, of course, for the procedures that we haven't got them at this stage. So net debt of Comgás is out. And on the working capital, it's basically the comparison we have last year. I know you had cost [ph] calls and this year, we have a different position there and a very strong performance in production on buying these prices.

Frank J. Chapman

Okay, right. Now, where do we start with this lot? Replicant FPSOs, there is a delay in the first Replicant FPSO relative to Petrobras's original plan. So we had already -- our plans, actually, have taken some accounts of that. So the additional delay, relative to our plan in the whole scheme of things is not material. But offsetting that not material change is the introduction of a new FPSO announced today, early last week and included in the release today that is intended to be onstream in 2015. So taking in around, that is not a significant change. Cabiunas pipeline. The way that's going to work -- is that the first pipeline over Mexilhao is going to take care of 3 or plus FPSOs. So the first 3 to go on stream will have that as an export route. Clearly, as the next FPSOs start to come in, FPSOs 4 and 5, they are going to need the Cabiunas pipeline. So that gives you a sort of back-end idea 2014 of when this needs to be installed. The -- in all of our ventures anywhere we're operating in the world, of course, there are permit issues to be dealt with. And given the amount of work we're doing offshore, Brazil, I don't foresee that this will be a particularly unique permitting process. Now Egypt. the discovery we made was in the El Burg concession, where we are have a 70% equity in our operator. It was unusual discovery because it was in the simian. So this is deeper than the prior processing sections that we proved earlier. That makes it liquid rich gas. And therefore, it's interesting because it makes us focus on identifying other such opportunities elsewhere in the play. That's the first thing. The second thing, of course, is that El Burg is home to a significant quantity of deeper legacy in prospectivity, which we talked about in February. And the Notus well will spot at the end of the third quarter and will be our first test of the Oligocene. And that's in the same block, but a much deeper horizon. I don't think I'm able to answer in this call all of the dimensions of the political situation in Egypt. So I'm going to put that to one side at the moment. We are producing gas. We are making progress there not within the difficult situation, the transition and so on. And for the moment, I'm just going to put that down, if I may, Thomas, that's big question. Kenya we've just -- just -- we now have off the boat process seismic. And we should have fully processed seismic in-house in the next month or 2, Looks extremely interesting with lots of different play styles. And it looks to me like a playground a bit for the exploration. They're quite happy with what they see. We believe that there is a good probability of this being an oil prone play. But there are also gas concepts in this whole area. So very interesting. We're already looking at well planning and trying to get rig availability for next year. So very good progress there. With respect to broadening our exploration horizons, we have a number of initiatives ongoing. Tanzania and Kenya were sort of last year's products, 2 years ago for Tanzania, last year for Kenya, products of that effort. And we have other things in the hopper, as you put it, which we won't disclose today. But we're with quite busy. So a couple of years ago, we weren't anywhere on this East Africa. Now we've got Madagascar. We've got Tanzania. We've got Kenya. We're quite happy with that and we're looking at other place elsewhere to strengthen our exploration portfolio. So Thomas, I hope you've gotten the most of your long list of questions.

Operator

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

Irene Himona - Societe Generale Cross Asset Research

It's Irene Himona. I had one question regarding Australia, please. I know you drilled 80 wells in the quarter. Could you perhaps put this in the context of what you need to start up Train 1 by 2014? So is there sort of quarterly run rate on the drilling we should be thinking about? And then aside of the number of wells, any update on Australia, particularly in the context of the cost pressures a that you and the industry is experiencing? And how do you perceive the risks surrounding that project?

Frank J. Chapman

Yes, I mean, last quarter, if I remember rightly, we gave some data on these number of wells. I mean, we need to have available by the time we get to 2014, we need to have about, I think, 1,750 wells available. I want to say that we've drilled something of the order of 750 to 800 wells already. When we get the 4 12 rigs operating this year, we'll be drilling about 40 or 50 wells a month. There've been -- it's been a bit slower than that in the past because of a combination -- and we haven't mobilized as many rigs because of having available drilling locations. But now we have something like 1,350 drilling locations available. So a strong inventory, which will support the ramping up of drilling activities. So we're sort of halfway there. We've got a couple of years to run. And we can do 40 to 50 a month, as we get through the second half of this year. So I'm not really worried about that. On Australia costs, we put a huge amount of effort and waited up to secure good market data, representative market data, based upon the real packages that we were bidding. And based upon that, we made changes to our capital cost estimates last quarter. And I'm happy to say that we regard those costs as stabilized and we're getting on with our execution. Actually, on cost, more generally, it is also, I think, very good news that following the award of its $4.5 billion of contracts, actually, they are now let under -- letters of intent will be formally letters contracts awarded is contracts imminently. With that $4.5 billion in place, the top side of 6 of the 8 replicants, we now have a very substantial proportion of the facilities under contract. And that, alongside really good progress with reducing drilling times. We just drilled one well to TD [ph] I think in 40.5 days. That's our lead well. Really, great progress there. And this is getting much more repeatable. With those 2 factors together, we are very happy that our cost estimates for Brazil have been affirmed. So that last piece of where, the 6 modules was one of the final bricks in the walled town really affirm the overall picture for Brazilian costs. Of course, working on the positive side, we've got Brazil FX working in this case. In Australia, which worked against us. In this case, It's working for us. So pretty happy about the capital cost situation in Brazil and that we managed to stabilize the situation and Australia.

Operator

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

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

I've got questions on U.S. and on Brazil. I was just wondering if the reserve -- would there be any reserves write-down associated with the changing gas prices. I'm just wondering to say you could quantify that amount. And also related to the U.S. If you could give an update on any potential further LNG export projects? It is in that you're lower U.S. gas price/mix even more confident in terms of these export projects. And then just a few clarifications on Brazil. And the last year you gave a target of 225,000 barrels a day of oil equivalent for Brazil in 2015. I think that was revised down this year to about 185,000 BOE per day. With what looks like an extended ramp up period of the FPSOs in Brazil, are you still confident in that 2015 target? Or do you think that might be pushed back? And the final one in Brazil is just to try and understand the CapEx situation a bit better. This is what Petrobras is saying. In Petrobras' recent strategic plan, we saw the CapEx has gone up 56% since the last 5-year plan. So up about $16 billion. I understand some of that 2011 rolling off, 2016 rolling on. But even with that increase, even without taking into account, that increase seems pretty steep, especially compared to your numbers. So I was just wondering how you reconcile the numbers versus your own?

Frank J. Chapman

Well, of course, Petrobras' numbers are theirs and ours are ours. So I mean, I can't answer any questions really about Petrobras' structure to their budget and how they have approved that and the changes relative to it. I mean, they've also got a pile of other things that -- many other things that we're not partners too. So therefore, it's not really relevant to extrapolate from their CapEx increases to our business. What I've just said a moment ago is that we are very happy having got the final -- well, not the final brick, but a significant outstanding piece of the facilities cost now pinned down in terms of contractual value, having got that and having now seen really good progress with the drilling efficiencies. We are comfortable, very comfortable that our estimates for Brazil have been affirmed. So we -- I'm not seeing any increase in our budget for Brazil, okay? Now in terms of production rates. Again, I have to be a little bit careful here. If we start picking out individual units and not allowing for other units coming in and so on and so forth, what I can say to you is that BG's plan that we presented in February was our own plan, right? It wasn't Petrobras' plan, which had some of these units coming on slightly later than their plan in any event. And I'm happy to say that they've -- essentially Petrobras confirmed their commitment to the fast tracking, as I mentioned earlier, and that the consequence of that delivers a plan in line with the plan that we presented in February. Now if you go down into individual FPSOs, there's 3 months here and 4 months there and new FPSO coming in here and so on, you will find small differences. But in the big picture here, it's exactly what we showed the market in February.

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

Okay. Just one to that. If Petrobras talking about 1.5 year ramp-up period on average, I think, for most of the FPSO. Is that in line with what you're estimating back in February?

Frank J. Chapman

Yes, I mean, we've got -- I believe our plan carried a 12 to 18 months sort of window for ramp-up. Now what's interesting about this ramp-up is that it is not a consequence of FPSO availability. Now I'm speaking now generically over the whole piece and this is what I'm saying now. It may not apply to each and every case. But the overall picture is that we won't be constrained for wells and we won't be constrained for FPSOs and we won't be constrained for major infrastructure, such as gas export. But there are constraints on the availability of subsea architecture. And Petrobras and BG are working very hard together to try to alleviate wherever possible any constraints from subsea architecture. So Christmas trees and subsea flow lines and so on. And of course, as I said earlier on, because of the highly cash generative nature of these investments, there is no doubt that Petrobras and BG and the other partners are extremely motivated to eliminating any delay in the ramp-up that can humanly be eliminated. So it's in everyone's interest. And we'll be working very hard on that the whole way to the time when these wells come on stream. Let's go back once again to the point here that is absolutely vital to make. When Petrobras issued their revised business plan, it represented a significant change to their outlook for production. When you disaggregate that plan, what it shows is their absolute first line commitment to delivering the properties in which we have an interest in line with the schedule that BG presented last February. That's the main message. Now you asked a question about U.S. reserves. We have to remember that the reserves booking process, what's in the ground and so on, is absolutely separate from the accounting treatment, which is driven by an assumption about future gas prices relative to the book value. So the -- I don't envisage, at this point, a change in the current reserves. The 8 Tcf that we talked about, for example, last year, that remains unchanged at the present time.

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

Okay. And then just a follow-up with your lower gas price. Are you getting more bullish on LNG exports and just the progress in terms of your own plans there?

Frank J. Chapman

Yes, no, I mean, look, we said to one of the earlier participants in the call, we said in February that we wanted to develop this strategy with 2 strands, and that, that strategy would provide us with the opportunity to create value over a much wider range of LNG prices. So as prices go down, we know that our activity level will fall in the pipeline gas and we're working very hard to perfect and deliver the many opportunities we have for creating LNG exports. So yes, sure. I mean, we know that LNG exports are profitable at significantly higher Henry Hub prices that we see today. So that effort that we are piling into that is going in irrespective of price. On the other side of the coin, as I've said before, the lead time between pumping in your first -- your investment and yielding revenues, so how long does it take between the time you decide to spend money on a well and the time you get revenue. This is only 3 months. So it's actually that arm of the strategy. It's actually quite flexible. We can turn it down and we can turn it back up again. And we can respond actually quite well to short-term price signals. and that's what we're doing today.

Operator

Our next question is from the line of Jason Gammel of Macquarie.

Jason Gammel - Macquarie Research

There is still a couple of questions that I have. On Brazil, actually. First of all, very specifically, now that you have some production history over Lula, can you make any comments about where you're seeing on reservoir pressure drawdown and water cuts at the facility? And then secondly, and more broadly, if one does disaggregate the operators business plan, one finds that there are 10 FPSOs in the plan that are related to transfer of rights areas, many of which have not been even drilled yet. So I guess my question here is really more of if the operator were to approach you to put incremental investment into Brazil in the back half of the decade to potentially replace some of those FPSOs in their plans, would you be willing to make those incremental investments in the back half?

Frank J. Chapman

Look, I mean, on this whole field development planning, we've got 14 FPSOs now, or we got 13 and we're in a process to tender for 14. And this increment is just one demonstration of the ongoing evolution of the field development plan. And this is going to go on for years. This will go on for at least another 2 decades as we get information, as we agree on which is the next -- I mean, we sort of like got our hands full at the moment because we've got 14 FPSOs. That's quite a lot of aggregate production capacity in total, you'll appreciate, and we're busy with that. And then parallel with that, the reservoir engineering people are working very hard to bring together a combined view of the partners on what should be the next thing we do. So when we talk about future investments, it's absolutely assumed, absolutely assumed that we will make many more investments, actually, in a new -- so far, not confirmed FPSO locations within this overall terrain on these various discoveries. And so that is actually sort of like normal business. And we've put a lot of effort into that, and I'm very optimistic about the further development potential. And that brings me back to your first question. I'm not going to give you specific data. Suffice it to say that we keep getting good data. These fields are incredibly prolific, and we are finding reservoir sections in some of the worlds that we haven't seen before and we're seeing very good performance. So when I say in my notes that we continue to successfully appraise Brazil, that means we're getting good results. That's code for we're getting good results. It's good.

Jason Gammel - Macquarie Research

Yes, anything on the water cuts?

Frank J. Chapman

No, we won't comment on that because we're busy with a whole series of gas injectivity, water injectivity. It's too early to tell. But the one thing I'm very, very pleased to say, and this was clear from the extended well test, is the production indices are incredible, right? And the interconnectedness of the reservoir is incredible. So if you go away some kilometers and observe what's happening over there, you see exactly what's happening at well bore kilometers away. It's like it's all one big tank. Okay, very good.

Operator

Since there are no further questions. I'll hand the call back for closing comments.

Frank J. Chapman

Well, thank you very much indeed for all of your questions. If I may, just to wrap up, I'd like to summarize our main points from today. The results for the quarter and for the half year have shown continued strong cash generation. Our LNG profits for the full year are expected to be at the upper end of the $2.6 billion to $2.8 billion guidance range. We've continued to make material progress with the delivery of our key projects in Australia and Brazil and indeed, elsewhere. We've delivered further exploration success, and our funding and capital release programs continue to progress. So thank you, once again, for taking part in the conference call today and for your questions. And I'd like to remind you that we'll be announcing our third quarter results on the 1st of November. So thank you, and goodbye for now.

Operator

This concludes our call. Thank you for attending. Participants, you may disconnect your lines.

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