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Executives

Bruce L. Connery - Head of Investor Relations

Andrew F. J. Gould - Interim Executive Chairman, Chairman of Chairmans Committee, Chairman of Finance Committee and Chairman of Nominations Committee

Simon Jonathan Lowth - Chief Financial Officer, Executive Director, Member of Finance Committee and Member of Chairmans Committee

Sami Iskander - Chief Operating Officer, Executive Vice President, Managing Director of Africa, Central & South Asia and Member of Investment Committee

Analysts

Brendan Warn - BMO Capital Markets Canada

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

Martijn Rats - Morgan Stanley, Research Division

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

Irene Himona - Societe Generale Cross Asset Research

Michael J. Alsford - Citigroup Inc, Research Division

Jon Rigby - UBS Investment Bank, Research Division

Lydia Rainforth - Barclays Capital, Research Division

Frederick Lucas - JP Morgan Chase & Co, Research Division

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

Lucas Herrmann - Deutsche Bank AG, Research Division

Peter Hutton - RBC Capital Markets, LLC, Research Division

BG Group (OTCQX:BRGYY) Q2 2014 Earnings Call July 31, 2014 7:00 AM ET

Operator

Hello, and welcome to the BG Group Q2 Results Conference Call. [Operator Instructions] I will now hand over to our host, Bruce Connery, Head of Investor Relations of BG Group.

Bruce L. Connery

Good afternoon, ladies and gentlemen, and welcome to BG Group's Second Quarter Results Conference Call. Our interim Executive Chairman, Andrew Gould; and our Chief Financial Officer, Simon Lowth, will take you through the quarter's key business and financial highlights. They will then answer your questions, together with our Chief Operating Officer, Sami Iskander.

During the call, we'll focus on our business performance results as highlighted in our results statement. We will also be making various forward-looking statements. Factors that could cause actual results to differ materially from the results we currently expect are set out in detail in the principal risks and uncertainties section of our 2013 Annual Report and Accounts, and also in our Results Statement published this morning.

I will now hand over to Andrew.

Andrew F. J. Gould

Good afternoon, ladies and gentlemen. You will have seen our statement by now, and Simon will take you through the key financial data shortly. Before I run through the quarter's highlights, I would like to say a few words about the recruitment of our new Chief Executive. As you know, we're in the process of selecting a new Chief Executive and I'm pleased with the progress we've made so far. While it's inappropriate for me to comment further, I have been impressed by the quality and depth of candidates. I look forward to making announcements through the appropriate channels in due course, and returning to my nonexecutive role.

During this quarter we made good progress for the development of our growth projects. In Brazil, production from our Santos Basin interest continues to grow, with a connection of additional wells and flow rates exceeding expectations. The first FPSO at Sapinhoá is now producing around it's gross capacity of 120,000 barrels of oil per day, and this has been achieved with only 4 wells. Progress is also being made at Lula North East, the second and third permanent wells have been connected, and we expect the FPSO to be reducing the capacity around year end. Progress on the next 2 FPSOs continues with both around about 95% complete. The operator expects production from Sapinhoá North and Iracema South to come onstream in the third and fourth quarters respectively.

Turning to QCLNG, we've made good progress during the second quarter, meeting our key milestones within commissioning the gas turbine generators. We remain on track the first LNG by the end of the year, noting the current risk of industrial action on Curtis Island as a potential to impact our schedule. In Egypt, continued core reservoir performance in the high level of gas diversion through domestic market, led to a reduction in volumes to 57,000 barrels of oil equivalent per day, which is 52% less than Q2 2013 and 14% less than Q1 this year. The first one in phase 9a has recently started up. However, even with all 9 wells onstream, this will only temporarily offset reservoir decline. Although one energy cargo was lifted in the second quarter, the likelihood of BG Group receiving additional cargoes is very limited for the foreseeable future. As a result, the group expects the earning contribution from Egypt to continue to decline over time.

Let's turn to exploration. This quarter, we continue to expand our presence in the Caribbean region, securing frontier acreage offshore Aruba. We also farmed into 2 blocks offshore Trinidad and Tobago, further expanding our presence in country. In Tanzania, we continued our appraisal activity during the Tertiary well in Block 1, marking our 10th gas discovery in the country. Meanwhile, work continues with the Tanzanian government on selecting a site for a potential onshore LNG export facility. In the quarter, we also made progress on the delivery of our active portfolio management plan, completing the sale of our interest in the CATS infrastructure in the U.K. for up to $961 million. As you know, the group is reviewing our operational investment and portfolio activities in order to deliver value to shareholders, and I look forward to updating you on further developments in due course.

I'll now hand over to Simon, who will review our financial results.

Simon Jonathan Lowth

Andrew, thanks very much, and good morning, and good afternoon to all of you on the call. Unless otherwise indicated, all of my comments are going to relate to the second quarter rather than for the half year. We've delivered a good set of results, with E&P benefiting from the growing proportion of oil in our portfolio and LNG performance reflecting additional cargo deliveries and favorable realized prices. Guidance for the full year E&P production volumes and for LNG operating profit remains unchanged.

Business performance total operating profit was up 11% to $2 billion, driven mainly by LNG Shipping & Marketing operating profit, which was up 44%. Free cash flow improved by 16%, mainly as a result of lower capital investment, principally in Australia, reflecting our lower equity share in the project and the completion of the majority of the pipeline in 2013. Business performance earnings per share were 22% higher at $0.355, resulting from the improvement in total operating profit, coupled with a lower tax charge, this reflects an expected 1% reduction in the full year effective tax rate to 40%.

Total earnings per share was 64% higher at $0.401, and this included a net gain of $170 million arising from the sale and leaseback 6 of our LNG vessels.

I will now turn to the segment-specific highlights. Total E&P production reduced by 10% to 591,000 barrels of oil equivalent a day. The contribution from our base assets fell by 17% to 493,000 barrels of oil equivalent a day, driven primarily by declines in Egypt and the U.S., together with a higher number of shutdown days in Trinidad and Tobago and in Tunisia. These reductions were only partially offset by the ramp-up of production from new developments, including Brazil, Bolivia and the U.K., although the performance from Jasmine has been lower-than-expected.

Production in the quarter benefited from the deferral of shutdown activity in the U.K. to later in the year. Group volumes for the remainder of the year now expected to be slightly below the second quarter, with full year production remaining at the lower end of the guidance range of 590,000 to 630,000 barrels of oil equivalent per day.

Upstream operating profit fell by 2% to $1.2 billion. E&P revenues benefited from a combination of higher realized oil prices, together with the higher proportion of oil in the portfolio. However, the increase in revenue was almost entirely offset by increased E&P costs. Liquefaction profits were 37% lower, reflecting the reduced throughput at Egyptian LNG. E&P costs increased by $320 million, and royalties and other OpEx rose by $120 million, mainly as a result of the increased production from royalty-paying fields and higher oil prices, whilst other E&P costs increased by $247 million, including the impact of higher oil shipping costs and the timing of liftings in Brazil.

The DD&A charge was $76 million lower as a result of lower volumes, reserves maturation in Brazil and lower charges in Egypt and the U.S.A., following the impairments recognized in the fourth quarter of 2013. This was only partially offset by the higher cost of new developments in the U.K.

Our full year unit cost guidance remains unchanged. The group expects high unit costs for the second half of the year. Unit OpEx is expected to increase, reflecting the cost of the U.K. shutdown program and the impact of new assets coming onstream for which the fixed costs will not be fully leveraged in this ramp-up phase. Unit DD&A will also increase, as new assets come onstream and start contributing to the DD&A charge, most notably QCLNG in our Egypt phase 9a. From a margin perspective, the increase in unit costs in the second quarter has been more than offset by the improved revenue mix. Our average unit revenue increased by around $11.20 per barrel, resulting in improvements of $2.29 in our EBITDA margin and $2.45 in our EBIT margin. Operating profit in the LNG Shipping & Marketing business improved by 44% to $749 million. This resulted from a 29% increase in delivered volumes, together with favorable pricing in Asia and in South America. Overall, we delivered 11 more cargoes with 9 spot cargo purchases, more than offsetting the reduction in supply from Egypt. Despite these high-realized prices, average cargo margins were lower, reflecting the cost of the spot cargo purchases.

The strong LNG performance in the first half of the year is not expected to continue into the second half of 2014, with lower near-term global LNG prices and an adverse change in the group's supply and sale mix, including low delivered volumes. Consequently, our full year LNG Shipping & Marketing total operating profit is expected to remain within our guidance range of $2.1 billion to $2.4 billion. As we've mentioned before, in 2015, the group expects materially lower cargoes from Equatorial Guinea, given the operator's plan to gas development program. Combined with the suppliers used from Egypt, there will be fewer portfolio cargoes available.

The group's net finance cost was $10 million and included foreign exchange gains of $34 million. Going forward, an increasing proportion of our cash interest payments associated with corporate debt will be expensed as assets are brought into production particularly following the startup of QCLNG. At the end of the quarter, net debt was $10.4 billion; gearing has reduced to 23% following the sale of the 6 LNG ships. As Andrew stated, the group completed the sale of its interest in the CATS infrastructure assets earlier this month and this transaction will realize a post-tax profit on disposal of around $700 million, which will be reported in our third quarter results. In line with our established policy, the board has approved an interim dividend of $0.1438 per share, which is half of the 2013 total dividend. The dividend will be paid on the 12th of September in sterling, which amounts to GBP 0.847 per share.

And we now like to open the call up for questions. Over to you, operator.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Brendan of BMO Capital Markets.

Brendan Warn - BMO Capital Markets Canada

It's Brendan Warn from Bank of Montréal. Just 2 questions in and around Australia, and I sympathize that your contract has to do with the CFMEU, but just firstly what recourses Bechtel have under the, say, fair work commission granted protection action orders, and just what sort of potential time delay do you possibly recognize if there's industrial strike action? And I'll just follow that by saying how much time or in float was allowed for industrial strike action, which is pretty regular in Australia? And just secondly, on the CapEx. I notice your first half, you've been fairly light on Australian LNG spend. But second half looks to be per quarter [ph] you have to get to about $1.9 billion per quarter to achieve the -- the $21.4 billion budget. Just going into 2015, what sort of, call it, CapEx per quarter run rate do you expect post the $20.4 billion 2011 to 2014 number that you've been providing us, please?

Andrew F. J. Gould

Sami, would you answer the questions on the PLA and then ask Simon to do the CapEx part?

Sami Iskander

Yes, thank you for that. As you know, there are 4 unions involved. You referred to the CFMEU, that's one, there are 3 other unions involved in this, and all have -- legally they could go on strike. What's Bechtel has done, and have announced in the last few days, is they're calling in a third vote, that third vote will be done around the 12th to the 14th of August with the results on the 15th of August. I'm sure it's not news to you as well that Bechtel have made their best and final offer to the unions and have engaged quite extensively with all the union members, all the workforce explaining the benefits of the current offer. So we expect the third vote or the results of the third vote by the 15th of August. And clearly, if there's any adverse results, i.e., a decision to strike, we will have to assess it then and communicate to you the mitigations. Your second or part of your question was do you -- what sort of float do you have for strike action? We don't have float for strike action. That is not built into the -- into our plans, really. However, there is float in the program, and really float, I mean we have started the commissioning process of Train 1, and we have built the schedule going into the Q4 date we mentioned based on our commissioning schedule that we have had in all 6 trains that we have commissioned before, whether in the 4 in Atlantic and the 2 in LNG. So there is some float in that schedule, but to be clear, it does not account for a long or a sustained strike action. On the -- would you like to get the CapEx?

Simon Jonathan Lowth

Yes, absolutely. I think there were 2 questions on CapEx if I understood you correctly. The first was where do we stand versus the previously disclosed capital budget for the project of $24 billion -- $20.4 billion, and we remain on track with the program against that budget, which will then take us to the completion of the LNG Train 1 and 2 into a next year. The map, we'll obviously update you as we normally do with our CapEx plans at the beginning of each year. I think we previously guided that sort of beyond the completion of the LNG plant, we could be seeing continuing capital in the $1 billion to $1.5 billion sort of range. But will obviously give you some further details on that at the beginning of '15. I hope that helps you, Brendan.

Operator

Our next question comes from Oswald Clint of Sanford Bernstein.

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

Yes, another question on Australia actually. I'm curious whether the Ruby Jo area or development area is sufficient in terms of wells and volumes to fill up and start the first train of the QCLNG project or whether you need volumes coming from the central part of the Surat Basin as well? And second question was, really related to the kind of risk section, talking about concentration risk in the portfolio. The risks to the supply-side Australia and Brazil and the demand side China as you look forward. Could you maybe talk about that and what plans you may have to kind of mitigate against that and in terms of the future?

Andrew F. J. Gould

Sami?

Sami Iskander

So addressing the Ruby Jo and the central area, I mean really the supply for Train 1 essentially is the supply from the central area and Ruby Jo. So the central area has been on production for some time and Ruby Jo as you know we have commissioned and started up both the CPP and the 6 FCSs associated with it. Probably your question was more around the Bellevue, I would guess, which is the another CPP we have in central. And I'm happy to say that Bellevue is mechanically complete and will be started up probably in Q3, sometime in Q3, together with the 3 FCSs. But fundamentally Train 1 is Ruby Jo and the original CPPs we had in the central area. On your second question, I'm not 100%...

Andrew F. J. Gould

So you are essentially describing the 3 large elements in the risk profile of BG as you perceive it. I would say that on the supply side, we are very comfortable with Australia, certainly through the first period of production, and we still have a long way to go before we start -- we need to start worrying about the second phase. On Brazil, we don't perceive an execution risk. We have certain risks around the future as some of the actions that may be taken in the government, but they are not in anyway crystallized at this point in time, and I think it will be way too early for us to start looking at mitigation beyond what we've said in the past. And on the China side, you're talking about a macro risk that really -- we don't have any particular control over. Obviously, we will be looking at the evolution of macro scenarios and function of our price deck and should that request -- require us to moderate what we're doing in the future, we will obviously go there, but I don't think we can be specific on the risks beyond that at this point in time. You want to add anything, Simon?

Simon Jonathan Lowth

No. I mean, I think, clearly on the demand side China is a very important driver both at the macro fundamentals and indeed it's an important customer of BG that we have a well-diversified portfolio of customers within the LNG business. We're building that in the oil business. So I think it's a macro risk for many sectors and one that we've already, I think, recognized and building mitigation into.

Operator

Our next question comes from Martijn of Morgan Stanley.

Martijn Rats - Morgan Stanley, Research Division

It's Martijn Rats of Morgan Stanley. I wanted to ask you 2 questions. The first is related to LNG, where all of a sudden there were 9 spot cargoes that you managed to trade during the quarter. And it's such a large number. I was wondering if you could make some comments about that where that was coming from and why also this opportunity wouldn't be there again in the second half of the LNG market? In general it's a little less tight than it was a while ago, why would that not be replicated in the second half allowing you to, sort of, to beat the guidance? And the second question I wanted to ask related to an earlier comment that was made on the BP conference call, where Mr. Dudley said in Egypt we're looking for possibilities to work with BG, developing a few projects that could feed into their facilities. I was wondering if you had any sort of thought about that?

Andrew F. J. Gould

Do you want to comment on the cargoes, Simon?

Simon Jonathan Lowth

Yes. I mean, I think, that both the purchase of spot cargoes and indeed the sale of spot cargoes has been an important part as our portfolio management optimization activities within the LNG business. We see a reasonably high number of spot cargoes, both in the first half of this year and indeed in the second quarter. We took advantage of market opportunities and specific availability that we saw. Clearly, if there are similar opportunities, we look to exploit those. But do bear in mind that if you're buying on spot, selling on spot, the margin on the middle isn't great. So I think we'll remain sort of attentive to those options, but that is not going to be a big driver of profile into the second half.

Andrew F. J. Gould

So to complement BP's comment, I would say that should business conditions improve in Egypt to the point where we are prepared to invest, which I would remind you is not the case today, there are obvious advantages to both BG and BP in sharing infrastructure in certain developments. We would obviously be really pleased to continue discussing those with BP.

Operator

Our next question comes from Theepan of Nomura.

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

Three questions please. Firstly, Andrew, I think you talked about in April just a more assertive review of the options for the BG portfolio. So could you just talk about how comprehensive that review may have been, and are you in a position therefore to execute a more rapid pace in the second half of this year into 2015? Secondly, just a follow-up on LNG, I just wanted to get a sense of what you are seeing in terms of the supply and demand dynamics in Asia. Are you surprised that the degree to which spot prices have fallen, and in that context, would you perhaps look to hedge profits next year? And then, a third and hopefully more straightforward question, just on the U.K. maintenance, why the deferral there?

Andrew F. J. Gould

So let's take it in the reverse order. Sami, why don't you do the U.K. maintenance; I'll do the LNG pricing; Simon and I'll talk about their portfolio review.

Sami Iskander

Yes, quite simply, the U.K. maintenance, I mean we're doing extensive maintenance, vessel inspection, pipe inspection, regulatory inspection on both at the Everest and Lomond platforms. And really the -- that schedule is attached to the availability of the flotels, the 2 flotels, that we need to bring alongside each of the platforms in order to have the necessary number of people and subcontractors, in order to execute this work in timely fashion. So it's not -- there's no other driver other than the being able to execute this program, to be able to execute the asset integrity program and have the right resources available. And for that we need the 2 vessels that are currently being -- actually that are currently utilized on one with Shell and one with ConocoPhillips. And they are going to arrive to us in early October of this year.

Simon Jonathan Lowth

On LNG spot prices, yes, obviously, we have seen a weakening of prices through the year. And that's on the back of actually a shortage of cargoes in the first quarter, which push prices up. So there's been quite a marked movement in spot prices. We see that as a function of lower demand, particularly in Asia, partly over the sort of macro and partly, I think, a spillover from milder conditions over the winter and also continued strong supply side. So that has weakened prices. Going back to the earlier question, Theepan, we're capable of taking advantage of those, where there are good opportunities. Looking forward into 2015, we don't have plans for hedging the commodity position. As you know that's not our core policy. We took some action this year very specifically to manage our cash flow volatility. We don't have current plans for 2015.

Andrew F. J. Gould

So on the portfolio review I would say that we're now in a position where there's a good understanding between management and the board as to which assets we might consider disposing off. I would say that there was nothing that was not under review. As you remember, I said in the first quarter that the whole portfolio was up for review. I also said in the first quarter that this is a seller's market at the moment, and it will be extremely difficult to imagine that all the transactions that we envisage would go rapidly. And therefore, I don't think it would be wise to comment or assume on what we might or might not achieve in the second half of this year. What I will say is that we're actively pursuing the options that the board has approved.

Operator

Our next question comes from Irene of Societe Generale.

Irene Himona - Societe Generale Cross Asset Research

It's Irene Himona of Societe Generale. And I had 3 questions, please. Firstly, you commented briefly on the CEO recruitment process. You're making progress, you're a few months down the line. What would be a reasonable timeframe in your view for the potential announcement? Secondly, a question on other E&P costs, if you could just remind us please of your expectations on that, in particular with a reference to the cost of the third-party gas contracts you signed in Australia? And then finally in Egypt, if you could just remind us of where we stand with receivables, and whether there is any progress. I mean recently, they were quoted as stating that they're keen to start repaying foreign operators, they're keen to abolish domestic subsidies to save some money. So I wonder if you can comment on that, please?

Andrew F. J. Gould

Okay, there's one question for each of us. I'll take the CEO recruitment, other E&P costs. Simon and Sami, would you like to comment on the Egyptian receivables? So on the CEO recruitment, as we've said there is an external search in process. It would be inappropriate and rash of me to comment on the exact timing of it. So all I will say is the search is in process. Simon?

Simon Jonathan Lowth

Yes, no, on other E&P costs, you have seen an increase through the quarter, but also for the half year. You may recall, we guided to this and threw it out at the beginning of this year. Other E&P costs will include both as we disclosed this quarter, the impact of the costs of oil shipping from Brazil, and secondly, while this hasn't impacted the number significantly in this half, it will do as Australia starts to ramp-up. That is where we'll account for the third-party gas. We haven't given explicit guidance on the future other E&P costs, and I don't intend to do so at this stage. But what we have done obviously is give some indication to the sort of level that third-party gas that we'll be drawing on through the ramp-up phase, which is up to I think 20% in the ramp-up phase. And exactly how that flows through on a quarter-by-quarter will depend upon the operational characteristics, which you will expect to see the other E&P costs rise, as Australia comes onstream. Sami?

Sami Iskander

And then lastly on your Egypt question, yes, indeed, there have been quite a few statements by the government, the new government in Egypt at all levels, Minister of Finance, Minister of Petroleum and Prime Minister, around the repayment of outstanding receivables to IOCs in general and BG in particular. As you can imagine, we're on very, very close contact with all of them at every level. Egypt is -- it clearly needs to develop its resources. We have quite a lot of resources to develop. However, as Andrew indicated earlier, we will only move once there is a solution, certainly a solution to the receivables issue, and some of the other issues we have. Lifting of the subsidy, which has been lifted, to a large extent, particularly on the liquid fields, is a very good first step, and maybe will help -- it definitely will help the balance of payments of Egypt BC. But it is a first step and very, very early days. So some progress. Our receivables, by the way you asked where they stand. We're at $1.5 billion. So higher than last time we spoke, but anyway we're working with Egyptians around their ability to raise funds. They are outstanding receivables and therefore unlock potential future investment.

Operator

Our next question comes from Michael Alsford of Citi.

Michael J. Alsford - Citigroup Inc, Research Division

So just got a couple, please if I could. Just to come back to Australia in terms of the ramp up, thanks for some of the comments you made earlier, but could you just talk about the pace at which the ramp-up should come through, both from I guess, we're talking about Train 1 ramp-up, and then subsequently the ramp-up of Train 2, would be my first question. And then secondly, just on your point around selling assets, you mentioned, obviously, it's sellers market for a lot of assets, but I think you also mentioned in the previous call that good assets still get good prices despite being a sellers market, and maybe specifically on Brazil, when I look at I guess what will represent in terms of cash flows by the back end of the decade, it's from 60% of BG cash flow. At what point does that get too big in terms of the portfolio? You mentioned your issues perhaps around the regulations in Brazil that causes you concern. When do they get too big, and then I guess, at what point do you need to sort of maybe look to sell down that asset?

Andrew F. J. Gould

Okay, so Sami would you like to talk about the ramp-up process?

Sami Iskander

So, let me spend some time, I'll talk a little bit about the upstream and a little about the midstream very quickly. Upstream had fantastic process, and this is really adjusting your ramp-up question. We have drilled over 2,000 wells, which is elementary the number of wells that we need -- would need for Train 1 and Train 2, and we've talked. This is put on production more than 1,100 wells, i.e. we have 1,100 wells that are ready to produce waiting for Train 2. We spoke earlier about Ruby Jo and the central area feeding into Train 1. We have Ruby Jo in the central area and Bellevue available for startup of Train 1. So some backup if you wish for mitigation. And Woleebee Creek, which is our northern area, will be available early in the -- early in 2015. So therefore, I mean, what I'm trying to tell you is the Upstream infrastructure, whether its wells gathering, FCSs, CPPs are on track to deliver both Train 1 and Train 2 volumes. On the midstream, there are really 4 simple steps, and I maybe -- I'm over simplifying a little bit, but there are really 4 things you need to be looking at. We have started the commissioning on the gas turbine generators as was said earlier. Next is introducing gas into the plant, into the flare, so lighting up the flare. So gas goes from where the pipeline ends into the plant lighting of the flare. And you do your first fire of the GTGs i.e. you fire them up, get the power and the utilities and the safety systems operational on the plant. This will happen early in the month of August. Following that, you start your compressors, the mechanical runs of your compressors, so this is roughly the period of September. And after that, gas flows into your entire trains. You have to feed gas into your train, you start your defrosting and your refrigeration and cool down period, and therefore, you're making LNG. Now all these 4 steps, I mean, I appreciate it's slightly simplified, these are major complex processes. We are proceeding well at the moment with our commissioning. However, there may be unknown unknowns, technical unknown unknowns and clearly if any event happens in any one of those 4 steps, we would be coming back to the market, whether it impacts our Q4 date or not. So, PLA? So moving onto the PLA and the unions, which is a risk, which is a big risk, as you know, the 4 unions working for Bechtel, and there is the relationship between Bechtel and the subcontractors, have legal recourse to strike action. Bechtel has announced that there will be a third vote on the proposals they have given. They have given their best and final proposals to the unions. There will be a third vote between the 12th and the 14th of August, with results on the 15th of August, announced on the 15th of August, and clearly if there is a decision to go to a strike action, we will evaluate back and if it will impact our Q4 date, and clearly that is a risk, a significant risk, we will come back to you as well.

Andrew F. J. Gould

So on Brazil, we stated very clearly that the whole portfolio was under review, and therefore, you have to assume that was part of the review. I'm not going to comment on any specific likelihood of a transaction on Brazil. I am going to say that Brazil is so big in BG's portfolio, that even a partial sale will not significantly reduce our exposure to Brazil. And we are going to have to learn as a company to live with that. We understand the risks, we understand also the rewards of the potential in Brazil, which as you know absolutely extraordinary, but we cannot undertake an action that will significantly reduce the overexposure of BG to Brazil, even in the event of some of our other development projects coming onstream around about 2020.

Operator

Our next question comes from Jon Rigby of UBS.

Jon Rigby - UBS Investment Bank, Research Division

Two questions. Actually keeping on the theme of Brazil, can you just talk around what you're seeing with -- in the experience of the high production rates that we've got so far? And then particularly, I guess, with the reference to the 2 FPSOs that are coming this second half of the year. What level of wells are predrilled, ready to go, predrilled and completed ready to go and given the production rates that you've seen from the existing producer -- producing assets, do you have any view on ramp-up periods, please? The second question just on your guidance. DD&A particularly, it seems like you're running below the full year guidance, and you did indicate that actually DD&A have fallen because the 2 big Brazilian units, 2 Brazilian units were reaching plateau. So I'm trying to understand a little bit about what the big levers on DD&A could be that would raise the full year rate to the guided range?

Andrew F. J. Gould

Thank you, Jon. So, Sami, would you like to comment on the Brazilian production profile ramp up, and Simon would you take the DD&A?

Sami Iskander

Yes, I think, so starting with FPSO 4 and 5, you probably know the operator has said that the FPSO 4 is towards the end of Q3, FPSO 5 in Q4. We believe that this is probably FPSO 5 will be early in Q4. So this is the rough timing of both and I would -- somewhere in that timeframe. The -- with 30,000, or give or take anywhere between 25,000 and 35,000, barrel per day wells, the ramp up has been quite fast, to be honest and we've seen that on FPSO 2. We have a number of predrilled wells. However, the time taken is really through spent for the connection on these wells. We no longer have the DSR issues that we have in FPSO 2 and 3, so the FPSO 4 and 5 will be rigid lazy wave connections. And you would probably, I would say, you would probably be looking at somewhere in the 4 to 6 weeks production per well, so somewhere in that timeframe for the ramp up of FPSO 4 and 5 per well. And I would venture to say they will be happening reasonably concurrently.

Andrew F. J. Gould

Simon?

Simon Jonathan Lowth

Sure, so on unit DD&A, I'm not sure that I can provide you with much more than I commented on in my remarks earlier. But to sort of reemphasize that, we do anticipate unit DD&A increasing, and we reaffirmed our guidance. And the main driver of this, and it is a significant driver, is the impact of new assets that come onstream and therefore, you commence the depreciation, and that can have quite a marked impact, particularly if there are assets that are relatively short time, rather short production lives. So we've got coming on midstream in the second half of the year, Knaar. As we said today, we've now got Egypt phase 9a just come onstream. So you got from those 2, and then, of course, just coming back to Australia, there is QCLNG comes on the stream, you've got 3 significant assets bringing in new DD&A charge, and in a couple of cases, relatively short lives. So those are the main drivers. And DD&A is very heavily impacted by mix. So there's quite a big difference in DD&A charges across the portfolio, and Egypt can have QCLNG up particularly high in terms of DD&A costs and they all step in, in a very short period of time. So, Jon, I hope that helps you with the question.

Jon Rigby - UBS Investment Bank, Research Division

Simon, while I got you. Just a quick follow-up on the question that was asked earlier, and you did referenced the fact that third-party gas costs will go through other E&P, but I guess that implies that you would be booking, obviously, revenues as well, right? So it's not a straight debit for P&L to get credit higher up?

Simon Jonathan Lowth

Yes, absolutely right, and I mean, I'm glad -- on your question, you're absolutely right. The other E&P costs that runs into that third-party gas is compensated by the sales, it's a very similar comment. Actually I should also reinforce the point I made about unit OpEx costs that we got an increase in this quarter and in the half-year from higher royalty paying fields particularly in Brazil. Of course, that's offset by the revenues and the fact that the royalties go through OpEx rather than paying high corporate tax burden. So you have to look at the costs movement but also the unit price movements. And as you've seen this, in this quarter we saw our margins improving.

Operator

Our next question comes from Lydia Rainforth of Barclays.

Lydia Rainforth - Barclays Capital, Research Division

I have 2 questions, please. The first one is on Jasmine. In the statement, the comments made on the performance is, it isn't developing as you expected. Could you just go through what the issues there are? And then the second one is really for Simon. Simon, you've been there for BG for over 6 months now. I'm just wondering how you're thinking about the organization, and whether there are any key areas for improvement that you've identified, and I'm thinking particularly in that around the cost base?

Andrew F. J. Gould

Jasmine, Sami?

Sami Iskander

Yes. So Jasmine, as you probably know it's an HPHT field operated by ConocoPhillips, of which, we are a 30.5% equity partner. And starting at Jasmine -- started production early, very early this year. What we have seen in terms of reservoir performance has been disappointing and really quite simply the reservoirs are more compartmentalized, i.e., there are barriers around the reservoir i.e., that the hydrocarbons don't flow freely. And what that means is the production that we were expecting which was somewhere in the 30,000 to 35,000 barrels, I'm talking now barrels equivalents, so i.e., gas and oil together, when we sanctioned this project is somewhere in the 20,000 to 25,000 barrels of oil per day. The workaround, which we're doing with the operator in order to maximize the value and what does that -- I mean, that means quite simply is you need more wells to develop the same number of reserves. And that is really the ongoing work we're doing with the operator in order to maximize the value of the Jasmine field.

Andrew F. J. Gould

Simon?

Simon Jonathan Lowth

So thanks, Lydia, for the question, I had, I think reinforced a couple of comments that I made in my very first sort of months or so in the company, where, might there's been a couple of areas that the company's been working on, and I'm -- we continue to -- I think drive improvements and I'm sure there's more to do. The first is in the area of planning and forecasting and continuing to strengthen our understanding of the risk, the range of our outcomes and getting more predicable planning and forecasting into our business. I think we're making good progress. Certainly there's more that we can do. The second, in terms of the cost base, we have recognized that there are steps that we can take to make the companies sort of back -- let me call it, the administrative, the G&A, there is sort of back-office infrastructure in the company, more effective, more efficient. You'll recall at Q1, we announced some restructuring changes, and that was all part of that program, and there will be further initiatives looking at whether we can provide some more activities through shared services around the company. Look at more automation. So yes, there's more work to do there. And the second area on the cost base, I think we've also talked about is in the area of delivery of capital projects and operations and, Sami, I don't know if there's anything further you want to comment on that. It's an area where continued work on upfront project engineering, management of our supply base. I'm sure there's further steps and we continue to remain very focused on that.

Operator

Our next question comes from Fred Lucas with JPM.

Frederick Lucas - JP Morgan Chase & Co, Research Division

Just a few questions. In Australia, if the third vote does lead to industrial action, do you have any contingency plans to enable work to be continued on Curtis Island? And sticking with QCLNG around this question of ramp, can you clarify during the ramp process on Trains 1 and 2, what percentage of your gas is consumed by fuels flaring and venting within the plant? And third, quite a high number coming from Santos on LNG, with 30%, 40%. Is QCLNG going to experience something similar on that?

On Brazil, I appreciate your comments around -- no sacred cows, everything under review. In today's FT, there was an article that seemed to be headlining a C-change in the M&A behavior of the Chinese NOCs. Total, yesterday confirmed, that it's planned sale of Usan in Nigeria have been aborted, for perhaps reasons cited in today's FT article. I'm not sure, but I'm just wondering if that's the case, do you see the ability to maximize the value of your assets in Brazil, potentially compromise, if those Chinese NOCs are not as active buyers as they have been historically?

Andrew F. J. Gould

So, Sami, why don't you do QCLNG first, contingency plans on ramp gas.

Sami Iskander

Yes, so let me start with contingency plans. We've built our schedule leading to the Q4 startup based on what we have done, on the last 6 trains, we have built the Atlantic trains and the Egypt trains. So there is some mitigation, I would say technical mitigation built in. However, there is no mitigation for strike action. And really, I can't talk to you about contingency plans until we know what it means. So who's going to strike, how are they going to strike. So I think I would leave it at that. On ramp gas, this is a really very, very good question. And I'd say that at plateau, so in 2016, I would say the, if you want to call the gas consumption that is not LNG, which I think is the heart of your question, is somewhere in the probably 13%, 14% Upstream. So you can be looking at somewhere in the 4% between the FCSs and CPPs 2%, 2%, you would look at about 2% for the HPUs of the well sites, somewhere there, and in the plant you'd be looking at 6% to 7% with 1% losses. So this is a steady [ph] state at Plateau. In ramp up, and I know it's important to say that today and I've said that earlier, our Upstream is now working through our FCSs and CPPs, so these numbers I think would be reasonably accurate. Where I think there may be differences with others and what you refer to is when you're popping wells and I'll refer to, we've put in wells on production. We have over 1,100 wells, therefore you're flaring at the well sites themselves. So you're not talking about the 2% at the FCS or 2% at the CPP. You're flaring at a well site on its own in order to start dewatering your well and flare your well, and therefore, that number could be significantly higher, and maybe that's the number you may be getting or hearing from others. But in short term, I would say 12% to 14% of the gas produced is taken into both power and HPUs at the well sites and losses between FCS, CPP and fuel gas oil plants.

Frederick Lucas - JP Morgan Chase & Co, Research Division

Sami, can you hear me? Just to clarify, so that [audio gap] is that with reference to steady-state? But my question was what is that percentage during the ramp period or do have I misunderstood you?

Sami Iskander

No, that is correct. That the 12% to 14%, that is steady-state for '16. What I would like -- what I'm trying to say is, I believe, we today, have that steady-state for Train 1 because we are producing through our CPPs. So our FCSs and our CPPs and once Train 1 starts. This is the number that you should expect for Train 1. Obviously, when you start popping the wells for Train 2, i.e. I'm referring to the Woleebee Creek CPP, that number would be higher and I really don't have a number for you there.

Frederick Lucas - JP Morgan Chase & Co, Research Division

And on Brazil?

Andrew F. J. Gould

So on Brazil, I'm not in any way confirming that we are conducting a sale in Brazil, but I would say that we've always known for an asset of the size of Brazil, there will be an extremely limited range of buyers. I don't think that the current position of the Chinese fundamentally changes view, and I'm somewhat surprised that you will compare Usan with Brazil as a quality of asset.

Frederick Lucas - JP Morgan Chase & Co, Research Division

No. I wasn't making the comparison between quality of assets. Just that you may have a common set of buyers and that behavior may be changing.

Andrew F. J. Gould

Yes, but they might not appreciate the assets the same way.

Operator

Our next question comes from Michele of Goldman Sachs.

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

It's Michele. Two, if I may. First, on maintenance, I was wondering if you could quantify how much you expect over your portfolio in the second half of the year versus what you've executed in the first half? And then secondly, on the reduction in the tax rate from 41% to 40%, I was wondering what the key drivers are and whether these are specific to this year or whether they're likely to be ongoing?

Andrew F. J. Gould

So, Sami, would you do maintenance?

Sami Iskander

Yes, I'm not going to answer your question in terms of mmbtu, which might be the question, but just to give you a bit of a flavor, I think if you look at it in a number of days, and I fully appreciate that number of days is not all days are equal really, but the number of days in H2 -- the number of shutdown days in H2 relative to H1 is somewhere in the 80% higher. However, I will point that the type of assets we're shutting down and really it's very much focused on the North Sea as I indicated earlier. But somewhere in that and you should, as a word of caution, not all days are the same, but I hope that gives you an indication of what we're talking about.

Simon Jonathan Lowth

To your question, the change in the tax rate this year are due to a number of specific changes in our tax positions. So resolution-specific issues in a number of different jurisdictions. They relate to 2014, for any implications for subsequent years.

Operator

Our next question comes from Lucas of Deutsche Bank.

Lucas Herrmann - Deutsche Bank AG, Research Division

Three, if I might. The first was just on the LNG business and the outlook for the second half. If I go back to your presentation of September last year on LNG, what was apparent was have your contracted supply broadly, I guess, a short 10 million tons or so looked as though it's put on the short or medium-term contracts. Clearly, I don't know the nature of those contracts, but my presumption would be they're oil-price linked. And the balance was in effect spot much of which clearly isn't available to you any longer, given what's happened to Egypt. So when you comment on pulling forward profits or looking into the profitability of the second half, I appreciate that you've obviously got no real idea as to what the volume opportunity and spot markets may be. But I'm trying to understand why there should be a fundamental change in the base level of profit that one might be anticipating from the contracts that are already on the medium and short-term contracts that are already in place and which should already be firm. And the second question was on Australia and third-party gas relative to own produced gas. I just wonder whether you can give us any indication of the delta in the fully costed price of developing your own gas, relative to the amount that you're actually paying origin in other parties, we guess, which in effect you're producing in large part anyway? And the third question, my understanding is that you've been laying down rigs in Australia around the Upstream over the course of this year, unsurprisingly given the number of wells you've drilled. Can you just confirm that that's correct and I think, that gives me some confidence as to the extent of your confidence in deliverability of your gas per Train -- well, Train 1 at the very least, if not Train 2?

Andrew F. J. Gould

Simon, would you take the LNG and the third-party equity gas ratios? And Sami, would you take the rigs?

Lucas Herrmann - Deutsche Bank AG, Research Division

The ratio is around price, Andrew, they're not on volume.

Andrew F. J. Gould

Understood.

Simon Jonathan Lowth

Lucas, thanks for questions. So on LNG, I mean, the guidance we provided for the full year as we said remains unchanged and represented our view of the overall outcome for the year, taking into account our contracted demand position. What we saw is the outlook for supply, and then there's essentially a range of views as to how the spot market might evolve for us. Clearly, as we went into the year, and we saw the continued challenges in Egypt, we've recognized that we simply we're not going to be seeing cargoes from Egypt. And so, really a minimal uptake from there. We're having against that backdrop, we have had a strong first half, 90 cargoes and up, clearly year-on-year. Pretty similar sales mix, but some higher contract prices and lower hedging losses. If you recall some of it, the hedges we had in prior years rolled off. And so it has been a strong first half. The second half we said won't be as strong. We do see fewer cargoes overall. Egypt, obviously a significant reduction year-on-year, and that's not going to be offset by further developments in QCLNG during the course of this year. And also, obviously, when you lose Egypt, you're then looking to reach out into spot market when average prices are going to be higher. So overall, lower volumes, weaker supply mix leads to a second half not being as strong as the first, and thus maintaining our full year guidance as we said. I think our views on the fundamentals, I should reiterate for LNG, Lucas, remain unchanged. We continue to see the demand globally will remain strong as we move forward, and as ever supply will likely get developed slower than some anticipate. So our overall views on the strength of the LNG market remain unchanged. What we're talking about here are some specific market conditions in 2014 and at least not in a yearly -- half yearly phasing of our business.

Sami Iskander

Just addressing your third-party gas and why it exists and then your rig question. I mean, the third-party gas, the reason we are out in the market for third-party gas is quite simply associated with the nature of coal seam gas, coal-bed methane, ramp ups are slow. So by the time you do the dewatering and you get these wells to produce, it is a slow ramp up. So if you can imagine a square startup of a train and a slow ramp up of many wells, you do have capacity in the train in the earlier startup period, that you can fill. And this is quite opportunistic. We have access to LNG market on one side, and we have a fast train to absorb third party -- absorb gas that may not -- that is not equity gas on the other side, and coupled with that you have the ramp gas in other proponents in Australia, that we are using to fill our train, therefore called third-party gas. I will not comment on the -- what we're buying -- you probably can imagine what we're selling at. I'm not going to comment at what we're buying at. However, suffice to say that these are profitable contracts, and we're taking an opportunistic view of the capacity of the plant due to the nature of coal seam gas.

Lucas Herrmann - Deutsche Bank AG, Research Division

Sami, can you now give me any idea of the materiality or otherwise of the difference between gas you buy in third-party or the fully costed price of gas that you develop on an equity basis yourself?

Sami Iskander

No, I really don't want to go there, I'm sorry. But I think it's important to say that it's -- I think, Simon mentioned that. In the ramp up in the '15, early '16, we're talking about 10% to 20% of the gas, and thereon it's 5% of the gas. So it's quite, I don't want to say it's immaterial, but it's not significant than the life of QCLNG.

Lucas Herrmann - Deutsche Bank AG, Research Division

Okay. And rigs?

Sami Iskander

Oh sorry, rigs, excuse me, apologies. Rigs, yes, indeed we're reducing our drilling activity. I think I spoke earlier about the number of wells already drilled. Our drilling efficiency, not only our drilling efficiency, our drilling efficiency and our ability to install gathering systems between wells and FCS at such a pace that we feel comfortable to put down some rigs and lower the rate at which we're spending drill rigs going forward.

Lucas Herrmann - Deutsche Bank AG, Research Division

Okay. And Simon, if I can just come back for one moment on your LNG observations. The profile that was presented in September last year, LNG, the amount that's contracted out on short and medium terms and is not traded on a spot basis, hasn't changed for 2014 has it? Or has it?

Simon Jonathan Lowth

No, not materially.

Operator

Our next question comes from Peter Hutton of RBC.

Peter Hutton - RBC Capital Markets, LLC, Research Division

Can I just come back again on maintenance? I know you can't quantify it, but just sort of a couple of quick follow-ups. You mentioned that the flotels will be arriving in October. Quarter 4 is not normally the kind you associated with the best time of the year to be doing maintenance in the North Sea, is there precedence for doing this level of maintenance so close to the winter period? And also can you just confirm when you have been expecting to do these maintenance programs in Q2, and when you are aware that they would be deferred? And the second question is on the cash flow and your margin proceeds of free cash flow this quarter. In the first quarter you said you expect it to be below -- even negative free cash flow for the rest of the year, and you've managed to sort of defer that for the second quarter, can you just give us an update on sort of how that's helping in the status of discussions with the rating agencies, and what you perceive to be the level of the tolerance you've talked about before of the breaches on the gearing for example over a defined period?

Andrew F. J. Gould

Sami, would you like to give a brief view on the maintenance? Because I think you've dealt with it already. And Simon would you comment on the credit ratings?

Sami Iskander

Thank you for the question. I mean, the point you make about maintenance in the middle of winter is taken. However, the point I made earlier, the maintenance and the work we'd like to do initially supported by the flotels, and it was really very much governed by, when are these flotels available and our desire not to postpone as integrity work, which is something we have done quite consistently, not to postpone this asset integrity work into the summer of 2015, because we think it's needed to be done. So this is really fundamentally where the availability of those vessels and in their schedule how they were pushed out during 2014 into the latter portion of the year.

Peter Hutton - RBC Capital Markets, LLC, Research Division

Would you confirm that you're dependent on the availability of the vessels from other operators?

Sami Iskander

That is 100% correct.

Peter Hutton - RBC Capital Markets, LLC, Research Division

So you didn't actually make a decision to defer, it was forced on you by circumstances.

Sami Iskander

It is the inevitability of the availability of the vessels from other operators where they're actually working today.

Peter Hutton - RBC Capital Markets, LLC, Research Division

Simon?

Simon Jonathan Lowth

Yes, so we have seen year-on-year improvements in our free cash flow and that sort of reflects both the strength that the cash from operations line, but also CapEx, has been coming a bit lower in the first half of the year as we had guided at the beginning of the year. Although, obviously, on a total basis, we are still reinvesting over 100% of the cash flow. So we're cash negative after investment, albeit an improving position. And, of course, as we said, we expect that to further improve as we move into 2015, where we see further strengthening of cash generation and a lower level of capital investment as we complete the significant phase of activity in Australia. In terms of the agencies you probably have seen that we had our rating confirmed by all 3 agencies, although we are on some negative outlook from all 3, and this reflects the fact that the agencies see the credit metrics being put under pressure, given the scale of the investment in 2014. But they're recognizing the improving profile as we move into '15 and beyond, driven both by the operating performance, the lowering level of CapEx, and indeed steps that we're taking on the divestment program of which you saw for example the proceeds coming in from CATS, that will be arrive in the -- in during the course of this year. So confirmed our ratings, we're on a negative outlook and obviously looking forward to seeing a strengthening of the cash position and financial position as we move forward, and that will be important underpin the rating.

Operator

This concludes the question-and-answer session. I'll hand back to our speakers for the closing comments.

Andrew F. J. Gould

Okay. So thank you, all, very much for your attention. Thank you for your questions. And we look forward to speaking with you again at our third quarter results on October 28, 2014. Good afternoon.

Operator

This now concludes the conference call. Thank you, all, very much for attending. You may now disconnect.

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