BG Group Management Discusses Q3 2012 Results - Earnings Call Transcript

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BG Group (OTCQX:BRGYY) Q3 2012 Earnings Call November 1, 2012 8:00 AM ET

Executives

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

Den Jones - Interim Chief Financial Officer and Financial Controller

Analysts

Rahim Karim - Barclays Capital, Research Division

Jon Rigby - UBS Investment Bank, Research Division

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

Jason Gammel - Macquarie Research

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

Martijn Rats - Morgan Stanley, Research Division

Michael J. Alsford - Citigroup Inc, Research Division

Hootan Yazhari - BofA Merrill Lynch, Research Division

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

Thomas Yoichi Adolff - Crédit Suisse AG, Research Division

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

Jason Kenney - Grupo Santander, Research Division

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

Unknown Executive

Good afternoon. Earlier today, we announced that we have signed the Heads of Agreement to sell part of the QCLNG project to CNOOC. We have also brought forward our third quarter results.

During the course of this conference call, our Chief Executive, Sir Frank Chapman; and Interim Chief Financial Officer, Den Jones, will take you through our Q3 results, progress on key growth projects, funding plans and an update on exploration.

We will be making various forward-looking statements. Factors that could cause 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.

But first, to Frank and Den for an update on our third quarter results. Thank you, and over to Frank.

Frank Joseph Chapman

Good afternoon, ladies and gentlemen.

First, I'll take a look at the key points from our Q3 announcement before I hand over to Den for a closer look at the financials.

Earnings in the third quarter increased 16% to $1.2 billion, driven by improved Exploration and Production income and the continued robust performance of the LNG business. For the group as a whole, total operating profit was up 17% at $2.3 billion.

In Q3, production rose by some 5% as new projects came on stream. This progress was held back by the previously announced shutdown of the non-operated Elgin/Franklin field and our earlier decision to scale back drilling in the USA due to low natural gas prices. As a result of these factors and the previously announced deferral of the Jasmine start-up to 2013, production growth in 2012 is now forecast to be some 3%.

Alongside these factors, which will continue to affect production in 2013, we have adjusted our 2013 plans to accommodate an extended subsea tie-in schedule for Brazil's Sapinhoá and Lula Northeast wells and to reflect lower production in Egypt where the Phase 7 compression project has been less effective than expected in arresting reservoir decline. As a result of these factors, 2013 production is expected to be in line with 2012. This revised outlook for 2013 reflects predominantly production deferrals. Elgin/Franklin will be progressively returned to production in 2013 and Jasmine will enter service in the second half of the year.

At Sapinhoá and Lula Northeast, an extended tie-in period is being allowed for each wellhead following detailed execution planning. This extended tie-in is associated with the use, for the first time, of a semirigid riser subsea architecture, which is expected only to be used on the 2 FPSOs to be installed in 2013.

The decision to scale back the U.S. rig count was driven by capital expenditure rationing considerations in the light of falling U.S. gas prices. Meanwhile, the group continues to develop its U.S. LNG export opportunities, which benefit from the effects of low U.S. gas prices.

And in Egypt, to address the reservoir decline, a program of workovers and further development phases is being assessed. In addition, near-field exploration to mature resources for plateau extension already forms part of our 2012 work program.

Clearly, this production use is disappointing. However, beyond 2013, the group's production plans, including Brazil and Australia, are unchanged, and I will, in a moment, summarize progress in these areas.

In 2013, as well as Elgin/Franklin and Jasmine, we will bring onstream further phases of Bongkot in Thailand and Margarita in Bolivia, and as I mentioned, the next 2 FPSOs in Brazil.

In 2014, we will see Knarr in Norway and Starfish in Trinidad, 2 more FPSOs in Brazil and of course, the start-up of QCLNG in Australia.

During 2015 and '16, we'll bring onstream no less than 6 further FPSOs in Brazil.

Our projects in Brazil and Australia are particularly important to the group's growth. They will each deliver unit earnings substantially higher than the current group average, which, alongside the growing contribution from our expanding LNG business, will result in group earnings growing considerably faster than upstream production.

Turning now to the exploration, appraisal and development activities in Brazil's Santos Basin.

In Brazil, the drilling momentum continues, with up to 11 drilling rigs operating now simultaneously. Drilling costs, which account for some 50% of project CapEx, have continued to fall as average drilling duration this year have fallen to 75 days, with the best well taking just 43 days. The prospect of continued drilling cost reductions in the future is highlighted by the best composite well duration of just 34 days.

Additionally, contracts are in place for 90% of the next 4 leased and 8 locally purchased FPSOs, and costs are tracking on or under budget. Falling drilling durations and the confirmation of costs for FPSOs and other capital scope reconfirms the development's very low unit costs.

The next 4 FPSOs are well on track to meet the planned onstream dates over the next 2 years. The FPSOs coming on stream next year will more than triple gross production capacity from around 130,000 to 430,000 BOE per day, and production will ramp up as wells are connected until plateau is reached in 2014 and '15.

In this quarter, too, we have received independent certification from Miller and Lents of the reserves and resources in the Santos Basin, confirming a mean of 6 billion BOE and an upside case of 8 billion BOE net to BG Group.

Turning now to Australia. We continued to make good progress with our Queensland Curtis LNG project, keeping it on track for first LNG in 2014.

The group now has contracts and other agreements in place for more than 90% of the project scope to 2014, reconfirming BG Group's $20.4 billion capital budget.

In the upstream, the pace of drilling ramped up with 135 wells in the quarter and a record 51 wells in August. This brings the total number of wells drilled to more than 1,000. In September, the group added its 8th rig and expects to be operating 11 drilling rigs by the year end. In addition, compressors at the Argyle field compression station are undergoing final commissioning.

Construction of the pipeline infrastructure continues with the gas collection header system and more than 50% of the gas export pipeline now welded. On Curtis Island, the construction of the LNG plant continues on track, with the first prefabricated modules from Thailand being installed.

Let me now turn to exploration.

Offshore Tanzania, the Papa-1 discovery produced our sixth consecutive success, and we currently estimate gross recoverable resources discovered to date to be near 10 tcf with extensive further potential to be explored.

The drillship, Deepsea-Metro 1, has now commenced the third phase of the drilling campaign, which will consist of 4 wells, with the initial focus on appraisal of the Jodari area in Block 1.

Elsewhere, exploration of other high potential prospects continued in Brazil and Egypt.

In Kenya, seismic activity identified significant prospectivity in multiple gas- and oil-prone plays, and future opportunities were added to our portfolio offshore Uruguay and India.

In Australia, exploration activity is ongoing, with stimulation and production testing of 3 of the Bowen Basin tight gas sands wells, each of which has intersected gas-bearing sections. Testing of coal seam gas discoveries in the Bowen Basin is also continuing, and the results of both programs to date have been very encouraging.

Finally, let me look at the -- our agreement with CNOOC.

We have today announced that we have agreed to sell certain interests in the QCLNG project in Australia for $1.93 billion. These interests comprise an equity stake in Train 1 and certain upstream tenements. Specifically excluded from the transaction are the transmission pipeline and the LNG plant common facilities where we are spending some 30% of the $20.4 billion CapEx.

In addition, BG Group has agreed to supply CNOOC with 5 million tonnes per annum of LNG for 20 years beginning in 2015 sourced from the group's global LNG portfolio, making the group the largest supplier of LNG to the world's fastest-growing energy market.

Fully termed transaction agreements are expected to be executed in the first half of 2013, and upon closing, CNOOC will reimburse BG Group for its share of QCLNG project capital expenditure incurred from the 1st of January 2012.

QTC will remain operator and retain majority ownership of the QCLNG project.

Let me now hand over to Den for a brief look at the financials.

Den Jones

Thank you, Frank, and good afternoon, ladies and gentlemen.

Let me begin with a summary of the advances we have made with portfolio rationalization and capital release. Here, we've made very good progress, having now completed or reached asset sales agreements that will release a total of some $7.6 billion of capital by mid-2013, with a material benefit to the group's balance sheet. Assets sales include interest in Quintero LNG in Chile, Comgás in Brazil, Gujarat Gas in India and as mentioned, certain interests in QCLNG.

Turning now to third quarter financials. I'll start with E&P segment. Unless otherwise indicated, all of my comments relate to the third quarter rather than the year-to-date.

Revenues increased by 14% to $2.9 billion, reflecting a 5% increase in production volumes, higher realized gas prices and improved production mix.

Total E&P operating profit of $1.3 billion was 13% higher as a result of increase in revenues and lower exploration charge, partly offset by high unit operating costs and depreciation, primarily arising from changes in the production mix. As a result of changes in the production mix, lower-than-expected volumes and higher commodity prices, we now expect unit operating costs to be between $10.10 and $10.30 for the full year.

In our LNG segment, total operating profit was up from 24% to $767 million. Once again, we benefited from strong demand from Japan where cargo deliveries increased from 13 to 20 this quarter. These results were in line with our expectations, and we therefore continue to 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.

The group's capital investment on a cash basis of $2.8 billion in the quarter was focused on our projects in Australia, Brazil and the U.K. and brings the total invested in the year-to-date to some $7.7 billion.

Cash generated by operations year-to-date increased by 19% to $8.5 billion, reflecting the strong business performance and the reversal of prior period margin calls on the group's hedged LNG contracts. We ended the quarter with cash of $4.6 billion and net debt of $11 billion.

The average maturity of the group's gross borrowings remains at around 17% and the gearing ratio was 25.3%.

Now let me hand back to Frank.

Frank Joseph Chapman

Yes, thank you, Den.

Let me summarize our key points today: a strong set of third quarter financial results across the business; full year 2012 E&P production growth now forecast at some 3%, with 2013 production expected to be in line with 2012; we have completed or reached agreements which, in aggregate, should release around $7.6 billion of capital by mid-2013; we have continued good cost and overall schedule performance on key growth projects in QCLNG and Brazil; and we have delivered further exploration progress and success.

So Den and I will now be happy to take your questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Rahim Karim from Barclays.

Rahim Karim - Barclays Capital, Research Division

A couple of questions, if I may. The first was just to try and understand perhaps the timing around all of today's announcements. I know it's come as a bit of a surprise to us in the market, so perhaps you could help us understand why this is all coming out a day ahead of our expectations. Another question then, just moving on perhaps to longer-term targets. I know the 2015 target obviously included a contribution from Australia. I was just wondering how we should expect that to change following the divestment. And then associated with that, what we should expect in terms of CapEx and the evolution of CapEx following the sale to CNOOC?

Frank Joseph Chapman

Yes, regarding the timing, we have completed this year somewhat earlier than normal our business plan for next year, and we have accelerated the completion of that in the recent days, and that has coincided with the completion, the signing today of the CNOOC agreement to sell down part of our interest in QCLNG. And therefore, we have accelerated by one day the disclosure on our Q3 results, and at the same time, announced the CNOOC agreement. So that's a little bit on timing. 2015 contribution from Australia, effectively, BG will retain a 74% of the interest in Australia, so that's 20% down from the current equity level. And therefore, as we consider our plans going forward, we will need to adjust for this change in the portfolio in terms of production in 2015. In terms of CapEx, the CNOOC will become responsible for its share of CapEx. It has now a 40 -- an additional 40% equity in Train 1, and it has this 20% interest in the upstream -- in certain upstream tenements, and it will carry its full share of the capital expenditure going forward -- actually, going forward from the date of completion, which is expected in the middle of 2013. But they will also reimburse on completion all of the capital that's been accrued from the 1st of January 2012, up to the expected completion date in the middle of 2013. And that, both the $1.98 billion consideration, as well as the reimbursement of already expended capital, are included within the $7.6 billion of total capital release that we indicated or Den indicated in his remarks. So I think the only other thing that I should just emphasize with the CNOOC deal is that this is a sale -- a part sale, if you like, of QCLNG assets insofar as CNOOC is not participating in the pipeline or Train 2, or any of the QCLNG -- of the LNG plant common facilities. And those components of the -- just to give you some idea, those components of the project actually absorb around about 30% of the $20.4 billion of CapEx. So that's -- I think I got all your questions.

Rahim Karim - Barclays Capital, Research Division

Sure. If I could just have a follow-up in terms of the timing. You mentioned a review of the business plan. I mean, obviously, you gave guidance around year-end exit rates of 720. I was just wondering how the evolution has changed over the last 3 months in terms of the outlook for 2012 and into 2013?

Frank Joseph Chapman

Well, I think, with regards to 720 year-end exit rate, we had assumed, and if you think back to Q3, as we stated -- Q2 rather, as we stated in Q2, we had assumed that we'd be able to partially offset the effects of the Elgin/Franklin shutdown and the deferred start-up of Jasmine by improved production efficiency elsewhere in the portfolio, notably from the U.K. And we also, in our plan, assumed the full effectiveness of the Egypt Phase 7 compression in erecting production decline in Egypt. So now with the year end in sight, we are now providing direct guidance on the expected annual production which we believe will be 3% up on 2011.

Operator

Our next question comes from the line of Jon Rigby from UBS.

Jon Rigby - UBS Investment Bank, Research Division

Two questions. The first is sort of process. This isn't the first time we've had a rather surprising change of guidance, and I just wondered whether you're comfortable or confident with the process, the planning process and the communication process within BG, both internally and externally, and whether there's an issue here of bad news not flowing up in a time-appropriate manner and whether you could go through that and whether there's any plans to sort of rectify that going forward so we have some better confidence over, with future guidance? The second is just on the mathematics of it. I mean, you're guiding to flat production year-over-year, 2013 over 2012, but then go through a whole host of production adds. I take the point that some of them are slower and some of them are delayed. But if we take your underlying declining rate of low-single-digit percentages of, say, 3, it doesn't seem right that those new production adds will only just balance that maybe 20,000 to 30,000 barrel a day decline that we can expect in 2013. So can you just go through that in a little bit more detail if that's possible?

Frank Joseph Chapman

Yes, I mean, that's essentially what we've got here are 2 effects, which are offsetting the somewhat later coming on stream in 2013 of various projects. And those 2 effects are, firstly, the decision to turn down the drilling intensity in Lower 48. So we've gone down there now to 6 rigs from more than 20, and that will result next year in a decline and this was something that we obviously announced earlier this year. And the second factor is the decline, the unexpected decline in Egypt due to the ineffectiveness or lower effectiveness than we had anticipated from the Phase 7 compression in Egypt. Now these 2 factors, largely, plus some decline, as you mentioned, averaged 3.9% over the period out to 2020 in other assets. If you add those 3 things together, they offset the growth from new projects, which are coming on stream in 2013, somewhat later than we had planned. And the new news there is really the extended tie-in program for the Sapinhoá and Lula Northeast wells, which are using this special subsea architecture for the first time. They will be the only FPSOs that use this architecture and therefore, the experience gained with the extended well test and the FPSO 1, the pilot, is not relevant to the planning and execution of the next 2 FPSOs. And that effect has flowed from the detailed execution planning where we have allowed for an average now of 3 months per well to tie in that architecture to the wellheads. So that's the answer to the decline question or the 2012 balance, if you like. The question about changing guidance, I mean, essentially, I think one can split this into 2 groups of things. What is happening with existing production from base assets. And there, I would say, the production efficiencies across the board, if I take somewhere even like Egypt where we are seeing just recently these decline issues, production efficiencies there are significantly over 90%, Karachaganak over 90%, down in Bolivia, Margarita, La Vertiente, these assets are producing at very high levels of production efficiency. The area where we are experiencing and have continued to experience difficulties is in the North Sea, and there, we are investing significant sums of money on our Armada, on Everest and on Lomond to improve the production efficiency going forward, based upon the fact that certainly Armada, and we anticipate also Lomond, will be key hubs for production, North Sea production in the future. So we need to make some more investments there. With respect to new projects, the only new news today, actually, from new projects is with respect to this tie-in allowance for this particular type of subsea architecture that we're using on Sapinhoá and Lula Northeast to be tied in next year. So if you break it down in that sense, these are the 2 buckets of considerations.

Jon Rigby - UBS Investment Bank, Research Division

Right. And just on my first question, I mean, as you said, it's not the first time. I mean, is there a process issue here, both with information flowing up to the head office, to your office and -- for information then flowing out from the company to the market?

Frank Joseph Chapman

Well, I think if you look at what's happened over the last couple of years, we have had Elgin/Franklin, which was a blowout, which was not anticipated. We have had CATS shut down for a very extended period due to ordinance settling beside the pipeline. We have had a number of other, due to the age of the facilities, lower production efficiency issues than -- lower production efficiency than we had anticipated. We need to invest, and are investing, in making improvements in these areas and I think we are making progress there. Certainly, if I look at the most advanced of these projects, which is Armada, a few years ago, we were looking at production efficiencies, which were a little better than 50%, and now we're up in the 80s. So this is improving, but it takes time with these facilities that were built in the Crimea and which don't have very large accommodation capacity in order to accelerate some of these remedial works. So we do need to break this down into what is associated with ongoing production, which is largely a U.K. issue which is being addressed, and what is happening with projects, and there, we've made it very clear earlier this year, Elgin/Franklin is shut down. We know why that's happening. We know it's going to go on to 2013. We've made it very clear about Jasmine would be deferred to the second half of next year. We've made it also clear that we will be turning down to a low rate our drilling activity in the Lower 48. Meanwhile, we're pursuing our LNG because that will benefit from these low prices so we have an offsetting non-E&P effect there. So the remaining issues that are news today are these: number one, the extended allowance for tie-in of Sapinhoá and Lula Northeast, and the unexpected and very recent coming to light of the ineffectiveness, the lower effectiveness than planned of the Egypt Phase 7 compression.

Operator

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

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

It's Brendan Warn from Jefferies. Just 3 questions, actually, if I may. Just in Australia, too, are there any further ongoing discussions with other parties regarding an equity sale? My second question relates to your revised production guidance. Can you just give us a sense of the confidence level for your estimates now into 2013? And perhaps, if you can express it by percent, which is current production to that is going to be required from new projects and just the risk of further delay of those new projects? And then just thirdly and lastly, in terms of when did Petrobras, or your operator, communicate to you the new or revised subsea architecture? And when did you start factoring that into your expectation?

Frank Joseph Chapman

Well, the new subsea architecture or the particular sort of subsea architecture that's being considered here is not something that has become -- that we become aware off in the recent past. Of course, this has been engineered and is in the process of being constructed and delivered. What has, of course, happened as we've got closer to this is that the detailed execution planning has been carried out and more allowances are being made for the time it takes to tie in these wells. I mean, I mentioned earlier on time periods going through 2014 actually for Lula Northeast coming to the -- just to the beginning of 2015. But there are, in both cases, 15 wells to be tied in. So you will gather from my remarks that we are assuming in the beginning these extended time periods, but we're also assuming some learning curve as we go along. I do want to emphasize as well that these are particularly complex arrangements, and they will only be deployed, I believe, at this stage, certainly not the immediately -- the following FPSOs immediately after these will not use this architecture because of improvements in the fatigue life of flexible risers, which is -- which has been proved through testing during the intervening period. Now in terms of 2000 and production guidance, what we have done here is we have made an estimate of what we believe a reasonable production efficiency is for all of our operating assets, and the only area where we have had difficulties in this measure before, significant difficulties has been, as I say, in the North Sea, and we think that we have made sensible allowances for production efficiency there. And with respect to the projects coming on stream, we have made sensible allowances like we are making additional allowances for the tie-ins in Brazil, and based upon schedule analysis, had estimated the installation time of Jasmine, the coming back on stream of Elgin/Franklin and the buildup in production from both of those facilities. So that's how we've done this. There's no -- there's nothing more elaborate to say about it than that.

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

Can I just confirm on that, though, in terms of going into 2014 that we're below what would be an extrapolation of a 6% CAGR from 2005?

Frank Joseph Chapman

We -- I'm not sure about that. I mean, if we look at our plan, the former plan for 2013, then relative to that plan, we will miss next year about 30,000 barrels a day from the U.K.-- this is Elgin/Franklin and Jasmine -- due to the deferral of the tie-in, the extended allowance, if you like, for the subsea tie-ins in Brazil that will account for another 20,000 BOE per day that shifted backwards. Scaling back in the U.S. will be 15,000 to 20,000 BOE per day, that will remain out of the mix because we're not, unless gas prices change significantly, planning to restore that. And the Egypt effect is about 30,000 barrels a day. So of those, the key deferrals being Elgin/Franklin and Sapinhoá and Lula Northeast FPSOs will give you some idea of how those will feed through into 2014.

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

Okay. And on Australia, are you still in discussions with anyone?

Frank Joseph Chapman

Yes, Brendan, I won't be speculating with you on the phone about equity sales.

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

Okay. Well, just last question on Australia then. Obviously, a lot of -- with a lot of people modeling start-up of LNG in 2014, when do you actually start to see earnings coming through or cash flow coming through from Australia? Is it well into 2015?

Frank Joseph Chapman

We'll start up in 2014 with our first cargoes and where we'll see earnings from 2014.

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

Fourth quarter?

Frank Joseph Chapman

I mean -- no, we're not getting any more cute than that. We've said from the very beginning 2014 and we'll be in 2014. And I would say at this stage that I'm very content with the fact that the results of recent tendering exercises in the upstream have confirmed -- reconfirmed for us our capital estimates with adequate contingency and reserve. We've now got 90% of those contracts in place, about just a little less than half of the work is done. And right across the project from drilling, where you heard that we've now drilled 1,000 wells through the infield infrastructure, through the pipeline, the Narrows Crossing, which is going now, it's no longer on the critical path, it's going ahead of schedule, and the LNG plant itself, this is all making first-class progress.

Operator

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

Jason Gammel - Macquarie Research

Another one to try to understand production. I'd like to focus, if I could please, on West Delta Deep Marine. I expect that the lack of effectiveness of compression is a reservoir issue, and should we thus expect to see continued declines at West Delta Deep Marine beyond 2013? Would that then imply that we see a write-down of reserves at year end? And then finally, I believe that you're getting about 3.5 million tonnes per annum or so of your overall LNG trading volume from Egypt. So how should we think about the LNG trading portfolio if there are continued declines in Egypt?

Frank Joseph Chapman

Yes. I mean, the -- what's happening in West Delta Deep is a combination of effects of reservoir and the subsea architecture. We are producing in certain areas more liquids than we had anticipated and this is causing further back pressure in certain elements of the subsea gathering system. You know that that's quite deep -- in quite deep water. And there is liquids accumulation in certain parts of this evacuation system, and that's causing back pressure to restrict the production from some wells. And we had anticipated, when we installed Phase 7, that the lowering of pressure and the increasing velocities in the pipeline would have a more significant effect on unloading the back pressure from some of these wells than has actually occurred. There are, however, some reserves issues. They are not material in the overall group context, but we will be reviewing those in further detail, and we will take adjustment on that towards the end of the year.

Jason Gammel - Macquarie Research

And on LNG output?

Frank Joseph Chapman

LNG output, we are not operating the plant at its full capacity. Clearly, we are missing some volume from this Phase 7. But certainly, at present, we are happy to confirm once again that we will be delivering earnings, or I should say, operating profit at the upper end of our $2.6 billion to $2.8 billion guidance range that we announced earlier this year.

Jason Gammel - Macquarie Research

Would it be safe though if I'm looking forward to assume that the 13 million tonnes per annum of offtake that you would currently have could be compromised by the lack of production in Egypt?

Frank Joseph Chapman

Yes, I think that we also need to understand a couple of things about Egypt. This is a prolific basin with a lot of reserves potential. We have multiple phases of development, some of which still are outstanding, and therefore, we're looking at both well workovers, as well as sidetracks and new development wells, which form part of Phase 9a and 9b, which development phases have always been in our plan. Added to which, we have both significant Pliocene prospectivity we'll be spudding, for example, the Scepter [ph] well in December, which is an example of Pliocene prospectivity, Miocenean prospectivity, which is very local to this existing infrastructure and could be tied in early were it to be a success. Now in addition to that, you will recall from the February strategy presentation that we have a new Oligocene play in the Delta. It's further to the east, but the potential there, we indicated that some 17 trillion cubic feet of gas, and we're pleased to report that the Notus well, which is our first test of this potential, has spudded and is making good progress. So there are a number of moving parts in this, and I don't think it's correct to assume at this stage that we're in some sort of terminal decline and there's no way out of it. There are various workover, subsequent development phases and very significant exploration potential in this basin that could come to extend the production life of these facilities.

Operator

Our next question comes from the line of Theepan Jothilingam from Nomura International.

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

A few questions, please. Just coming back to Brazil, could you just tell me what your previous allowance was on the tie-in, please? And then I'm still just trying to reconcile for 2014. Are you assuming, therefore, that these 2 new FPSOs are ramped up to plateau by the end of 2013? Or is there actually a risk in terms of the price offer for subsequent years? Secondly, just -- you have given an impact around production. I was wondering whether you could give an impact around cash flow for 2013 and just reiterate your priorities for retaining the single A credit rating. They would be the 2 questions, please.

Frank Joseph Chapman

Well, on the single A credit rating, I am pleased to report that on the fixed interest side of the equation, the market is very stable today. We certainly do not see our single A credit rating under threat from the new information that's being disclosed today. Regarding tie-ins, we had assumed 1 to 2 months per well earlier in our program. And the detailed execution planning has only recently been firmed up and the decision taken to make a more generous allowance for the tie-in of this particular type of subsea solution. With regards to 2014, both Sapinhoá and the Lula Northeast will have a total of 15 wells tied in. They're not all production wells and they're not all required from day 1. Some of these are injection wells, gas injection, water injection wells. At present, we anticipate that all 15 wells will be connected to Sapinhoá in the course of 2014, and all 15 wells on Lula Northeast will be achieved, I think, it's by January or February in 2015. We don't need all those wells and I'm not going to give you today a specific date for reaching plateau. But for example, Sapinhoá is the most prolific of our reservoirs. And you will know from the experience at the Lula pilot that we only required 4 wells actually to fill that unit and Sapinhoá has got something like 2 to 3x the productivity of the Lula wells. So that will give you some indication of the program going forward.

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

Just a follow-up question, I guess. Is there any other further internal processes that are occurring at the moment that would change your view on 2014 or 2015 production, let's say, for an update in February? I mean, I guess the thesis or what you have very much pitched has been the growth of 6% to 8% would be front-end loaded to sort of 2015, 2016. Is there anything that you are reviewing that could change that for February?

Frank Joseph Chapman

No. As I've said in my remarks that beyond 2013, the group's production plans, which are very -- to a very large extent driven by Brazil and Australia, are unchanged except to the extent that they're affected by today's announcement of CNOOC taking a stake in QCLNG.

Operator

Our next question comes from the line of Martijn Rats from Morgan Stanley.

Martijn Rats - Morgan Stanley, Research Division

I've got 3 questions, if I may. First of all, on Australia, can you remind us of the capital expenditure that you've done so far? Out of that $20.4 billion figure, how much money has been spent on the project so far? And secondly, I was hoping you could provide some commentary on the terms for the 5 mtpa for 20 years sort of sale to CNOOC as well because, obviously, the aggregate value of that...

Frank Joseph Chapman

Sorry, Martijn, the second question was the terms?

Martijn Rats - Morgan Stanley, Research Division

Well, I would imagine you're going to say, "Well, we're not going to say much about it." But I was going to say hopefully you would say something about it.

Frank Joseph Chapman

You've got it in one. We're not telling you about that.

Martijn Rats - Morgan Stanley, Research Division

Is it in line with current market conditions?

Frank Joseph Chapman

I'm not telling you anything about terms. I never do. It's commercially sensitive. That has served us well in the past and it will serve us well in the future. Very competitive market and I'm not dealing with that.

Martijn Rats - Morgan Stanley, Research Division

Okay, okay. And the last question that I wanted to ask you, on previous calls, you indicated that on Queensland Curtis LNG, you need to drill 1,750 wells before the first 2 trains are going to start up. I was wondering if that figure is still relevant. And also, at the current rate of drilling and also taking into account the time to afford dewatering, when do you think that process will be complete?

Frank Joseph Chapman

Yes. I mean, I think that in the order of 1,700 to 2,000 wells is valid. We've done half of them. We're drilling, as you see, something like 130 wells in the last quarter. We want to get this work finished because we do have dewatering to do. The dewatering period for these wells vary quite widely. They can be short as weeks, they can be as long as 4 months, and so we do need to get this work done. We are fortunate in the sense that we have made excellent progress with accessing well locations so we have no shortage of well locations and hence, we are stepping up the number of rigs in order to recover some of the lost time that we had earlier in the program through all of the flooding. You will recall 1 million square kilometers of flood -- flooded area in Queensland. So I'm quite comfortable that the well side of this thing is moving ahead as it should be. With respect to how much money we spend, I'll give you 2 measures: value of work done, right, is getting on for 50%; and the amount of capital contracted, firm contracted is getting on for 90%.

Martijn Rats - Morgan Stanley, Research Division

All right. So value of work done, about $10 billion. That's roughly what you'd spend on it so far?

Frank Joseph Chapman

Yes. You're getting on that way, yes, a little bit less.

Operator

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

Michael J. Alsford - Citigroup Inc, Research Division

I've got 2 questions though, please. Just firstly on Brazil, it feels a little bit, as we go into 2013, that your reduction in your ramp-up is coming broadly in line with -- more in line with Petrobras, the operator, in terms of their slower ramp-up profile versus your more optimistic guidance. Could we suggest, therefore, that the long-term target that BG has of 600,000 barrels per day by 2020, which would include more capacity into Brazil than Petrobras has laid out in its plan are therefore at risk and you come back to us in February to downgrade that number? Secondly, just on Australia, could you maybe give a little bit of color as to why the deal that you signed with CNOOC is so complicated? I've not seen many transactions where you sell bits of parts of the project. Is there a rationale for that? And just taking on the following point around the value of work done, that 50%. If you've sort of spent about $10 billion, if you include your acquisition costs, could you maybe talk about the fact that the price doesn't seem to pay you back for both your acquisition costs and the share of value of work done?

Frank Joseph Chapman

Yes. Just going through these, we have to date some 6 years after making the discovery, placed orders for 2.3 million barrels a day of production capacity. That, in my book, is really good progress. We have agreed with partners to tender a 14th unit, which will be coming on stream in 2015. And we have recently, with the BMS9 partners, agreed to tender for a further unit for Carioca, which is good news, so that will be a 15th unit. It's putting out installed capacity beyond 2.5 million barrels a day. Meanwhile, from the -- if I go back to the time when we first talked about 600,000 barrels a day, the overall setting in terms of the productivity and recovery from these reservoirs has continued to improve. So I have no doubt that the field development plan is not yet complete and it will continue to evolve in discussions with our partners. And I believe that we will continue to see further units added. So I am maintaining, and will maintain, the 600,000 BOE per day target coming out of Australia or coming out of Brazil by 2020. In Australia, I'm wouldn't -- I'm not going to go through the rationale for this. Suffice it to say that we will maintain control over important infrastructure, which will enable us to ensure that future reserves, and we have significant already discovered reserves and significant future exploration potential that we have control over how that is developed, evacuated, liquefied and sold. There was another question. Did you have another question?

Michael J. Alsford - Citigroup Inc, Research Division

Just on the value of the deals, so $1.9 billion value of work done. It doesn't seem like it's actually washing your face when you think about the acquisition costs that you paid in earlier years?

Frank Joseph Chapman

Yes, yes, you obviously don't -- you don't know the terms of the deal so it's difficult for you to see that. But what I can say to you, as I mentioned in my remarks, is that one of the features of our program going forward is that earnings are going to grow a lot faster than upstream volumes. And the reason that's going to happen, well, there are 3 reasons really. Firstly, there's the higher oil indexation. Even though quite a lot of the production is gas, it's quite a high oil indexation. Secondly, the economics of Australia and Brazil will deliver unit earnings, which are very substantially higher than the group average. So if you say to me how much, I would say I can't give you exact number, but somewhere between 50% and 100% higher than the portfolio average. Now in addition to that, we will get a growing contribution from the LNG business, which of course is not production -- upstream production denominated, if you like. So we will get this very substantial earnings increase. And within all of this information is buried the fact that the unit margins for Australia, as we go out to 2020, I expect to be at the same -- approximately the same level, actually, as the unit margins are coming out of Brazil. And one of the sort of flaws, I guess, in the way economics are being done on Australia is that one assumes that all the value sitting on the balance sheet, including value associated with resources to be assessed, appraised, developed, has been ascribed to the economics of the first 2 trains. We will develop through the first 2 trains something like 13 to 14 trillion cubic feet of gas, whereas the total resource level, including risk resource, is something north of 20 -- I want to say 23 tcf. In addition to that, we're making progress, as I mentioned in my earlier remarks, in areas such as the tight gas sands play and the Bowen Basin coal seam gas. So we are very comfortable with the economics of Australia, and we see a lot of potential to build out from our base 2 train position.

Operator

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

Hootan Yazhari - BofA Merrill Lynch, Research Division

A couple of questions, please. On Brazil, I'm just keen to understand how -- as going into 2014, where you are with regards to the detailed development plan in terms of bringing on the 2 further FPSOs plan for 2014. I mean, is there a risk that we have a similar issue where you have the detailed plan being presented to you and that differs materially from what you're expecting currently? Or do you -- have you already conducted that detailed plan? Are you comfortable that actually 2014, there's very little risks there? And then moving on to Australia. Just keen to understand how the sell-down of a big chunk of the asset base there, A, de-risks the potential for a third train, and indeed, how you're thinking about Tanzania at the moment and whether that sort of frees up some resource to start looking more towards Tanzania.

Frank Joseph Chapman

Yes, 2014, I mean, what -- just to give a little more flesh on this subsea architecture issue, essentially, although the pilot and extended well pits have used flexible risers, there's been a remaining concern about the longevity, and we're not talking about longevity in terms of 1 or 2 years, we're talking about longevity in terms of 10 years or more, longevity of some of the flexible riser equipment. And for that reason, we chose to use on these next 2 units a different architecture, which is more complex but more robust, if you like, in terms of fatigue life. Now in the interim period, development work has been going on with a number of suppliers to the point where trials are being conducted and tests are being completed, which have demonstrated sufficient fatigue life. And it is therefore anticipated that this contingency measure, if you like, of using this more complex solution will not be, in fact, now required to be deployed in future. And therefore, the arrangements that we have -- or will have for subsequent FPSOs, I'm expecting to be all of the flexible riser variety, and therefore, will be subject to less installation and tie-in risks. Having said that, I mean, I also believe that were we to continue with these semirigid riser arrangements, of course, there is a learning curve associated with that as well and we would, in any event, expect to get better at that as the time goes on. So I don't see the same type of risk associated with the units coming on beyond -- the next 2 units beyond -- the next 2 leased units beyond the Sapinhoá and Lula Northeast units. Regarding de-risking of the third train, I think the thing that de-risks the third train is essentially further progress with resource appraisal -- exploration and resource appraisal. As I've said before, the momentum in the LNG business is being maintained through, for example, LNG coming out of the U.S., and therefore, there is no critical push to do the third train from an LNG business momentum perspective. And therefore, what we've done essentially is to shift focus to the U.S. for that business while we take more time to appraise the resources. And that's really the key consideration in determining the timing of Train 3 and subsequent trains, actually, given, if we're successful in proving sufficient resources, those further developments. Tanzania, I think Tanzania -- we are going to need the Tanzanias as we go out in the future as investment vehicles to absorb the cash flows that will come -- the very significant cash flows that will come from Australia and Brazil and the other projects that we are bringing on. So Tanzania timing fits very nicely in terms of being new demand for CapEx, just beyond this current suite of projects that are coming through. Meanwhile, we've got to get on with the appraisal. It is good. I would say, this happened a few times with BG, but it is good again to be drilling in a province where we've had a 100% success rate. Six wells on the bounce, 10 -- approaching 10 trillion cubic feet of gas in essentially 2 campaigns which we started in 2010, that's pretty good going, I would say. So we'll continue to focus there, and we're continuing to look for further resources. We're continuing to engage with the government in terms of potential LNG sites. So work is on its way.

Operator

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

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

For Frank, just 2 questions here. The first one is, your $7.6 billion release of capital effectively implies about $1.7 billion from CapEx that CNOOC could give back to you by the middle of 2013. In terms of accounting, should we assume that you will book the CapEx until then as organic CapEx and then you get the proceeds all in one go or would it be treated differently? And then the second question is on your U.S. activity, and I was wondering, if you have a gas price in mind above, which one you would start to ramp up again your activity up from the current 6 rigs?

Den Jones

Okay, I'll take -- I'll answer the first question, on the accounting. Obviously, we will account for CapEx until the deal has been completed and then we will get a refund through the proceeds when the deal completes mid-next year.

Frank Joseph Chapman

Now the other issue was U.S. gas prices, I mean, this is an issue of not much economics but capital efficiency. So if we put a ranking of the projects that are challenging for a share of the available CapEx, the U.S. upstream pipeline gas at the moment doesn't rank. It's down lower on the rank list. So it's not a question of economics, it's the challenge for CapEx. And I think that as we go out and anticipate prices sort of somewhat higher in the $4.25 as we've indicated earlier this year, and at those levels, of course we would be -- I imagine we will be developing.

Operator

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

Thomas Yoichi Adolff - Crédit Suisse AG, Research Division

Two questions as well, please, one on QCLNG and one on production. Firstly, just on QCLNG, when looking at the offtake agreement from your portfolio, with CNOOC starting from 2015, obviously, you're not commenting on the pricing formula. But my question is, whether there be a ramp-up for this 5 million tonne from 2015 and whether this will help underpin Tanzania T1 and T2? In essence, if Tanzania takes longer, you can use Sabine Pass, but if you accelerate Tanzania, you can use Sabine Pass availability as bait for increased flex offerings to Asia.

Frank Joseph Chapman

You should come and work for us, Thomas. That sounds exactly like the strategy. I mean, essentially, that is a feature of the strategy whereby we are knowledgeable about markets. We have a flexible LNG portfolio that we can work in the short term. We can place quantities of that on term contracts from time to time as new projects come on stream. So that is exactly what we're doing. So for example, using -- and again, this is all in a pool of portfolio supply, so it's not the dedicated supply from some of these contracts that we're doing. They're not dedicated supply and that's exactly what we will be able to do. So when we bring on projects like Train 3 or Sabine Pass or when we are successful with Tanzania, we will be able to work those volumes into the portfolio and generate new trades on the back of it.

Thomas Yoichi Adolff - Crédit Suisse AG, Research Division

Okay, perfect. And the second question is just going back to the longer ramp-up period in Brazil, which was already kind of guided by Petrobras in June, I think, but also including for the FPSOs that are expected to start from the end of 2014 even without this new subsea architecture. But when thinking of the longer ramp-up period in Brazil, taking Petrobras as guidance, lower production from Egypt and the U.S. possibly beyond 2013, should we think that the medium-term production target of over 1 million barrels per day, even without the adjustment for the lower upstream share in Australia, looks quite challenging?

Frank Joseph Chapman

Well, we have to make an adjustment for QCLNG. But as I said, beyond the 2013, the group's production plans are unchanged, say, for the adjustment that we have to make. There is, of course, an assumption in there also about our ability through subsequent development phases in Egypt to recover some production there. But in the overall scheme of things, that is not very material actually. So yes, that's where we are.

Thomas Yoichi Adolff - Crédit Suisse AG, Research Division

Okay. And just one follow-up question on the Cabiúnas gas pipeline in Brazil. I was just wondering where you got the environmental permits for this and whether construction has now started.

Frank Joseph Chapman

Yes, the answer is yes.

Operator

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

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

Maybe just another one on Brazil and more on the audit reserve -- audit report you had. Can you talk about whether that incorporates water alternating gas separation in some of the deviated wells that you intend to drill in some of those discoveries? And also, can you just remind us of the timing when you will start that WAG process and the deviated -- some of the deviated wells in Santos Basin in Brazil? And then the second question, just talking about North American LNG, can you just say -- is there a strategy? Or what exactly is happening with some of the news flow around the British Columbia and pipelines in Canada, et cetera?

Frank Joseph Chapman

Yes. The reserves audit make certain assumptions about water injection, but water alternating gas is not included in as a primary successful, if you can say, recovery mechanism. We will be starting, if my recollection is correct, the first phase of this in January of next year. We already have started water injection. I believe we already stated separately gas injection. But the WAG process, I think, is starting, from memory, in January of next year. Deviated wells, the first deviated well we will drill will be on the Iara structure and that will occur, I want to say, at the back end of next year, but I will get back to you on that and confirm. There are 2 Iara wells to be drilled next year and the second one, I believe, is the first deviated well to be drilled. The -- sorry, the next question was?

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

Just around some of the press reports about you taking position, land positions in British Columbia.

Frank Joseph Chapman

Yes, well -- I mean, essentially, what we're trying to do in Canada is to create some optionality. We have, for not very much money, secured an excellent export site. And we have, in conjunction with others, secured capacity and pipelines to be financed by a third party. So this is an early stage of trying to generate some optionality in a commodity where we regard ourselves as expert. I wouldn't say any more than that. It is an option that we're developing for the longer term.

Operator

Our next question comes from the line of Jason Kenney from Santander.

Jason Kenney - Grupo Santander, Research Division

I wanted to go back to you a couple of earlier question themes. And speaking with a number of investors, there's a real credibility issue here despite the results, the capital release and the deal because of the significant change in production guidance. And I just want to know what specifically you're going to do to restore faith in any medium-term outlook that you're going to propose in early next year or even the year after. I mean, it's simply a question of maybe delivery in Brazil. Or do we have to wait for the P&L and balance sheets to offer itself in 2014 or longer term? And then a second theme I think we've heard from questions earlier is, why do you think it's necessary for BG to defend the Brazil technical considerations? And why do you stand up so differentiated from Petrobras, the operator's view? We've seen Repsol and Gaupe both issue press releases today saying that their production forecast have not changed versus earlier guidance, and obviously, you are cutting your own view. And maybe if you had followed Petrobras' guidance, we could all be lumping this onto the Petrobras issue rather than a BG Group issue. And I'm just wondering about the connotations of that and maybe you can give me an answer for those.

Frank Joseph Chapman

Yes, in terms of restoring confidence, it is disappointing today. But I do want to point out that our company has managed to add a huge amount of resources over the years, I mean, about 1 billion barrels of resource a year, and that resource now resides inside the company. Even if I take a view of the situation since just before the 2008 crisis in an industry that simply is not finding resource and is not achieving a 100% reserves replacement ratio, we have actually added over 6 billion barrels of resources during that time and the value of that resource sits in the company today. Our reserves replacement ratio over that period is over 200%, the industry, less than 100%. Over the same period, from before the crisis, we've managed to deliver 25% growth in earnings. Industry average, negative, it's gone down. Even production where we are having disappointing news today, setbacks, we still have grown over that period. Production is something like 5% or 6% against an industry where production has shrunk by 4%. And I think that one of the things that needs to be acknowledged is that our company is adding a huge amount of resource. The reserves replacement ratio tells the market that we are sanctioning the projects, we are spending the capital on those projects and we are providing detailed updates of where we are with the projects. Now it will take time for people to watch and observe those projects coming on stream. But on stream, they are definitely going to come. And this very large resource base of over 17 billion barrels of total resources now is going to drive production growth, and that production growth is going to enjoy higher unit margins than the portfolio average today by a substantial margin. And we ought not forget that very unlike some of our competitors where their midstream earnings are really not making a contribution to overall group earnings growth, we have an LNG business which is very different. It is making a very substantial contribution and one that's growing. Now I know that these things are difficult to accept on a day when there's been disappointing news, but they are the facts and we will continue to execute and commercialize our projects, and we will continue to demonstrate that we're adding a lot of value to our business.

Jason Kenney - Grupo Santander, Research Division

And on Brazil?

Frank Joseph Chapman

Well, on Brazil, you take a view. I mean, we have a view. We're sitting in consultation with Petrobras, we take a view. There have been changes flowing from the detailed executions. I mean, I'm not going to comment on what other parties have done or may do in the future. We have got a 20,000 barrel a day impact due to additional time allowances next year and that, together with Egypt, is the news for today. All of the other factors which we have enumerated have been disclosed before today.

Jason Kenney - Grupo Santander, Research Division

Frank, just maybe going back to that first answer. I mean, I appreciate the resource base and we can see it in the standardized measures of cash flow in the back of your annual report. I mean, from an investor point of view, they just want to pay a price for what they think you're worth and we've lost nearly 20% to that value today. I mean, is that a fair reaction?

Frank Joseph Chapman

You mean, it's a fair reaction from the investors?

Jason Kenney - Grupo Santander, Research Division

I mean, it's a shocking reaction as far as I can see. I'm just wondering how we recouped so much in a short time.

Frank Joseph Chapman

Well, I think I've answered that. I mean, we are being successful in securing resources in a way that the industry, as an average, is not doing. And we are commercializing that in a very short time frame. I mean, we have to remember as well that we did not enter Australia until 2008. And 6 years later, in 2014, we will be starting up our first LNG export. There aren't many companies that are managing to progress at that pace. And I don't want this to come across at all in an arrogant way, but there is a balance here. We have added a huge amount of resource. We are commercializing those resources and making progress. We can see that in our capital spend. We can see that in our reserves replacement ratio, and we will come to see it in our earnings.

Operator

Our next question comes from the line of Anish Kapadia from Tudor, Pickering, Holt.

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

I had a couple of questions, please. Just going back to the impact from Egypt, so working it out, it seems like you're going to be losing about 200 million cubic feet per day of LNG volumes from Egypt. I was just wondering if the way to think about that versus your previous expectations are that we assume a margin on that for the LNG business, say, we're assuming $5 per mcf, you'd be losing about $400 million of EBIT versus your prior expectations for 2013. Could you just talk through that?

Frank Joseph Chapman

No, I'm not going to do that, Anish, because there are too many assumptions you're making there. It is reasonable to assume that we're losing a couple of hundred million standard cubic feet a day. I think that's a correct piece of arithmetic, but I'm not going to extrapolate that into how we're marketing our LNG in the market and what we expect to achieve in terms of operating profit.

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

Okay. But in terms of you losing -- the way to think about that is that it's 100% LNG volumes as you've got to meet your domestic commitment first.

Frank Joseph Chapman

Yes, I mean, there's obviously not just BG delivering into the domestic market, there are a number of players and therefore -- and there is a limit as to how much gas we can deliver into the domestic market because its facility is constrained. So we're meeting our domestic obligations, and we're exporting LNG from which we are, through an escrow arrangement, recovering our revenues.

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

Okay. And then my second question, sorry to get back to it again, but relates back to production again. I'm struggling to see how you get as low as around 660,000 barrels a day of oil equivalent in 2013 with just the impacts that you've cited. I was just wondering if you could give a bit more granularity on your production forecast for some of the key countries in 2013. Just trying to work out if there's a bit more of a structural issue in terms of decline rates outside of -- outside some of the areas that you've mentioned.

Frank Joseph Chapman

No, there's not a structural decline issue. I mean, we presented over the period 2011 to 2020, including maintenance CapEx and investment in projects in existing countries, we call this base production. We talked about between 2011 and 2020 a decline rate over that period average of 3.9%. The effect of Egypt is to change that by something around 0.5% over that long period. So in terms of decline rates, that is not particularly significant. In absolute terms this year, it's quite a big number, but in the overall scheme of things, when you talk about decline rates over the decade, these numbers are not that material. I've gone through the numbers earlier today, but I don't mind doing it again, Anish, because it is important to understand.

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

I just thought the absolute numbers for -- maybe you can give the absolute numbers of what you expect in 2013 for each area, just so we can get a bit more for clarity on the way you see yourselves.

Frank Joseph Chapman

I'm not going through each of the fields.

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

I know the fields, but just the key countries like the U.K.

Frank Joseph Chapman

What I'm saying here is that relative to the plan, we're missing something like 100,000 barrels a day, 30,000 Elgin/Franklin and Jasmine, 20,000 from the -- and that's the deferral, 20,000, due to the extended tie-in periods in Brazil. We're turning down -- it will be 15,000 to 20,000 out of the U.S. because we shut that off. As I said earlier on, that's an economically rational decision. We will be pursuing the LNG business as an alternative and we've laid out how these 2 things provide opportunities, both in a high- and low-priced environment to create value. And the reservoir decline issues at the moment, until we get further with assessing infill drilling, advancing -- or not advancing but implementing the already planned later phases of 9a, 9b local exploration activity to extend plateau and all of that, for the moment, the Egypt decline is 30,000. So if you put those numbers together, that will give you the difference. And of all of those numbers, the Elgin/Franklin, Jasmine and the U.S. data has been in the market for some time.

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

Sorry, just one more thing on that. Could you give what the decline in the U.S. was or what you expect the decline to be in the U.S. for 2012? And then also yet, Trinidad was an area last year where you saw a significant decline. I think about 9% in your volumes in Trinidad in 2011. So is that something that we should expect to be flat going forward? Or is there going to be any recovery there?

Frank Joseph Chapman

I mean, look, the U.S.A. is 15,000 to 20,000 barrels decline next year, okay?

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

But off what base?

Frank Joseph Chapman

Yes, we're going to do -- I'll tell you what we're going to do. If you give Siobhan a call afterwards, we'll go through all this offline because I'm sure there are a lot of detailed question and we're happy to take them offline.

Operator

As there are no further questions, I'll return the conference to you.

Frank Joseph Chapman

Okay. Well, thank you very much, everyone, for taking part in the conference call today. I'd like to remind you that we'll be announcing our fourth quarter and full year results on the 5th of February 2013. Thank you once again, and goodbye.

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