Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Executives

Bruce L. Connery - Head of Investor Relations

Chris Finlayson - Chief Executive Officer, Executive Director, Chairman of Governance Committee, Chairman of Investment Committee, Chairman of Exploration & Appraisal Committee, Member of Chairmans Committee, Member of Finance Committee and Member of Sustainability Committee

Den Jones - Interim Chief Financial Officer, Executive Director, Chairman of Risk Management Committee, Member of Chairmans Committee, Member of Finance Committee and Member of Investment Committee

Analysts

Jason Gammel - Macquarie Research

Michael J. Alsford - Citigroup Inc, Research Division

Jon Rigby - UBS Investment Bank, Research Division

Frederick Lucas - JP Morgan Chase & Co, Research Division

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

Thomas Yoichi Adolff - Crédit Suisse AG, Research Division

Lucas Herrmann - Deutsche Bank AG, Research Division

Rahim Karim - Barclays Capital, Research Division

Peter Hutton - RBC Capital Markets, LLC, Research Division

Matthew Yates - BofA Merrill Lynch, Research Division

Martijn Rats - Morgan Stanley, Research Division

Iain Armstrong - Brewin Dolphin Limited, Research Division

Alejandro Demichelis - Exane BNP Paribas, Research Division

Shola Labinjo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Andrew Whittock - Liberum Capital Limited, Research Division

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

BG Group (OTCQX:BRGYY) Q3 2013 Earnings Call October 31, 2013 8:00 AM ET

Operator

Good afternoon, and welcome to the BG Group Third Quarter 2013 Results Conference Call. [Operator Instructions] And it is a great pleasure to present Bruce Connery, Head of IR. Please begin your meeting.

Bruce L. Connery

Good afternoon, ladies and gentlemen, and welcome to BG Group's third quarter results conference call. During the course of today's call, our Chief Executive, Chris Finlayson; and our Interim Chief Financial Officer, Den Jones, will take you through the quarter's key business highlights, and then Chris and Den will answer your questions. During the call, we'll focus on our business performance results as highlighted in our results statement. We'll 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 risk and uncertainties section of our 2012 Annual Report and Account and also in the half-year results statement published in August. We have also produced a brief set of slides that support today's announcement, and you can find them in the results section of our website. Thank you, and now over to Chris.

Chris Finlayson

Good afternoon, ladies and gentlemen, and thank you for joining us on what I know is a very busy reporting day. You'll have seen our results statement published this morning, and in a few minutes, I'll hand over to Den to take you through the financial data.

Production volumes for the quarter fell as a result of our decision to reduce activity in the USA due to low gas prices, reservoir decline in Egypt and the impact of the planned maintenance shutdowns primarily in the North Sea. However, we will see production recover in the fourth quarter, with completion of the shutdown program and new projects coming onstream in Bolivia and in the U.K. While LNG volumes in the quarter were impacted by disruptions in Nigeria and fewer cargoes from Egypt, the proportion of deliveries to high-value Asian markets increased to over 70%.

In May, I outlined our strategy to build on our strengths, focusing on areas where we have distinctive competitive advantage, in exploration and in LNG. And as I said in May, we will prioritize value over volume. Our priority is execution, the delivery of our growth projects in Brazil and Australia, which over the next 5 years, will be the key drivers for trebling the proportion of our production with cash margins of more than $50 per barrel, and also the delivery of our other 2013 milestones.

So I'd like to update you on the progress that we've made. In Australia, progress on QCLNG project continues as we move through the construction phase into testing, commissioning and, finally, to operation. Following the completion of hydro-testing, gases already flowed into the collection header system, and testing of the entire export pipeline is underway. This should be complete by the end of November.

We've drilled 225 new wells in the quarter, taking the total to over 1,700. And of those, 457 wells have now flowed gas. Three field compression stations, along with the central processing plant in the Ruby Jo block, are due to start commissioning in December.

Now today, it's exactly 3 years since we sanctioned QCLNG, and the progress we have made across such a technically challenging and huge project has been impressive. We are on track to flow first gas to the plant around the end of the year and to deliver first LNG in the second half of 2014 as planned and within the announced $24.4 billion Phase 1 budget. That will be less than 4 years since we took the final investment decision.

In Brazil, well performance from our pre-salt interest continues to exceed expectations. The first 3 FPSOs in operation produced around 160,000 barrels of oil equivalent per day during the quarter, with each well on the second and third FPSOs producing more than 30,000 barrels of oil equivalent per day gross. All 4 buoyancy-supported risers required for further wells on the FPSO 2 and 3 are in-country. Installation of the first unit is underway following recent adverse weather delays. And completion is expected during the final quarter with the second BSR to follow. As a result, the connection of new producing wells on both FPSO 2 and 3 is now expected during the first quarter of 2014. The next 2 FPSOs, which shall also be brought onstream in 2014, are making good progress, tracking to budget and around 80% and 70% complete. Along with our consortium partners, we've also signed a letter of intent for a ninth leased FPSO that is due for start-up on Carioca in 2016. In addition, we continue to improve our drilling performance offshore Brazil. Average drilling time from spud to target depth in 2013 is around 57 days, down from an average of 69 days last year, providing further cost savings over the long-term development program.

We've also received approval from the regulator, the ANP, to submit a Declaration of Commerciality for the giant Iara discovery in December next year. This will allow for further appraisal and well testing of the discovery to optimize development plans. Importantly, first oil from Iara remains 2017 as planned.

We've also continued to make progress on our other 2013 milestones. During the quarter, we successfully brought 2 new projects onstream, with the start-up of Margarita Phase 2 and Bongkot Phase 3K in Bolivia and Thailand, respectively. The major planned shutdown and restart across our North Sea operations is almost complete, with only the Lomond platform left to restart in the coming weeks. The start-up of the Jasmine field in the North Sea and the Itaú development in Bolivia will be delivered in the final quarter.

Now in Egypt, clearly, the business environment remains difficult. Throughout the third quarter, domestic offtake from West Delta Deep Marine development was higher than expected, averaging around 1 bcf of gas per day, which corresponds to the technical maximum of the plant. While the Egyptian LNG plant has operated continuously throughout the year, it has done so at lower than planned levels. As agreed, 5 Qatari LNG cargoes, with 2 allocated to BG Group, were lifted as partial compensation for reduced export volumes. And we have seen domestic offtake in October reduced, with current rates between 700 million to 750 million standard cubic feet per day.

In respect to the receivables balance, for the year-to-date, we have received payments of around $75 million more than we did in the whole of 2012. However, due to the higher domestic offtake during the quarter, the balance increased by $100 million to $1.4 billion, with the overdue balance now standing at $700 million. As such, further assurances regarding future domestic offtake and a material improvement in the outstanding debt position are required before releasing funds for the next phase of development.

Elsewhere across the portfolio, we have advanced new opportunities that play to our competitive strengths of world-class exploration and our unique LNG model. In Tanzania, the Pweza-3 drill stem test demonstrated that development wells will flow at significantly higher rates than anticipated, indicating that the Pweza reservoir is the most prolific amongst our Tanzanian discoveries, reducing the likely well count and, of course, the development cost. We've now fully appraised and tested our acreage around the Block 4 discoveries, with results demonstrating the excellent quality of the fields and their potential to be developed as a northern hub to feed the proposed LNG export terminal. In conjunction with the Block 2 partners in Tanzania, we have recently submitted a proposal for the LNG plant site for consideration by the government. We've also made good progress with the Lake Charles LNG export project, where we expect to lift the majority of the offtake from the proposed 15 million tonne per annum project. The Department of Energy has given conditional approval for exports to non-free trade agreement countries, and we've also signed a project development agreement with the site's owners, Energy Transfer.

Finally, I look forward to welcoming Simon Lowth, who will be joining us as Chief Financial Officer and Executive Director on December 2. And before handing over to Den, I'd like to thank him personally for the hard work and invaluable contributions he has made as Interim CFO during the last 15 months.

That concludes my overview. And now Den will take you through the key financial data.

Den Jones

Thank you, Chris, and good afternoon, ladies and gentlemen. Unless otherwise indicated, all of my comments relate to the third quarter rather than the year-to-date position. As you would have seen, the group's total operating profit for the third quarter was down 15% to $1.8 billion. However, earnings were down only 4% to $1.1 billion. As Chris said, production in the quarter was lower, with around half of the volume decline due to the group's decision to scale back activities in the U.S. in response to low gas prices. This equated to approximately 30,000 barrels of oil per day equivalent. Other impacts included reservoir decline in Egypt and planned maintenance activities, principally in the U.K. These reductions were partly offset by the new developments that came onstream and the continued ramp up in Brazil.

Upstream total operating profit for the quarter of $1.2 billion was 18% lower, reflecting the 10% reduction in volumes, together with higher operating and depreciation costs. The impact of this was partially offset by higher realized oil prices, together with a favorable change in the product mix with a higher proportion of oil produced.

ANP unit operating expenditure increased, reflecting the impact of higher lifting costs in the U.K., which included the impact of planned maintenance, together with higher royalty costs for new developments in both Brazil and Bolivia. The unit depreciation charge increased due to combination of higher costs, new developments coming onstream and the impact of minor reserve revisions. LNG Shipping & Marketing total operating profit of $602 million in the quarter was 12% lower. This was a result of fewer cargo diversions -- sorry, deliveries and reduced margins, partially offset by lower hedging losses. In the quarter, there were 3 fewer cargoes in Nigeria due to disruptions, and there have been 2 fewer liftings than expected from Egypt LNG due to the higher levels of volumes delivered to the domestic market.

As I mentioned earlier, earnings for the group were down 4% to $1.1 billion, with the decrease in operating profit being partially offset by forecast reduction in the group's effective tax rate for 2013 to 42% from our previous guidance of 44%. The reduction reflects a revision to opening deferred tax balances following changes to U.K. taxation rates enacted in the quarter and a change in expected mix of profits for the full year. Cash generated from operations decreased 25% to $2 billion as a result of reduced operating profits and a higher working capital cash outflow.

In line with our strategy of more active portfolio management, we successfully completed the disposal of our remaining 20% equity interest in the Quintero LNG facility in Chile for $176 million. We also signed an agreement with Azure Midstream Energy for the sale of our 50% equity holding in TGGT in the U.S. for $231 million, and we expect this deal to complete before the end of the year.

The group's capital investment on a cash basis of $2.8 billion was broadly in line with last year. And at the end of the quarter, the group's net debt and gearing ratio were $13 billion and 27.6%, respectively. The completion of the CNOOC transaction for the sale of certain additional interest in the QCLNG project expected in the fourth quarter this year will improve gearing by about 5 percentage points.

Thank you very much for your attention, and both Chris and I are happy to take your questions.

Chris Finlayson

[Operator Instructions]

Question-and-Answer Session

Operator

[Operator Instructions] And the first question comes from the line of Jason Gammel from Macquarie.

Jason Gammel - Macquarie Research

My question is on the United States. I think you guys have been really very transparent about your lack of desire to drill in the current price environment, and that's actually quite understandable, and we don't really mind losing your profitability production. But just in terms of longer term positioning, I did note that you opted not to participate with your partner on an acquisition of incremental Haynesville well sites. And I was hoping you could just comment about why you made that decision and if you're comfortable becoming more and more short at the Henry Hub natural gas basis as Sabine Pass comes online.

Chris Finlayson

Thank you, Jason. Yes, I mean, several subpoints there in many ways. We decided not to participate in the sale of the additional Haynesville interest because we were comfortable with the level of exposure we have there. And frankly, we didn't want to build more low-margin positions. At the same time, we have clearly monetized where we think it makes sense. So we've completed the sale of TGGT this year. But at the moment, we feel in the right position keeping some exposure to Henry Hub in the Upstream as we build ourselves into these very significant offtake positions in the U.S.A. We will see how that moves in the longer term, but it's not something that we wanted to move precipitately on at a time when the market would have been very poor for those assets. And it gives us, clearly, some elements of a natural hedge, though, obviously, the volumes we produced do not match the volumes we'll be taking in when you take together our interest in Sabine Pass and Lake Charles.

Operator

And our next question comes from the line of Michael Alsford from Citi.

Michael J. Alsford - Citigroup Inc, Research Division

I've actually got one question on QCLNG. You mentioned obviously very good progress with the project. But could you maybe talk a little bit about what you're seeing from the initial flow rates from the wells, how the deordering is going, and I guess confidence around how quickly you will ramp up the facility to plateau production? That will be really helpful.

Chris Finlayson

Yes. I mean, I agree with you that the speed at which you ramp up is probably the more critical thing next year than the exact date that we come onstream. And to that end, we're in a very good position as we are ahead of the curve in terms of the number of wells we've drilled. The distribution of deliverabilities is pretty much in line with what we expected that to be. And we're also looking at some opportunistic third-party purchases to make sure that we have more-than-adequate capacity available as start-up.

Operator

And our next question comes from the line of Jon Rigby from UBS.

Jon Rigby - UBS Investment Bank, Research Division

Just actually going back to QCLNG and the start-up phase. I think Martin, I think in reference to Egypt at the recent event that you did talked about the kind of minimum utilization rates you can run these plants at. And I think it sounded like they were quite flexible. So I guess my question on QCLNG is, at what point can you start making LNG? Does it -- do you have to be feeding the plant with 1 train full of gas to be actually starting manufacturing in 2014? And the second question is just a quick picky one. On the U.K. gas realizations, you seem to be lagging well behind spot prices. I just wondered whether -- in terms of your realization, I just wonder whether there's issues around sort of legacy contracts, et cetera, or whether it's a strategy or whatever. Can you just maybe explain what's going on there?

Chris Finlayson

Okay, I'll take the question on QCLNG, and then Den will take the question on U.K. gas prices. For QCLNG, the point that Martin has made, I have made as well, in some of these -- with respect to Egypt is that one of the advantages of the ConocoPhillips' Cascade technology is that you can turn it down to an individual train at approximately 35% of ultimate capacity. So it does give you a lot of flexibility. Now that said, in the case of Australia, we would anticipate in having plenty of well capacity available so that we would not be starting at such a low level of gas availability, but we could start at a lower level. It won't, I don't believe, be necessary.

Den Jones

Jon, on your price -- I'm sorry, on your question regarding gas realizations, there's one key long-term contract, which has low prices. So that [indiscernible] impacted us in the quarter.

Jon Rigby - UBS Investment Bank, Research Division

And does that -- when you said it still got a long time to go, so it's going to be a feature of your realizations going forward?

Den Jones

No. It's not a -- it's kind of a midterm contract I'd describe it rather than a long-term contract.

Jon Rigby - UBS Investment Bank, Research Division

Right, okay. So that would mean over time we'd expect your realizations to trend back towards spot. Will that be a reasonable expectation?

Den Jones

Yes, absolutely.

Operator

And our next question comes from the line of Fred Lucas from JPMorgan.

Frederick Lucas - JP Morgan Chase & Co, Research Division

Just a question on -- just wondering how we get to the guidance of an $800 million exploration expense. In the Yagan, we've done $342 million in the 9 months. Is -- could Notus really be a $750 million well? And just a small question on the asset impairment, $58 million pretax written off in the quarter. What was the asset?

Chris Finlayson

Okay. I'll answer the exploration question, and Den will pick up the impairment question. We have 2

[Audio Gap]

to emerge in the exploration spend. One, with regard to some old wells in Brazil, where there's been discussions about whether they're capitalizable or not, as well as Notus. So it's not all down to Notus. But you're right that Notus will be a big swing item one way or the other, depending on the results of the well. The well is still progressing. It's very deep. It's over 7,000 meters now. We've penetrated the secondary targets. We've set a liner yesterday. That's gone very well, and we should be drilling out in the next week or so towards the primary target in the next 300 or 400 meters, but we won't make any announcement until we have completed the well and evaluated the well. And obviously, we won't be deciding on whether it's capitalizable or expensable until we've done that.

Den Jones

Fred, on your impairment question, I mean, it's nothing major. It's just various bits and pieces going through there, nothing specific in there to worry about.

Operator

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

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

Two quick questions, please. Firstly, just back to Brazil. When you think about your own internal budget on production, I think you referred to that in the September update, how do you think about the move up -- the move and the hookup on the BSRs to the right versus, clearly, some better productivity levels from the wells that you have up and running? And then a quick one, just the currencies, particularly in Brazil and Australia, have winged around a bit in recent months. So I was just wondering what sort of impact that has on capital budgeting purposes.

Chris Finlayson

Again, I'll pick up the well hookups, and Den will cover the currency movement. As you will have seen in the Petrobras quarter results and, the Galp quarterly results and Repsol, there has been some delay in the hookup of the wells, all 4 BSRs are in-country. The first one -- the problem has arisen because it was intended these would have been deployed last summer. And we ended up deploying this first one during the winter period when the weather was a lot worse. They have pretty tight weather limits in which they could actually connect and lower the BSRs. The first one is now at working depth, and we're in the process of connecting the permanent tethers to it, which we think is a process which should last another 3 to 4 weeks. That has to be complete before we start tying in the wells, which is why we give advisory it's going to be into the first quarter before the next producing well is connected up. You may have seen, I think it came out in the Galp release, that there is a possibility of a temporary flexible time to get a second well online on this FPSO, which will give us a few weeks of additional production. That is something that we are looking at. It's not yet being decided by the operator if they're putting it forward for a vote, and we'll have a look at the cost against the opportunity that comes with that. You're right when you say there is a balance between the delays in these wells coming onstream and the fact that, clearly, the wells are more prolific so far than we have -- than was built into the plan. So hopefully, we'll have to connect probably 1 less well up to each of the FPSOs before the FPSO is running at capacity. So those 2 effects will partially cancel out. But overall, we believe there will be a small reduction in production next year in Brazil.

Den Jones

Theepan, on your currency question, I mean, mainly, the Aussie dollars has depreciated around 10% for the full year. Although, in the quarter, it was relatively stable. And then we had the kind of sterling against the dollar strengthening as well. And our budget, we still, for the full year, are looking at $12 billion on our CapEx budget. And in Australia, we're still sticking to $20.4 billion for the Phase 1 cost. So we will see some benefit as we go through that and as the currencies kind of change. The impact from the financial -- I mean, if you look at the -- on Page 15 of the release, the consolidated statement of comprehensive income, you can see in there, there's a big impact in there from the Aussie dollar on our Aussie dollar assets; 70% of that CTA movement is due to the Aussie dollar.

Operator

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

Thomas Yoichi Adolff - Crédit Suisse AG, Research Division

Also a question, please, on QCLNG. Perhaps, not really on Train 1 but more on Train 2. I guess, from what you note today, I was just wondering how confident you are on the ramp up of the second train, especially in the context of what your -- what the other projects are saying. They're much more conservative on the ramp up. I guess my question really is about, how capital intensive do you think Q2 will be in the initial years to get the train really running and staying at plateau versus your initial expectation and your ability to keep production at plateau without any further third-party gas deals, thereby passing on the economics?

Chris Finlayson

Okay. As you know, these coal seam gas projects are ones where you need to continue to invest over the life of the project with a significant ongoing well count, and that we will pursue. And at the moment, we have no reason to assume that the wells that we have there will be better or worse than the one -- than we anticipated at the start. But what we are doing, of course, is that we have, as we've talked about, a significant ongoing exploration campaign in Australia, looking not only at the other areas within the coal seam gas, the northern area into the Bowen Basin, but also looking at deep tight gas below our existing tenements. It's pretty much below where our existing facilities are. And also, shale gas in the Cooper Basin on the Queensland-South Australia border. And we'll be drilling our first wells in that in the next few months. We have a program also for these deep gas wells. And clearly, what we're looking for is to see which of these opportunities actually gives us the least capital-intensive way of filling our trains as we go forward. But I'd reassure you that we -- that this extended exploration campaign that we're carrying out will mean that we should have plenty of opportunities to find the gas that we need.

Thomas Yoichi Adolff - Crédit Suisse AG, Research Division

I was just wondering, because when you sanctioned T1 and T2, I guess you've already proved up sufficient reserves, and you're still drilling elsewhere, I guess. And I thought it was meant to be for the expansion rather than for T1 and T2. So just trying to get an understanding of how comfortable you are on the Upstream on the proven side?

Chris Finlayson

Well, for coal seam gas or, indeed, for shale gas, it just doesn't work like that. It's not like a conventional LNG gas play where you hopefully get close to -- I wouldn't argue not always a full coverage of proven reserves. In unconventional resources, you do prove the reserves up as you go along. There is not an equivalent route that you would have for a conventional resource. So we don't have -- we don't and never did have coverage at the proven level and nor would anybody else and nor would you expect to have for a project of this sort. And as you move out into new areas, you see whether the deliverability matches that which you expect. I'll say we've had no unpleasant surprises to date. But at the same time, it makes absolute sense to look for what are the most cost-effective ways of supplying gas, not just for filling Train 2 but, as you say, for looking for expansion potential as well.

Operator

And our next question comes from the line of Lucas Herrmann from Deutsche Bank.

Lucas Herrmann - Deutsche Bank AG, Research Division

Again, 2, if I may. Forgive my ignorance. Can you just talk us through the process of commissioning the LNG plant? I guess, in part, I just -- I'd like a better understanding of why 6 months between the introduction of first gas to plant and the initial expectation of loading ships with LNG. And secondly, just on the LNG volumes themselves, the deliveries into the U.S. have fallen sharply to one cargo a quarter. Is that a sustainable position? In short, have you managed to find alternative sources to feed into Elba that negate your need to deliver and offer you opportunity to divert?

Chris Finlayson

Thanks, Lucas. Okay, on the first one, the commissioning process. Well, as you can see from the picture, it is a very complex piece of kit. We will have gas to the island, as we say, around the end of the year. First thing you have to do then is there is a gas delivery station, which needs to be commissioned. That will allow us to forward flow gas into the plant. At that point, we will start -- the first commissioning phase is to start commissioning our prime movers, and then early commissioning of the flare system. We then have to move into what we call the half end of the plant, start commissioning that and then finally start the cooling progress going up. And then, of course, you need to stop cooling down your LNG tanks. So we have a phased approach for the first couple of months. I think we need about 20 million standard cubic feet of gas, then we move into requiring about 200 million standard cubic feet of gas a day for another couple of months, and then we start moving into full supply and manufacturing. So it -- I'm as inpatient as you, Lucas, but it's a big plant, and it takes time.

Lucas Herrmann - Deutsche Bank AG, Research Division

But I guess the question, Chris, in part is how conservative do you feel, the timelines you're allowing yourself commissioning are? And I still fail to understand why certain of the plant can't be commissioned by bringing in external gas? [indiscernible] can get it from elsewhere.

Chris Finlayson

The reason it can't be commissioned by bringing in external gas is that it wasn't designed to be. I have, myself, commissioned exactly in using external gas. And if the plant is designed in such a way that it can be, it can be advantageous. This one was not. And again, a feature of the difference between the APCI process and ConocoPhillips' Cascade process that makes it much harder to do it through imported LNG using ConocoPhillips and requires a large additional capital investment. That's why we didn't do it.

Lucas Herrmann - Deutsche Bank AG, Research Division

And in terms of the amount of headway you've let yourself after the commissioning period, how conservative do you think -- how much scope for mishap, if I want to put it that way, have you let yourselves get in the 6-month window you're talking about?

Chris Finlayson

Clearly, we have contingencies in there. Contingencies are there if things go wrong. So we stick to the schedule that we've given.

Lucas Herrmann - Deutsche Bank AG, Research Division

Okay. And the question on Elba.

Chris Finlayson

Yes, it is sustainable. I mean, we are -- there have been changes, as I recall, to the pipeline infrastructure around Elba, which has allowed us to reduce the LNG imports into there. So this low level of U.S. imports will continue.

Operator

And our next question comes from the line of Rahim Karim from Barclays.

Rahim Karim - Barclays Capital, Research Division

Two questions, if I may. Chris, you kind of alluded to the fact that you are holding back investment in Egypt until you got a bit more clarity from the government around the evolution of domestic offtake. I was wondering if you could just perhaps elaborate on that a little bit and give us a sense if the implications on both CapEx and forward production profiles in Egypt should you not get the insurances that you need. And then the second question, just to try and get some guidance for the tax rate going forward, obviously, 42% for this year. What should we be expecting for 2014 and beyond, if possible?

Chris Finlayson

Okay, I'll try and give a bit more color around Egypt, then obviously, Den will come around and talk through the arcane matters of tax. I would start by saying, remember that when we talk about future investment, we are really talking about Phase 9b. Last year, we committed to Phase 9a. We're now deep into execution. The drilling is going very well for that. In September, we said that we had largely on the onshore part of construction, the manufacturing of the subsea cape, which is being done in Egypt, there was some delay from that. And as a result, Phase 9a would be 3 months late coming onstream. Clearly, with the amount of some costs that goes with that, there is not any intent to hold back or stop Phase 9a. That will come onstream in the second half of next year and will be the main driver for volumes into 2015. What we're talking about is the next phase of commitment to Phase 9b, which we are due to take sometime around the end of this year or into the first quarter of next year. That's what we're saying is before we are prepared to make that further level of commitment, then we need to see progress and more clarity and assurance on what the offtake profile is going to be like and, clearly, a significant reduction in the debt. There is a high level of engagement going on with the Egyptian government. I was there last week. I met with the minister and the Prime Minister. There is a lot of -- there's good understanding in the Egyptian political system of what needs to be delivered there. We now need to see them deliver that.

Den Jones

Yes, Rahim, on tax, we've reduced the ETR for this year from 44% to 42%. As I said in my speech, basically, a percentage of that is due to reduction in rates from U.K. corporation tax. And then another percent is due to kind of a mix of profit. Going forward, as Chris said earlier, and we said earlier this year, we will give the kind of effective tax rate for the year when we give our Q4 results. So for 2014, we will do that in February. And I'm not going to give you a longer term rate. It would -- it just depends on the mix of profits as we go through -- as the portfolio develops. As Brazil and Australia come on, things will change. So for the year, it's down to 42%. And we'll give you future years as we go through them.

Operator

And the next question comes from the line of Peter Hutton from RBC.

Peter Hutton - RBC Capital Markets, LLC, Research Division

Guys, on Egypt again. Just sort of a bit further on this one. In thinking about the rates into the domestic market declining from October from 1 bcfd to 7,750 million scfs a day, what indications have you had from the discussions with the government and EGAS that the volumes of gas freed in the domestic system will go through to your plant? Or is there any offset in terms of allowing the restart of the Damietta plant, which has been shut until February? Does your plant still get priority for any available gas? Or is there an allowance for the restart of that one? And can I just also say, on the winter demand, that's lower. But, of course, summer will start again next year and you'll be -- that's probably slightly ahead, I think of the new phasing on 9a. And are we going to face exactly the same kind of issues but slightly worsened given the decline when we get to this period in around 6 months' time?

Chris Finlayson

Thank you, Peter. The answer to the first question is very simple. All the gas that we produce through Itcu [ph] comes from our own developments and comes into the plant directly from offshore. So there is no question of any of that gas being used to restart Damietta. Damietta works, as I understand it, directly off of the Egyptian grid rather than having dedicated offshore fields coming to it. So there is no linkage between those 2 items there. In terms of what happens next summer, you're right. That's exactly the area in which we are seeking the assurances from the government. One thing that I can tell you that they are doing is because they are seeing a greater visibility of liquids, they are actually in the process, as we speak, of converting more of their power generation capacity into dual fuel or oil burning, which will allow them to change that primary fuel mix next summer.

Operator

And our next question comes from the line of Matthew Yates from Bank of America Merrill Lynch.

Matthew Yates - BofA Merrill Lynch, Research Division

I was going to ask a question on Egypt, but I think it may have been covered already. Just curious, from your preliminary discussions with the government recently, would your expectation be that you would get full year visibility on domestic versus export? Or will this continue to be a quarter-by-quarter discussion?

Chris Finlayson

I'm not going to give you sort of a false assurance. This is an ongoing discussion. But what I can tell you is that we have had a very firm assurance from the minister that the Itcu [ph] plant will continue to operate through the year. Obviously, the debate that we have now is on levels, on the amount of gas that is going to be taken to the domestic market next year.

Operator

And our next question then comes then from the line of Mart Rats from Morgan Stanley.

Martijn Rats - Morgan Stanley, Research Division

I wanted to ask you 2 things. First of all, there has been some sort of commentary in Australian local press about the sale of the pipeline that connects the Upstream to the LNG facility in Curtis Island, which could be sort of a particularly large disposal. I was wondering if you sort of could comment on that and to where we are in that process? And secondly, I realize this might be a little premature. But if, in Brazil, wells are flowing faster or at least at a higher rate than you initially expected and you can also drill them quicker, of course, there's cost savings to be made. But what does that mean indoors? Can you just give us any quantification of that? Again, I realize, this might be a little premature but you're much better positioned to answer this question than we are, and it might be significant I would suspect.

Chris Finlayson

I'm afraid it is too. I mean, this is the first 2 well, one well on each of the vessels as we go through there. Clearly, the performance in FPSO 1 has also been very good, but it's too early to start translating this into cost savings. I think what you should do is to take assurance from the many comments that have come through on worries about Brazil costs out of control going up and whatever. We've always come back and said, "No, we're on budget for Brazil." And we reiterate that now. And clearly, results such as this show how that we will be on budget for Brazil. With regards to the QCLNG infrastructure, there has been a lot of speculation. We are clearly looking at this as an option. We think these are assets which would be attractive to infrastructure owners. There needs really to be an income flow coming from them before the type of buys we have identified for these assets are likely to be interested. So we're not talking something that is likely to occur in the very short term. But, as you say, we think that they are good opportunities to further decapitalize the project in Australia and improve our returns.

Den Jones

Yes. And Martijn, it's all part of the active portfolio management as we detailed in May and through our strategy.

Operator

And our next question comes from the line of Iain Armstrong from Brewin Dolphin.

Iain Armstrong - Brewin Dolphin Limited, Research Division

First question, what's the situation on Elgin/Franklin at the moment? Are we anywhere close to getting back to full production? And the second one will be on Tanzania. Are you precluded from bidding for an additional stake in the Ophir blocks which have been put up for sale?

Chris Finlayson

Okay. First question, Elgin/Franklin. We are not back to full production. It will be sometime until we ask to go back to full production because we have a need to -- or the operator has a need to abandon a number of other wells where there are high annular pressure. That process is ongoing. We then have a full redevelopment of the field using new wells with new cement in there. What is good news is that we have seen the reserves to be developed rising in Elgin/Franklin, so it remains a highly attractive asset with a long-term future in front of it. We put in 2 additional platforms, Elgin B and Franklin B, in the last 12 months. One of the decks is on that, the other one will be added in the summer, and we will be operating with -- as a consortium with up to 4 rigs looking forward to make sure that we do the redevelopment of that field as rapidly as possible. In terms of Tanzania, we are clearly very, very happy with the results that we have had from our exploration in Blocks 1, 3 and 4, Remind you, no failures to date. There is lots of speculation in the press around what Ophir will do going forward. We will wait and we will see what will happen. We clearly have normal sort of preemption rights within that -- within those blocks, and that would give us an opportunity to act if we chose to do so.

Operator

And our next question comes from the line of Alejandro Demichelis from BNP Paribas.

Alejandro Demichelis - Exane BNP Paribas, Research Division

Two questions, if I may. The first, one staying on Tanzania, the partners on Block 2 seem to be having discussion with the government regarding higher domestic gas market obligation. Would that just apply to those or are you having those similar discussions with the government? That's the first question. And then the second question is, in your Capital Markets Day, you reiterated your guidance for 2015 on volumes. You have been now telling us about the Phase 9b on Egypt that, potentially, could be on ice or delayed. You have been talking about the ramp up on Train 2 also. So maybe you can give us some kind of indication of what are the sensitivities around those targets in terms of size of volumes because of these 2 things?

Chris Finlayson

With regards to the specific points you make, we should be clear that our intention is to secure the necessary assurances that we need and to continue to invest in Phase 9b. As such, that remains our base case. If we were to choose not to do that, then we would clearly need to inform the market that we were not doing so. But at the moment, that remains our base case. For the rest -- for our 2015 figures, we will be coming back. As we said last year, at our Q4 result, full-year results, and setting our targets for 2014 and any update we want to make on 2015, and we don't feel any need to do anything in advance of those -- of that day.

Alejandro Demichelis - Exane BNP Paribas, Research Division

Okay. And how big is Phase 9b then in terms of volume?

Chris Finlayson

Well, it doesn't give you anything in 2015. That's when we're drilling it is right at the end of that year and into 2016, so it wouldn't impact on those figures anyway. With regard to Tanzania Train Block 2, we are not privy to the PSC of Block 2 between Exxon and Statoil. But I can tell you that the domestic market obligation for us is very clear in the PSC and that is what we're working to. And at the same time, as we put in the release, we are working together with the Block 2 partners on a joint plant. We've submitted jointly the preferred site for that plant to the government. And clearly, again, that fits within our strategy of trying to reduce capital intensity of these developments and make sure that we have the best capital return on them.

Operator

And our next question comes from the line of Shola Labinjo, TPH.

Shola Labinjo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

I had a couple of questions in exploration, actually. In Kenya, particularly, you're drilling early next year. I was just wondering if there's anything that you can read across or take away from the wells that Anadarko has drilled offshore Kenya to date. And then the other thing is, in the Cooper Basin, you mentioned that you were chasing the shale gas plays there. Just wondering if there's any commentary that you could share with us with regards to the well that has been drilled and completed by Santos, which appears to be producing with pretty good results so far?

Chris Finlayson

Yes, with regard to Kenya, what I would say is that the play that we are pursuing with the first well is a very different play from the one that Anadarko did. We talked about it at our capital -- at our exploration day in September. This first well is targeted at pinnacle reef buildups, carbonates, something very strongly in our expertise base. It's a relatively high risk but also a very high-reward well. It's repeatable as well. So we will see how that develops. But it's certainly one of our high-impact wells for next year. With regard to your second question, which I've temporarily forgotten...

Den Jones

Cooper Basin.

Chris Finlayson

For the Cooper Basin, the well that are -- we have not yet spudded a well. We will be doing so. It is, you're right, relatively close to the Santos find, which is -- so we are encouraged by that. But we're not going to say anything further until we've actually completed our own drilling.

Operator

And our next question comes from the line of Andrew Whittock from Liberum.

Andrew Whittock - Liberum Capital Limited, Research Division

A question or 2 on CapEx. Year-to-date, it looks like capital spending has been about $7.6 billion. So I wondered if $12 billion was really the best number for this year. And secondly, I wonder if you could give us a steer as to what we should be thinking for in 2014. Is it another $12 billion?

Den Jones

Yes. I mean, our forecast for this year is $12 billion. We do see a pickup in Q4. And as we've said before, the number for cash CapEx for 2014 is also $12 billion. And then after, it's coming down from that to $8 billion to $10 billion from 2015 onwards.

Andrew Whittock - Liberum Capital Limited, Research Division

Well, I guess, we'll get an update on that in February as well. Will we?

Chris Finlayson

You will.

Den Jones

You will, yes.

Operator

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

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

Two, if I may. And first, on the QCLNG infrastructure disposal, I was wondering how much capital is associated with those assets out of the budget of $20.4 billion. And secondly, on the North Sea maintenance, could you quantify what the impact was in Q3 and how much you expect to come through in Q4?

Chris Finlayson

I'm sorry, Michele, I'm not going to be very helpful for you here. Clearly, we see the amount of capital, and the infrastructure in Australia is a commercially sensitive item as we move forward with the work we want to do there. And we're not going to talk in detail about the individual items in the North Sea, so my apologies.

Operator

And as we have no further questions, I'll return the conference to you.

Chris Finlayson

Thank you very much, indeed. So thank you, all, for your questions, and I'd just like to end by summarizing the key points from today's announcement. Earnings for the third quarter are down year-on-year as a result of lower volumes in both production and LNG. But production will recover in the final quarter as new projects come onstream and our shutdown is finished. The QCLNG project, as you've heard, is advancing to plan as it enters the commissioning phase. Well performance in Brazil continues to exceed expectations, and I think we've made good progress against our other 2013 milestones. So thank you, all, for your time. I look forward to seeing you in person when we present our fourth quarter and full-year results on February 4 next year. Thank you, and goodbye.

Operator

This now concludes today's conference. Thank you for attending. You may now disconnect your lines.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: BG Group Management Discusses Q3 2013 Results - Earnings Call Transcript
This Transcript
All Transcripts