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Executives

Peter Voser – CEO

Simon McHenry – CFO

Analysts

Lucy Haskins – Barclays Capital

Jon Rigby – UBS

Alan Define [ph] – Citi

Oswald Clint – Sanford Bernstein

Alejandro Demichelis – Merrill Lynch

Irene Himona – Societe Generale

Deepan [ph] – Morgan Stanley

Kim Fustier – Credit Suisse

Iain Reid – Jefferies

Mark Gilman – The Benchmark Company

Jason Campbell – Macquarie

Jean-Pierre [ph]

Neill Morton – Bloomberg

Sergio Molisani – UniCredit

Royal Dutch Shell Plc (RDS.A) Q4 2010 Earnings Conference Call February 3, 2011 8:30 AM ET

Operator

Welcome to the Royal Dutch Shell Q4 results announcement call. (Operator Instructions) I would like to introduce our first speaker, Mr. Peter Voser. Please go ahead, sir.

Peter Voser

Thank you, operator, and good afternoon everybody. Simon and I will take you through the results and portfolio developments for the Q4, and specifically for the full year 2010. And then we’ll have plenty of time for your questions.

Firstly, take a moment to read the disclaimer. The world is in an era of important geopolitical transitions, strong volatility, and intensified economic cycles. Emerging nations like China and India are going through intensive developments. The recession interrupted the oil and commodity price boom but it may well return. This is a complex and volatile landscape for the energy industry and an opportunity for Shell.

A year ago I mapped out a three-year plan for Shell to 2012. The focus is on three strategic priorities: improving our near-term performance, growing the company by bringing new projects on stream, and generating new options for future growth. I’m pleased to say that we have made good progress on all of these themes in 2010. Our 2010 CCS earnings excluding identified items were $18 billion, an earnings per share increase of 56% year-on-year. This improvement comes despite pressure on Downstream margins and natural gas prices. We have taken out $2 billion of costs, we sold $7 billion of non-core assets, with exits from 12% of our refining capacity. We increased our Upstream production by 5%, we made eight new discoveries and made strategic acquisitions in unconventional gas and bio fuels. Project delivery is going well and I will update you on that, including Qatar, in a moment. So overall good progress on our plans in 2010.

Let me say that also although we made good progress overall in 2010 I’m not satisfied with the Q4 results. These results underscore why we have set out the three-year plan for better performance from Shell and we have more to do. We have reduced down-the-line costs by $2 billion in 2010, bringing the total cost reduction for ‘09 and ‘10 to $4 billion, or about 10%. But we haven’t stopped here. We have a series of continuous improvement programs on the way across the company. These plans in total are expected to deliver further multi-billion dollar cost savings in the future. Now going forward we should expect to see increases in headline costs in the areas where we are targeting growth. However, our continuous improvement plans should go some way to offset these trends.

Now let me update you on our asset sales program. 2010 asset sales proceeds were $7 billion, essentially completing our 2010 and ‘11 targets for $7 billion to $8 billion. These include exits from seven of our eight non-core refineries and continued progress in refocusing our markets and portfolios. We have exited from 450,000 lbs today of refining capacity in 2010, or about 12% of our total, and this brings the reduction since 2002 to almost 30%, or 1.2 million barrels per day. Total asset sales in the last five years were some $30 billion, which is a rollover of about 20% of our capital employed. From here, the pace of asset sales could slow although we expect some $5 billion for 2011, including some $2 billion of proceeds still to come from these down across the end of 2010.

Let me now turn to growth delivery. We have a sequence of new projects for 2010 and ‘11 startups that underpin our production and cash flow targets for 2012. We made good progress in ‘10 with six new startups. Let me give you an example. In Nigeria, the Gbaran Ubie gas project has ramped up well, and is on track for its peak production of some 250,000 barrels, or BOEs per day. This adds to Nigeria’s LNG supply capacity, and will feed electricity supplies for local communities. Our most recent start-up in early 2011 was in Qatar, and let me say more about that with the next slide. 2011 is going to be an exciting year for Shell in Qatar. We have two projects there, both due for startup this year – Pearl GTL and Qatargas 4 LNG. Together, these projects, which will cost about $20 billion for Shell and will add about 350,000 BOEs per day to our production, which is over 10% of our current production worldwide today.

The first of these, Qatargas 4 LNG, is now in the startup phase. We started to produce LNG at Qatargas 4 in the last few days, and we are expecting the first shipment of LNG in the next few weeks. Our second project in Qatar – Pearl GTL – is also making good progress. Major construction on both trains is now complete. This was a mammoth undertaking – 52,000 workers at the construction peak. Safety performance has been excellent and we have set new records in 2010, with 77 million working hours, or hours worked onshore without a lost time incident. During the Q4 of 2010 we made considerable progress on commissioning. More than half of the roughly 2000 Train 1 systems we need have been brought to what we call ready for startup status. We have completed our Train 1 steam blowing. We have started our first air separation unit, imported gasoil and condensate to do the live commissioning, and loaded catalyst in over half of our Train 1 reactors. So overall a very satisfactory performance for what is a large and complex facility.

Now let me update you on progress with longer term options. We are working hard

to turn exploration success into commercial production. In 2010, we took final investment decision on two new deep water projects in the Gulf of Mexico and Brazil. And we made good progress with new exploration and appraisal, with eight new finds and further appraisal success. Now we are studying all of these results, and will update you on the resource potential during our strategy presentation in March like in previous years.

2010 was also a busy year for new deals. We have added new acreage positions in 2010, some 53,000 square kilometers. The focus here has been on building up new plays for Shell. We’ve also made progress on Iraq oil, and in our Downstream and bio fuels joint venture in Brazil. Now, Shell has a long history of successful partnerships with national oil companies. I would like to highlight the new momentum that we have built with NOCs in 2010, including deals with PETRONAS in Iraq, in Qatar where we are in talks for a new petrochemicals plant, in Saudi Arabia going forward in the Empty Quarter and with China. We have concluded a series of deals with the Chinese NOCs in 2010. This included an Upstream partnership in Syria, the joint acquisition of Arrow, the CBM-LNG player in Australia, gas exploration in China and exploration in Qatar linking Shell, QP and a Chinese NOC. Finally on NOCs, late last year, we signed a new MOU with Gazprom, looking at joint expansion of our Upstream activities in Russia, so Sakhalin LNG and (inaudible) Siberia, and the new international partnership.

Now before I hand you over to Simon, let me say a few words about safety. Safety is at the heart of everything that we do here in Shell. We manage personal and process safety with the positive trends you can see on this chart. Macondo was the largest ever deep water blowout, and the largest peace time oil spill for 100 years. We can all talk about causes and make all kinds of explanations but the reality is that the picture has changed for the deep water industry. There will be increased regulations and more public scrutiny on safety. To put it simply, our industry needs to rebuild trust with the communities we work in. Shell has a good track record in deep water, and we always look for ways to improve.

We have completed an initial review of the Presidential Commission report into Macondo, and we agree with the majority of the findings. In particular, we share the conclusion that US regulations and the risk management practices of some companies in the Gulf of Mexico do lag behind the standards set by other companies and set by regulators in other countries. We support the Commission’s recommendation to introduce risk-based standards specific to the relevant activities, similar to the safety case approach in the North Sea. Now we at Shell has been applying the best of the North Sea standards to our worldwide operations for many years. This includes the safety case approach worldwide. On Shell’s wells, the roles and responsibilities are clear, both for accident prevention and incident response, and we have a strong safety record.

Let me also update you on the near-term drilling outlook in the US offshore. In the Gulf, I am pleased to say that Shell is the first company to have successfully submitted plans for exploration drilling, three wells in the Auger area in accordance with the new HSE standards for the Gulf. These permits are now with the authorities for review. In Alaska, Shell has the leading acreage position in offshore Alaska, and this remains an interesting area for us in the longer term. We have been working rigorously for the past 5 years to meet and exceed all regulatory and permitting requirements in Alaska. However, despite our investment in acreage and technology and our work with stakeholders, we have not been able to drill a single exploration well.

Our plans for drilling in 2010 were put on hold following the BP Macondo blowout. Despite our best efforts critical permits continue to be delayed, and the timeline for getting these permits is still uncertain. Therefore and regrettably, because of these uncertainties, we have decided not drill in offshore Alaska in 2012 and stop the spending for these activities. We need urgent and timely action on permitting and regulations in order to go ahead with the 2012 drilling program. We are working towards that.

With that, I pass you to Simon on the results.

Simon McHenry

Many thanks, Peter. I’ll just take you through the Q4 numbers and give you a heads up on some of the key figures for 2011. First on the macro. If you look at the macro pictures compared with the Q4 of 2009, the oil and gas prices have increased from year-ago levels, although actually in North America the gas prices did decline. Refining margins increased from year-ago levels and chemicals margins increased in the United States, but they declined slightly in the other regions.

Turning now to Shell’s Q4 earnings. The headline current cost of supplies earnings of $5.7 billion for the quarter included identified items of $1.6 billion primarily gains on asset sales, namely Woodside. Excluding the identified items, the CCS earnings were $4.1 billion and that’s an earnings per share increase from Q4 2009 of 49%. Cash flow from operations for the quarter was $5.5 billion and the dividend for the Q4 was announced at $0.42 US per share. Now we expect to announce the Q1 2011 dividends as an unchanged $0.42 US per share, although this of course is a decision reserved for the Board at a later date. In the Q3 we introduced the scrip dividend for the first time. The take up of the scrip was equivalent to around $600 million and that’s about a quarter of the dividend, and we’re offering the scrip again of course for the Q4.

Now let me turn to the business performance in a bit more detail. Firstly, the Upstream. Excluding the identified items the Upstream earnings increased by 25% to $3.4 billion in Q4, and that was driven primarily by higher oil prices, higher realized gas prices outside of North America, and by the 5% increased volumes. We did see increased costs in some areas, associated with for example startup activities in projects such as Canada Oil Sands, in Qatar and in Iraq. Of course we’re building up that operating capability ahead of the new revenue and production growth that we expect when the projects come on stream. We had overall another good quarter for production.

The Upstream production increased by around 5% Q4 on Q4, and LNG sales volumes increased by 11% for the quarter. If you look at the full year, the production averaged 3.3 million barrels of oil equivalent per day, output from the new fields and field ramp-ups was 170,000 barrels of oil equivalent per day, and that more than offset the natural field decline. Production this year was also boosted by external factors such as colder weather, particularly in Europe and North America, and an improved security situation in Nigeria, and therefore production was ahead of our initial guidance for the year. Having said that, the growth was typically from lower margin barrels.

For the full year the LNG sales volumes grew by 25%, and that was underpinned by increased volumes in Nigeria LNG, largely increased supply from new projects and better security, but also by the full ramp-up of Sakhalin LNG in Russia, which has been producing above name-plate capacity for basically all of 2010.

Turning to the US Upstream where the whole of our industry, of course, has been impacted by the BP Macondo blowout. Now Peter talked about the longer-term implications; I’ll focus on the financial impact. So we didn’t actually receive any permits for new exploration or development drilling during Q4. As a result we took a $70 million identified charge in the Q4 for the cost of the idle rigs, the four deepwater floaters that we have in the region. And this combined with the charges in the earlier quarters – Q2 and Q3 – and the production shortfalls, that led to an earnings loss for Shell in the full year of $260 million. The equivalent was 10,000 barrels of oil equivalent per day of lost high-value production, mainly liquids. By the year end that was a run rate approaching 30,000 barrels of oil equivalent a day. And we actually had to postpone around $700 million of planned investment in exploration and development during the year. In 2011 we are expecting around a 50,000 barrel a day impact against the plans that we had prior to the moratorium, and that’s an increase to the guidance. At the last we previously had around 40,000, so recognizing that the slow pace of any likely restart in the Gulf and the lack of any permits being issued to date.

Turning now to the Downstream. Excluding the identified items, the Downstream CCS earnings, they increased from the Q4 2009 around $482 million. Within this number the chemicals earning increased substantially. This was driven by industry margins, lower costs, and our actions to enhance the portfolio, to improve the structure of the margins including conversion to gas field. And our chemicals margins did fall at the end of the quarter reflecting higher naphtha prices following the crude price up, and that will impact into the Q1 of 2011. I should also update you that we have substantial planned downtime in the Singapore chemicals plant in the Q1 of 2011, so both factors will play a part.

In refining we did see an improvement in the industry refining margins and certainly year-on-year improved outcomes, but the refining conditions do remain difficult overall, reflected of course in the losses in refining in the quarter which were around $460 million. That compares with losses around $940 million last year in the Q4. Earnings were also impacted by exchange rate movements and refinery downtime. We had maintenance downtime, planned and unplanned, including cat crackers, cat crackers being the main revenue generator in several of our refineries, and we also had downtime at eight refineries in the Q4. It’s also typical that we concentrate or focus our maintenance activities in Q4 and in Q1 which are typically lower demand quarters. Now, the increased costs associated with the additional maintenance, and the opportunity loss, the margin loss as a result of not operating – that cost us around $200 million in the Q4. For the Q1 of 2011 we’re expecting similar or even slightly lower refinery availability compared with Q4 2010, so again impact on Q1 results.

The marketing earnings were broadly similar to a year ago, actually a year ago Q4, but this is below our long term trends, several hundred million dollars below. In fact, marketing and trading results in the quarter were around $375 million. We did see lower costs. We did better year-on-year in retail, lubricants, and B2B, but trading overall saw a less favorable environment and a less positive contribution. Monthly margins and underlying volumes did decline compared to the Q3 of 2010, and that was mostly driven by the steady increase in oil prices although volumes were also impacted by some of the weather conditions we saw in the US and Europe.

So those are the earnings; we’ll turn now to the cash flow. Cash generation on a rolling basis, the twelve-month basis, was around $40 billion, including $7 billion of disposable proceeds, also excluding the working capital impact in (inaudible). And that was broadly balanced against the outflow of $39 billion for the year. Upstream and Downstream businesses cash generation was in fact ahead of their own spending requirements. We remain, have been and will remain in a capital intensive stage as we invest for the new growth. We continue to watch the cash position on the balance sheet very closely, with particular emphasis on costs and of course capital efficiency.

Now turning to CAPEX and the balance sheet, we ended the year 2010 with gearing at 17.1%. That’s several percentage points below earlier projections, slightly down from the Q3 levels; comfortably in the target range of 0% to 30%, helped of course by divestments concluded in the quarter. Our return on capital in service, i.e., currently producing assets, was 18.5%. Of course that’s only about two thirds of the balance sheet, about 65% at the moment; the rest of the balance sheet remains work in progress to produce in future.

2010 was also a busy year for acquisitions, $7 billion of acquisitions, not yet including the conclusion of around $2 billion of the Cosan [ph] joint venture in Brazil which should close in the coming months. Those acquisitions were matched by an equivalent number, $7 billion in asset sales. Both of these additions and divestments are part of the drive to enhance the portfolio, upgrade the quality of the margin and to improve the capital efficiency. For 2011, we are expecting in line with earlier strategic statements, net capital investment, $25 billion to $27 billion; in line with that long term strategic plan we talked about a year ago. And you can see some of those details on this chart.

In 2011 we will see spending rates decreasing in some of the players like Qatar and Canada heavy oil, which has dominated recent spending, but we will step up in areas such as Australia, Iraq, and of course the $2 billion to complete the Brazilian biofuels deal. So within this mix I expect exploration spending of around $3 billion again this year, and our overall North American tight [ph] gas spending, where you will recall we talked about quite a wide range of possible spend, we’d expect that to be around $3 billion again this year. So both exploration and the tight [ph] gas spending of around $3 billion, similar to 2010 levels, excluding acquisitions of course because around $6 billion of last year’s acquisitions were actually in that area.

Okay, with that let me pass you back to Peter to summarize before we move to the Q&A.

Peter Voser

Yeah, thanks Simon. Just a quick summary from our side. Our performance in 2010 underlines that we are delivering on our strategy. We are making good progress with our three strategic themes and targets for 2012. Our earnings increased by 56% year-on-year. $2 billion of costs we took out, sold $7 billion of non-core assets, with exits from 12% of our refining capacity. We increased our Upstream production by 5%, made new discoveries, and made strategic acquisitions in unconventional gas and biofuels. So overall good progress on our plans in 2010. And Shell is back on track for growth.

Thank you very much. Back to the operator for the Q&A session.

Question-and-Answer Session

Operator

We will now begin our question and answer session. (Operator Instructions) And the first question comes from Lucy Haskins from Barclays Capital. Please go ahead.

Lucy Haskins – Barclays Capital

Good afternoon. I think at the first half stage you were within 12% of your 2012 cash target, and there seems to be a move away from that in terms of the Q4 numbers. Obviously, Simon, you talked about some issues that impacted the quarter. Is there anything else you’d like to draw to our attention in terms of being not quite special items but slightly one-off or exceptional at this stage? And then the second question was how did you manage to spend $4 billion less than you had thought you would during the course of last year?

Peter Voser

I’ll pass this one on to Simon and good afternoon, Lucy, anyway.

Simon McHenry

Hi Lucy. Thank you, Peter, thank you, Lucy. Just to reiterate the cash flow performance and targets, in 2009 it was actually adjusted for working capital $24 billion cash generation. That’s the basis for the (inaudible) and 80% growth targets at $60 or $80. Adjusted for working capital was 33 in 2010, and coincidentally, actually, ‘09 was roughly a $60 world and 2010 was roughly an $80 world, albeit in both cases with gas and refining margins below what we’d expect mid-cycle to be. Now cash flow in any given quarter or half, actually, is impacted by working capital. I think you need to take that into account when looking at any short-term cash flow generation.

Lucy Haskins – Barclays Capital

I think that even in making those adjustments, though, which I would agree – we always strip the working capital movements out – but certainly you seemed a lot closer to target sort of at the mid-year point. Now perhaps annualizing the Q4 would be unfair but even for the full year 2010 numbers, clearly you’re a bit farther away than you were at the midpoint of the year. And I just wondered if there had been anything exceptional in the first half or something exceptional in the second half that perhaps is dragging back.

Simon McHenry

Let me finish, Lucy, I was going to get on to the question: the impacts for the course. Of course the first half we were producing better in the Gulf of Mexico than we were in the second half. There was some impact there – (inaudible) left on the table. Tax payments typically are backend loaded in the year; that is an always ongoing effect. Those two effects definitely come through. Q4 against previous quarters, I don’t want to give you a very long shopping list but here are some things to think about: in the Upstream, around $450 million income impact from startup costs; higher taxes and royalties, and that’s on the income statement, not just paid – and that’s partly a reevaluation of deferred tax assets in Brazil; and also lower contributions from gas trading. The market’s just less volatile, and most of that in the Upstream showed in UA’s – it’s $450 million there. I talked about refining. The operational impacts basically left $200 million on the table. The DIE impact is another $200 million, and marketing of course is coming in $400 million below the typical trading range of $800 million to $1.1 billion that we’ve done in most quarters. When I say DIE effect, it’s effectively foreign exchange movement. When the Euro strengthens we get a benefit; when the Euro weakens we get a negative, and we’ve had very significant Euro/Dollar impacts this year. In fact, the absolute impact in Q4 wasn’t that big, so it’s really the comparative impact that you see coming through. It’s positive in Q3, negative in Q2, a year ago it was roughly neutral as well so that does introduce volatility. So yes, there are in Q4 several impacts that all feed through to the cash flow. Most of them, if not one-off they do not occur structurally every quarter in the same direction. So hopefully that helps.

And second area: how did we manage to spend $4 billion less? Well, we went into the year with a $28 billion capital target. Peter keeps in his back pocket a hold back to the $4 billion, which is the maximum flexibility that we had. During the year some of that was allocated directly to the smaller acquisitions that we made. The larger acquisitions were then effectively offset by the divestment increase. The Gulf of Mexico saved us in that sense $700 million in investment, and you will be pleased to hear we have (inaudible) some cost to that. We delivered a few projects, at least there’s a contribution from both (inaudible) and projects starting up early. We also chose not to do one or two things. So overall it all added up, and our aim was to manage the net investment and the balance sheet accordingly. And you can see the outcome hopefully in the results.

Lucy Haskins – Barclays Capital

Many thanks.

Simon McHenry

Thanks. And our next question?

Operator

Your next question comes from Jon Rigby from UBS. Please go ahead.

Jon Rigby – UBS

Yes, thank you. I’ve got three questions, hopefully all three of them are quick. The first is just its notable how little money you’re making in North America at the moment, and I guess some of that as you referenced is Gulf of Mexico. But I notice you’re still going to spend another $3 billion in tight gas. At what point do you start to reappraise that portfolio shift that you’ve been conducting? The second is, can you just have a guess at what you would think in normal circumstances your capital in service would be? And then the third is just a question – a long time ago it always seemed to be that certainly in Q4 Shell had a lot of costs coming in, and I’ve kind of worked under the assumption that the kind of tight centralization that had come into the business and the new accounting systems, etc., would do away with that. Can you just talk to how you can have fairly dramatic shifts in your booking costs through a quarterly period please? Thanks.

Peter Voser

Yeah, thanks Jon and good afternoon. I’ll take number one and three and capital service I’ll leave to Simon. Let me talk about North America first. I think making money, you can talk about it in terms of earnings or you can talk about it in terms of cash. Simon talked about the special stuff in Q4 and there have been results obviously in North America, etc., so we are driving the operational performance and we are driving actually quite clearly our assets to top performance excluding obviously the Gulf of Mexico issues which we have had. So if you actually would take a cash view on this, the Americas’ UA actually performed rather well, substantially above the earnings as most of the (inaudible) which we had were actually non-cash items, etc. So I think the way we or I manage at the moment, UA is clearly on a cost basis but also on a cash basis. We obviously keep earnings in mind but that’s really how we are driving it, and I’m pleased with the way they’re performing on the gas side in terms of optimizing cash costs and costs in general. I’m pleased with the progress on total costs related to the rest of the portfolio. I have to say obviously as we have AOSP startup across the first half of 2011, so we have combined startups and the upgrade is still to come. We had higher costs for that but we didn’t get the revenues – that had obviously quite clearly an impact. So all in all I think we are on the right track, measuring the cash earnings which are substantial, and therefore I think I’m pleased with the progress so far.

Also we have in the UA actually the highest percentage of non-productive assets given our acquisition drive and our investments over the last few years. It is actually higher than in the rest of the group, so if you look at returns, pure earnings returns you need to take that into account as well. On the cost side, I think we have improved because indeed in the past this was a little bit of a problem for Shell, with the centralization of the systems and the way we actually monitor our monthly accounts. We have improved which is maybe not everywhere completely done, but we have improved considerably over the last two years. I wouldn’t say that this is our biggest problem in Q4. I think some of the operational things which Simon said were much more kind of on our minds when we looked at the results, and where we always check that we have to write strategic initiatives and ways to sort out a few things which we still have to sort out. So yes, it’s a problem which we know. It’s a problem we have worked on quite a bit and it is getting better. We are not yet completely there. Capital in service I’ll pass on to Simon.

Simon McHenry

Thanks, Peter, there is some linkage between the questions as well. The capital assets service at the yearend on the balance sheet was $194 billion of capital employed. We had $44 billion working progress projects ready to roll hopefully in the next year or so; more than half of that is in Qatar and Canada Oil Sands because the (inaudible) is not yet operational. It will drop clearly, as those three projects come on stream; it will then go back up again as we continue to invest. This is our business model so that number will not reduce to zero. It will probably run at a level below $44 billion, but more towards $30 billion maybe plus or minus next year as it goes forward.

We also have around $19 billion, $20 billion of lease bonuses or acquisition premium. For example on leased resources, lease bonuses and some of the acquisition premium we do amortize anyway and because it’s in North America, that amortization before we actually produce does impact the results. So there is an impact there that drives earnings down but has no cash flow impact in our Upstream America results. That piece of capital becomes active as we bring the assets into production, so the piece in the gas, particularly the unconventional gas, as we develop and produce leased resource acreage for example, that will produce and returns will increase. So quite closely linked answers. I don’t know where that $19 billion to $20 billion will go. I hope we continue to acquire new acreage going forward at a similar level to that which we have done recently.

Jon Rigby – UBS

Okay, that’s great. Thank you.

Simon McHenry

Thanks.

Peter Voser

Thank you, Jon. Next question.

Operator

Thank you, and the next question comes from Alan Define [ph] from Citi. Please go ahead.

Alan Define [ph] – Citi

Thank you, Peter and Simon. Can I ask you a question on refining because it’s sort of eight or nine quarters now of losses in that business, albeit at the bottom of the cycle? And I guess my question relates to the profitability doesn’t look anywhere near as robust as some of your peers, and I wonder how you think about the 2012 cash flow targets in that context.

Peter Voser

Yeah, thanks Alan. I’ll take this from a strategic point of view. We have clearly outlined and now we are rationalizing the portfolio and I have mentioned all these numbers. I think we are well on track there. The majority of our cost savings actually is coming out of Downstream and a good proportion is coming out of the refining. We’re adjusting always to this new refining capacity which we have and that takes its time. We had these outages and relatively high turnaround work in the Q4 but clearly there is more to be done on the refining side, but we have all of that at hand or in hand and we are moving forward to that. As I have said in previous calls and previous talks, the strategy update in March will be kind of the next news of Downstream, how we take it forward, and I think once we have embedded our current portfolio of refining there might be more to come on that side. But we’ll talk about that either in March or further down the road when we are getting to that.

So a lot has been done. Availability was high, etc., but we have some locations where we have disadvantages – some of them are out of the system, some of them we are still working so we need a little bit more time here. But it’s clearly part of our integrative strategy, and hence we need to make sure that we have got the right size of refinery with the right throughput and the right overall complexity. And we are working on that. Some new stuff is also coming on stream which will be helpful in that sense as well.

Thank you. Next question, please.

Operator

Thank you. And the next question comes from Oswald Clint from Stanford Bernstein. Please go ahead with your question.

Oswald Clint – Sanford Bernstein

Yes, hi, good afternoon. Maybe just one on chemicals and specifically the new MOU you’ve signed in Qatar. Obviously chemical returns are generally roughly around the cost of capital over the cycle of these projects. Can you confirm that this new project in Qatar is going to benefit from advantaged feedstock raw materials through the natural gas stream? And then secondly you talk about your natural gas there and certainly tight gas and expenditures in the US. I know you’ve been testing some areas specifically across in Europe and in Sweden. I just wonder, you didn’t mention it today, I wonder if you could talk about some of that unconventional gas exploration.

Peter Voser

Yep, thanks Oswald for your questions. On the first one if I heard you correctly saying you were kind of also implying that we’re taking advantage of lower capital costs, etc., so I think we’ll see how these will develop over the next few years. On the feedstock question quite clearly we do these together with QP and therefore we go from gas to chemicals, which has its advantages. We have signed the MOU; we haven’t signed the (inaudible) agreement and the final agreement, so I think we will give you feedback once we have done that. But I think one of the advantages of doing this in Qatar is around the pricing of the feedstock but too early to talk in details about it.

(inaudible) our unconventional gas, clearly we have talked about North America where we are making good progress. In terms of Europe, Sweden, that’s exploration pilot stage – we’ll inform once we have converted there so it’s too soon to say. It is, I think in general in a way a slow pace in Europe. There are quite clearly footprint issues, there are permitting issues, not just in Sweden but in many other areas so we’ll see how this develops. What is much more exciting is China and that’s where we have got quite sizeable square kilometers of acreage which we have, actually at the end of the Q4 we started to actually reach the explorations. So we’re very excited about those two blocks for shale gas, tight gas, and the one block for CBM. And we think China has got quite a bit of potential in that sense, and we’ll report back on that once we are further in the exploration phase.

Thank you. Next question, please.

Operator

Thank you. And the next question comes from Alejandro Demichelis from Merrill Lynch. Please go ahead with your question.

Alejandro Demichelis – Merrill Lynch

Yes, good afternoon, gentlemen. One question: maybe you can touch a bit more on what you’re seeing in terms of cost increases, not just for this year but the trends for you on those growth projects; and how much of those cost increases you think that could offset the cost reduction that we have seen in Shell oil the past couple of years?

Peter Voser

Thanks, Alejandro. I’ll give that to the guy who manages a lot of these kinds of things, to Simon.

Simon McHenry

Thanks, Peter, thanks Alejandro, good afternoon. Since 2008 the cost pressure or inflation did come out of most categories in the industry but is now returning. Two categories that we see significantly impacting the industry are steel and rigs. Steel impacts about 30% of our capital costs; rigs is also a significant element – we’re spending somewhere between $7 billion and $10 billion a year. The costs for 2011 are largely locked in. Our rig costs for the next two to three years, and in some cases out five years, are also largely locked in at reasonably attractive levels. Our average day rates on the fourth and fifth generation deepwater rigs is below $500,000 a day on average, well below in fact. We cannot completely mitigate against steel price rises that we see. Having said that, one significant advantage of our new organization has been the development and perhaps more importantly the execution of global strategies per category of contracting spend. We spend around $60 billion with third parties each year. We developed category management strategies and global framework agreements, now over 100 global framework agreements with key suppliers, which is driving our costs down and often have imbedded in them low cost country (inaudible) such as from China, Mexico, and elsewhere. And that impact is so far offsetting the inflation we see coming back into the market. This does take careful management with (inaudible) suppliers but we’re hopeful that we can not only continue the downward trend in OPEX but avoid significant inflation on the capital account as we take new investment decisions going forward.

Alejandro Demichelis – Merrill Lynch

So if we have to look at the absolute overall costs, we can see that that trend of cost reduction kind of changing here.

Simon McHenry

Well, it’s difficult to see, it’s even difficult for us to manage the actual unit cost of any given unit of activity. But for example in onshore gas drilling we know we drive the cost down through better performance over time and we shared that with you before; offshore drilling equally over time in any given activity, we do take costs down. Each large project tends to be unique and difficult to benchmark. What we’ll aim to do and do aim to do is to benchmark the project at the point which we take decisions and at the point at which we deliver them. And I can share with you that our benchmarking done by the IPA does show us significantly improving in both Upstream and Downstream projects over the past four years. We’re in a reasonably good position there and we intend to stay there.

Alejandro Demichelis – Merrill Lynch

Okay, thank you.

Peter Voser

Thank you, Alejandro. Next question please.

Operator

Thank you. And the next question comes from Irene Himona from Societe Generale. Please go ahead with your question.

Irene Himona – Societe Generale

Yes, good afternoon. I have two questions please. First of all the depreciation charge year-on-year is up roughly $1.1 billion. Is that clean? Are there any impairments in there and should we expect a similar increase in 2011 as the new projects start up? Secondly, I don’t know if you can update us at all on organic reserve replacement? I suspect not, in which case I actually have a third question which is this: that pre-2004, ‘05, Shell used to have serious and persistent operation problems in its refineries, particularly in North America, then you appeared to have resolved that. It seems to be back. Can you talk a little bit about the specific operational problems that you’re encountering in Q4 and Q1 2011? Thank you.

Peter Voser

Yeah, thanks Irene. I think I’ll leave number 1, the depreciation, and number 3, the refining to Simon, and I’ll take the middle one which is an easy one. We will, as in the previous years, we will give you those numbers when we have the strategy update, i.e., when the (inaudible) comes out around the same time.

Irene Himona – Societe Generale

Okay.

Peter Voser

The depreciation and the refining and what exactly has happened in Q4 and Q1 to Simon.

Simon McHenry

Thanks, Irene. 2009, 2010 depreciation both had impairment impacts, and if you remove the impairment the impact was also an asset sale impact. The underlying deprecation went down slightly from just over $12 billion to just under $12 billion. It’s a fairly constant $3 billion per quarter charge – no expectation that will change materially in the coming year, although as the big projects come on stream you will start to see that nudge out. I can’t speak for pre-’05 activities in the Downstream, but in Q4, specific issues on the refractory linings, furnace linings and cat crackers in Port Arthur and Purnette [ph] driven basically by faulty equipment supplied five years ago. It should have lasted 25 years, now it needs replacing after five. This is an industry problem. One of two of the competitors got exactly the same issue with the same supplier, so not endemic. One or two of the other trends we’ve had unfortunate, as Peter said we’re not satisfied with the performance we’ve seen, and we see it as a bump on the road more than an endemic issue with the manufacturing sites.

Peter Voser

Thank you. Next question.

Operator

Thank you. And the next question comes from Deepan [ph] (inaudible) from Morgan Stanley. Please go ahead with your question.

Deepan [ph] – Morgan Stanley

Yeah, hi Peter, Simon. A couple of questions actually: just coming back to startup costs, I imagine that’s sort of increased through the year. I was wondering if you could give some sort of guidance of how you see that sort of let’s say twelve months on from here, or how you would suggest we model that into our numbers. Just a sort of follow-up just in terms of the Upstream, any thoughts on how maintenance levels will be in 2011 relative to 2010? Do you see increased levels or not? And then a question perhaps for Peter: I mean you’ve talked about the disposal program slowing down. I can understand that perhaps in the Downstream but looking at the Upstream it does seem to be a seller’s market. I was wondering if you could give some thoughts around why perhaps Shell shouldn’t look to use this as an opportunity to monetize its let’s say bottom quartile assets.

Peter Voser

Yeah, I think, Deepan, I’ll start with the last one and give Simon a little bit more time to think about one and two. Portfolio management is key – from that point of view, no change in the strategic emphasis we are putting on the portfolio management. Clearly we have a growth strategy in order to deliver actually production growth over time, so there’s quite clearly- This is a distinction to some of the talks which are in the market about shrinking. I find shrinking rather easy; growing is a little bit more difficult. So from that point of view we do clearly look at portfolio management. “Slowing down,” what I said is I just don’t want you guys to think that we will do another $8 billion or something like that in the next twelve months. We will do $5 billion and then we’ll see how the market is over the next 12 to 24 months, and then guide you further. For the moment it’s $5 billion to $11 billion, and in long term I think go back to what we always have given as a guidance, which is slightly lower than that. But we are kind of clearly focused on it, and if the market is right we have known (inaudible) assets or later life assets, we will not be shy to turn the portfolio over in the near future. But we will clearly keep a focus on growth and this is as we always said, a clear driver for our 80% increase in cash flow and an $80 world by 2012, and we will make sure that we actually deliver that. So I’ll turn questions one and two over to Simon.

Simon McHenry

Thanks, Peter. Startup costs broadly speaking were around $200 million in the Upstream in Q4. You can expect that level to continue into the Q1 as we start up the upgrades in Canada and the two projects in Qatar, and basically the work, what we’re doing in Iraq. It’s a bit plus or minus but it is on the order of that magnitude. It will go down by definition as we get into the second half of the year, and that’s a pre-tax figure of course. Divestment, sorry the Upstream maintenance levels – we have no expectations that maintenance levels will be any different next year from what they have been this year. The two biggest issues in our Upstream have been fundamentally Nigerian availability largely driven by security, and Gulf of Mexico return to activity. The rest of the portfolio is pretty much on track and is actually operating very well.

Deepan [ph] – Morgan Stanley

Great, thank you.

Peter Voser

Thanks, Deepan [ph]. Next question, please.

Operator

Thank you. The next question comes from Kim Fustier from Credit Suisse. Please go ahead with your question.

Kim Fustier – Credit Suisse

Hi, good afternoon, gentlemen. I have two questions please. First is could you talk a little bit about the Associated Gas deal in Iraq and whether you are confident that it will be finalized by the end of this month? And secondly, can you talk about the delays to sanctioning and CAPEX overruns in cash against these two, and whether there’s any scope to relaunch the project? Thank you.

Peter Voser

Okay. Good afternoon, Kim, I’ll take both of them. On the south Iraq gas deal, I think as we always said there are great, great benefits to the Iraqi people, especially Basra area in getting on with this project to generate domestic gas for power generation, and later on export either LPG or LNG. We have had various rounds with the governments and I think you’re referring to say most of the press releases or press statements I have seen that it is ready by the end of February. I would just say that we have well progressed, negotiated. It’s up to the Iraqi government to come to a conclusion and resolution, so the timetable is in their hands. I cannot say much more other than that at this stage but I am somewhat optimistic that we will get it over the line soon.

On cash against (inaudible), I guess first of all we’ll let ENI work and catch the first phase of three. I think this is (inaudible) pre-FID. We are looking into various options, could me modularized, could be projects – we are in that phase at this stage and too early to talk about it for the longer term. So I think we’ll update on this once we go further on the pre-FID work. So not much more to say on this one. And thank you for the questions, and the next question, please.

Operator

Thank you. And the next question comes from Iain Reid from Jefferies. Please go ahead with your question.

Iain Reid – Jefferies

Good afternoon, Peter and Simon. Can I ask a specific question about Nigeria? You’ve obviously been selling undeveloped discovery certs to indigenous companies. I wonder whether you’re going to get past that or further than that and dispose of any of your existing production given the fact that as you said earlier, it’s fairly low margin. And second question about Australia: perhaps you can just tell us how close you are to FID on Prelude and whether you can give us any indication of what the costs of that might be; and also where you are on the coal bed methane Arrow development. Thanks a lot.

Peter Voser

Okay, I’ll take the second one and the first one, Simon can take on Nigeria. On Prelude we’re making good progress in the oil feed discussion, and as we have said this is a key FID target for 2011. We’re getting closer to it and the prime work at the moment is clearly down around the technical side but also around the costing side, and as you know we do not disclose costs per project in any project. But I think I would summarize it as we are making good progress on A) advancing it, but B) on also optimizing the costs. So the second one was FIDs in 2011. Arrow making good progress. You may have seen some of the press releases from Arrow. We are inviting companies for the feed; that should happen during 2011. And as usual we will update on the progress of what’s happening in Arrow to turn (inaudible) CMPC during the quarterly calls to come. So not much more at this stage to say on that one. Thank you, and over to Simon.

Simon McHenry

Nigeria – unsure. We have 38 blocks overall, a very widespread portfolio across an area with a population of 35 million people and an area that exceeds the size of Belgium. So it’s a very broad and diverse footprint that we have. Our strategic aim has been to reduce the size of the footprint by increasing the participation of Nigerian companies and stakeholders in the production activity. Of those 38 blocks last year we sold four blocks – the results of which are in the 2010 financials – and we currently have another four blocks on offer and that’s what you may have seen some press about recently. We still have 30 blocks. The blocks sold and for sale represent less than 10% of our production there, so we’re really reducing the footprint, increasing indigenous participation in line with the Nigerian government’s objectives as well, it has to be said. We don’t have an intent to significantly change further the footprint. We’re focusing on the core oil and gas areas, and that’s the strategy as it stands today.

Peter Voser

Thanks, Simon. Thanks, Iain, and next question.

Operator

Thank you, and the next question comes from Mark Gillman from Benchmark. Please go ahead with your question.

Mark Gilman – The Benchmark Company

Simon and Peter, good afternoon. A couple things: Simon, I wanted to go back to a comment I thought I heard you make in response to a question regarding 2011 DD&A being roughly comparable to 2010 on a clean basis. Can you clarify that and explain how that is possible in light of incremental (inaudible) and plural DD&A, which are quite sizable? And I have a follow-up.

Simon McHenry

Okay. Put simply, both the upgrade and pearl [ph] will be straight line depreciation, not units of production, which means they don’t kick in at a heavy level; plus, and this is not a projection at all – track record of adding reserves recently has generally meant that the depreciation has gone down slightly in the Upstream year-on-year. So without giving anything ahead, that plus the fact that the big two are straight line means we won’t see a big step up during the year.

Mark Gilman – The Benchmark Company

Okay. I am I guess a little bit confused by a comment in the presentation regarding the exploration results in 2010. Eight discoveries yielding net 250 million equivalent of resource suggests that this is not exactly a high impact kind of program. Am I mixing apples and oranges by putting those two things together?

Simon McHenry

You could be there, Mark. We haven’t given the total resource add from the exploration program. The added discoveries of course which we have from the tight gas activity, we’ll give the figures when we finalize them in the March presentation. The 250 million refers to Appomattox, which is a single discovery, the single largest discovery in the Gulf of Mexico.

Mark Gilman – The Benchmark Company

Okay, one more, just one more from me. The integrated gas earnings in the Q4 were sharply below anything that we were looking for. Can I assume that that is where the lion’s share of your referenced startup costs have hit?

Simon McHenry

No. Basically it’s a dividend from one of the LNG companies that was large in Q3 and absent in Q4, hopefully back again in Q1; plus the ramp up in volumes was Nigerian which was effectively going into spot markets. So the actual average realized LNG price was down on average slightly for the quarter.

Mark Gilman – The Benchmark Company

Versus Q3 or…?

Simon McHenry

Versus Q3, yeah, I’m talking about Q3, Mark, as opposed to year-on-year. The realized gas prices were quite significantly up year-on-year versus Q4 2009. Sorry for not being clear.

Mark Gilman – The Benchmark Company

Okay, thanks Simon.

Peter Voser

Thanks, Mark. Next question.

Operator

Thank you, and the next question comes from Jason Campbell from Macquarie. Please go ahead with your question.

Jason Campbell – Macquarie

First of all with the Gulf of Mexico and Alaska now I guess more or less off limits for the next two years from an exploration standpoint, can you talk geographically about where you could have high impact exploration? And then secondly, given the huge discrepancy on a BTU basis between natural gas and liquid product globally, would you be looking to invest incrementally in gas-to-liquid projects?

Peter Voser

Okay. The first question, I think I didn’t say that it is off for the next two years but I said we are actually the first company that has three exploration wells kind of in the public discussion now. So they have fulfilled all of their agency requirements as published through a press release last Friday by the authorities, so we are in that phase. So we are really hopeful to get back into the Gulf rather sooner than later. And actually I said clearly again, it’s not two years; it is for 2011. We are preparing the permits so we can actually drill in 2012. I just don’t want to spend the money as we naturally still have uncertainties and we would have to spend $100 million, $150 million between now and getting then maybe no answer, and then we would have to actually dismantle what we have already built up and prepared. For all the rest of the exploration I think we will give a key update in March as well. You can obviously see in the presentation slides there are some indications there where we have clearly some new acreage, etc., but we will give you a clear overview on how the exploration program will exactly work in the March presentations. Can you just repeat your second question?

Jason Campbell – Macquarie

Just given the large discrepancy in pricing on a BTU basis between natural gas and liquid products, would you consider incremental investments in gas-to-liquids?

Peter Voser

Yes, thanks for that. I’ve always said I want to finish (inaudible) start it up and have a very smooth kind of transition into full production there. Then we can have another look at what’s possible. The most logical one will be a train 3. As you know we are constructing Pearl [ph], it’s actually weighted and tie-ins for train 3 are already there. The land is also booked and reserved, etc., so that’s quite clearly the one which would come to mind for the next step. Therefore your answer is yes; if you have the right countries, the right reserves, the right pricing. So from a feedstock point of view then that could be attractive, but I think let us finish Pearl [ph] first and operate and then come back to that.

Thank you. Let’s go to the next question.

Operator

Thank you, and the next question comes from Jean-Pierre (inaudible) from (inaudible). Please go ahead with your question.

Jean-Pierre [ph]

Yes, good afternoon, gentlemen. I have three questions. First question: can you indicate for us what were exploration expenses in 2010 and did you exceed budget plans for 2011? My second question is regarding the concessions in Abu Dhabi which is expected to expire by the end of 2013. If I’m right can you indicate to us assuming that the concession is not renewed, the possible impact on your product churn and what would be your new 2014 prediction guidance and the impact on your earnings? And my third question is regarding your dividend policy. You are expecting a stable dividend in Q1, 2011, that is this quarter. What are the key drivers that may increase your dividends for the (inaudible)? Thank you.

Peter Voser

Okay. Well, I’ll give questions one and three to Simon; I’ll take two. Simon, you want to start?

Simon McHenry

Yeah, I’ll start. Exploration expenses are getting tricky to add to the report now because our unconventional gas activity becomes exploration or development, almost well by well depending on exactly where it’s drilled in terms of recognized reserves. So I’ll speak in more general terms. The amount allocated by budget was just over $3 billion in 2010, again in 2011 for two exploration activities – that’s seismic and drilling – about half of that is spent on drilling. So no real increase. What actually gets reported as expenses does vary for that reason in unconventional gas. Abu Dhabi, so sorry, I’ll leave Abu Dhabi for Peter. The dividend – the key drivers of the dividend. The dividend policy that we restated last year will grow in line with earnings and cash flow. We also said it is our intent to manage cash flow by 2012 at $60 such that we earn from cash from operations enough to support $25 billion to $27 billion of net investment and $10 billion of dividend. The big drivers of that cash flow growth to get us back to that likely equilibrium position are the projects, as we go through this year the big three projects that target cash flow – the two Qatar projects and the Canadian Oil Sands – should ramp up, that’s what we expect as of when they come on stream. That plus the ongoing oil price development will drive the discussion about dividend growth. Peter?

Peter Voser

Abu Dhabi, it may be too early to talk about it, but the fiscal terms are based on a tax royalty structure with a fixed post-(inaudible) earnings of $1 per barrel lifted, and yes indeed, the production license expires in 2014. And we produced 132,000 barrels in 2010. I think with that you can do all your sums and your totals. Thank you very much. Next question?

Operator

Thank you. And the next question comes from Neil Morton from [Brannenburg]. Please go ahead with your question.

Neill Morton – Bloomberg

Good afternoon, it’s Bloomberg, actually. Two quick numbers questions, please. Firstly could you perhaps say how much of the OPEC increased in production in 2010 (inaudible) the weather year-on-year? I think, Simon, you have given us a profit impact on that as well – that would be useful. And secondly, could you quantify your expectation of production growth from new field startups and ramp ups in 2011 versus the 170,000 barrels that you achieved in 2010? Thank you.

Peter Voser

Yeah, over to Simon and thanks for the question, Neill.

Simon McHenry

Thanks, Pete. There were a couple of impacts that were out of our control in terms of OPEC demand constraints and the weather, basically a thousand barrels a day increase year-on-year 2010 versus 2009. If you remember it was very cold not only in Q4 but also Q1. It’s a lot warmer this year is all I can say on that. Sorry, could you just repeat the second question? I didn’t–

Neill Morton – Bloomberg

It was just your expectations for production growth in 2011 from new field startups and ramp ups.

Simon McHenry

Well we would hope it would be higher in principle because we should get the better part of the year out of Oil Sands and we should see the impact of full year, for example, of (inaudible) EVA, of Arrow and hopefully we’ll get back to [Perdito]; and the Qatar projects will start to ramp up. And I wouldn’t want to give a (inaudible) production forecast for 2011. We said broadly similar but with quite a wide range of potential outcomes, both positive and negative, depending on for example the weather and Nigerian security and the rate of those ramp ups. So it’s broadly similar plus or minus.

Neill Morton – Bloomberg

I had one clarification. On refinery availability in Q1, you said it was flat to lower. Was that versus Q4 or was it year-on-year?

Simon McHenry

Versus Q4.

Neill Morton – Bloomberg

Versus Q4, thank you.

Peter Voser

Thank you. Now we go to the last question.

Operator

Thank you. And the final question comes from Sergio Molisani from UniCredit. Please go ahead with your question.

Sergio Molisani – UniCredit

Yes, good afternoon everybody; three quick questions if I may. First on the tight gas – if I understand well you are guiding for the low part of the $3 billion to $5 billion total CAPEX indicated allocation on the North American (inaudible). If I am correct what is the right course we should take in terms of this decision in terms of gas prices you expect for 2011 and 2012? And second question is can you give us an update on the exploration in Brazil on the BMS-54? And the third question is a follow-up on a near question regarding the production guidance for 2010, ‘11. Did I understand well that you expect more or less a flat production versus 2010? Thank you very much.

Peter Voser

Yeah, thanks Sergio. I think Simon can do all of them.

Simon McHenry

Thanks, Peter. Does the low end CAPEX indicate low gas prices? Well initially to some extent yes. We’re drilling where we need to hold acreage and where we’ve already got the cost down to where we can make money at $4, and that’s what’s driving this. If the gas price goes up we’ll see where we can go. This is a relatively easy activity to ramp up. BMS-54 exploration, just a reminder there’s an 80% shell block; now we’re 20% in. We have two prospects to drill. We drilled one late last year; we hope to drill roughly the middle of this year the second prospect. There are two reservoir horizons in both prospects. We are currently evaluating the first well. It looks prospective. We have indicated this is not a multi-billion barrel prospect but it looks very interesting at the moment. We need to drill the second well and do the appraisal work before we can really say anything further.

2011 production – yes, the statement is broadly similar but with a wide range, a relatively wide range of outcomes. We actually increased our production in Nigeria onshore by around 100,000 barrels a day or over 100,000 barrels a day in ‘10 versus ‘09, in the current security environment and with both the EBA and the gas project up and running we could do that or better again in 2011. But there is an election in Nigeria this year and that’s a level of uncertainty. In the Gulf of Mexico we lose 50,000 barrels a day of high-value production compared to what we would have expected to deliver if there had been no moratorium. And we do not drive the pace at which we’re able to restart development and production drilling in the Gulf of Mexico. So it’s unfortunate but there are a significant number of factors outside our control.

Our aim and expectation for 2012, because we control most of the main drivers of 2012, is to deliver the 3.5 million barrels a day target, even though the divestments we’ve done will in fact reduce production in 2012 by around 80,000 to 100,000 barrels a day compared to what we had originally projected.

Peter Voser

Good, thank you very much, Simon, and thanks for all the questions today. And thank you for joining us for this call. We are having an Investor Day on the 15th of March in London with a global webcast. We will also make this more interactive with breakout Q&A sessions with our business leaders, and I hope to see as many of you there as possible. Thank you again for calling in and have a good rest of the day. Thank you, cheers.

Operator

Ladies and gentlemen, this concludes today’s presentation. Thank you for your participation; you may now disconnect.

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