Royal Dutch Shell plc (NYSE:RDS.A)
Q1 2012 Earnings Call
April 26, 2012 08:30 am ET
Simon Henry - CFO
Teplan Justalingram - Nomura International
Jon Rigby - UBS
Iain Reid - Jefferies
Martijn Rats - Morgan Stanley
Michele della Vigna - Goldman Sachs
Rahim Karim - Barclays
Peter Hutton - RBC
Kim Fustier - Credit Suisse
Jason Kenney - Santander
Lucas Herrmann - Deutsche Bank
Robert Kessler - Tudor, Pickering, Holt & Co.
Irene Himona - SocGen
Neill Morton - Berenberg
Welcome to the Royal Dutch Shell Q1 results announcement call. There will be a presentation followed by a Q&A session. (Operator Instructions). I would like to introduce our host Mr. Simon Henry. Please go ahead.
Thank you very much operator. Welcome to Royal Dutch Shell's first quarter 2012 results presentation. Good morning or good afternoon wherever you may be. I will take you through the results and the portfolio development for the quarter and leave plenty of time for questions. First of all though the cautionary statement.
Okay, quarterly results are important, but they still remain a snapshot of performance in a volatile industry where we are in the process of implementing a long-term strategy. First quarter earnings excluding identified items were $7.3 billion and also the earnings per share increased to 15% compared to the first quarter last year. With $2.4 billion of divestments in the quarter, we are increasing divestment target for this year from $2 billion-$3 billion range to at least $4 billion.
Underlying oil and gas production increased by 4% in the quarter. We started up new projects in Upstream and now in the Downstream for further growth and we continue to mature new options, mostly of course in the Upstream with successful drilling in the Gulf and new exploration acreage in the quarter. So this continues the progress we made on the new options in 2011, for example the Abadi floating LNG project in Indonesia and the additional liquid-rich shale positions.
The dividend for quarter one will increase year over year with the strategy delivering underlying and sustainable financial growth. So we are making good progress against that target to deliver a more competitive performance. To give you some more details, starting with the macro environment. And if you look at the macro picture compared to the first quarter last year, oil prices are higher. There is an increase in the differential between the Brent and WTI.
Our overall global natural gas realization, they increased from the first quarter 2011. Well of course the US Henry Hub related prices declined quite sharply. Our overall refining marketing and chemicals margins were all weaker for Shell year over year. Currently we are seeing a very mixed picture on energy demand. Oil prices have been supported by geopolitical events despite a market which in our view is fundamentally well supplied. We are seeing LNG demand increasing year over year led by Asia. In the US, a combination of improving economic conditions and low gas prices are now stimulating gas demand. But European gas demand remains weak due to the weak overall economic conditions and basically price competition with coal.
In oil products, our underlying volumes were flat quarter one to quarter one. Demand is being eroded in developed markets by high prices. Our volumes are flat in Europe and the US and a firm demand for branded fuels in Asia. Economic outlook remains very uncertain particularly in Europe where many commentators see the prospect of new recession. So those are the Q1 to Q1 trends. In aggregate a weak demand, a little evidence of fundamental year-over-year recovery or in fact much improvement since the fourth quarter of 2011.
Before I turn to earnings, let me just highlight that we published country level tax information for the first time yesterday. And Shell is committed to high standards of transparency to all stakeholders and we have had a number of questions from you on this topic and I hope if you access the information on the website, you will find this information useful and I will be happy to take any questions you might have on it.
Moving on to the earnings. Current cost of supplies, CCS earnings in the quarter including the identified items were $7.7 billion, excluding identified items, the earnings were $7.3 billion. Earnings per share increased 15% compared to 2011. On a quarter one to quarter one basis, earnings in Upstream were higher and Downstream lower. Cash flow generated from operations was $13.4 billion. Dividends in the quarter were $2.7 billion of which $1.0 billion was settled with the new shares under the Scrip Dividend program.
Now we are offering the scrip again for the first quarter 2012. We have recently restarted share buybacks in the quarter, the second quarter of this and as part of our overall strategic intention to offset dilution from the scrip. Scrip dividends have now totaled over $5 billion since we launched in 2010.
Just let me talk about the business performance in a little more detail. Upstream earnings excluding identified items were $6.3 billion in the first quarter and that's an increase of 35% versus the same quarter last year. The earnings were of course driven by higher oil and international natural gas prices, but also by volume growth from high margin new projects particularly in Qatar and positive environment for gas trading.
There were some offsets from higher costs and depreciation and lower US Henry Hub gas prices. The headline oil and gas production for the first quarter was 3.6 million barrels of oil equivalent per day and that is an increase of 4% excluding asset sales exit and price impacts. In addition we had some 80,000 barrels of oil equivalent per day of entitlement loss from profit-sharing contract as our lower entitlement kicked in the contract and milestones and high oil prices moved PSCs out of cost recovery mode. The LNG sales volumes grew by 17% quarter one to quarter one and not reflect basically growth from Qatargas 4 and Nigeria LNG. The year-over-year plant maintenance impacts were negligible in the first quarter, Upstream and Downstream.
During the second quarter, though, of 2012, looking forward there will be higher levels of plant maintenance activities on offshore sales in the Americas and Asia-Pacific and in Europe. This is expected to lead to a production impact, a negative impact, of some 50,000 barrels of oil equivalent per day across the second quarter and that's compared to the second quarter in 2011.
In Qatar, Pearl gas-to-liquids project continues to make good progress. We are on track to release full capacity in the middle of 2012 as planned. We are running planned maintenance on sections of both of the Pearl trains during the second quarter. These pit-stops, they are part of the startup phase of the project that clearly impact production. The three large start-ups last year -- Qatargas 4, Pearl and the Athabasca Oil Sands Project in Canada are capable of producing 450,000 barrel oil equivalent per day at their peak production oil capacity.
These three projects alone produce some 360,000 barrels a day in the first quarter. That compares with 130,000 barrels a year ago. So, clearly a significant growth for them and clearly also further growth to come. I would expect the three projects to deliver a fairly similar production level in the second quarter as first quarter this year reflecting the pit-stops I just mentioned.
Turning now to the Downstream. Excluding identified items, the Downstream CCS earnings were 1.1 billion and that's lower than a year-ago level. Our Oil Products results were lower than a year ago level but similar year-over-year numbers in chemicals. In aggregate refining, marketing and trading margins were all weaker compare to Q1 2011, somewhat less from the Raízen joint venture in Brazil and from lower operating costs. However, we did see an improvement in refining chemicals and trading conditions compare to the fourth quarter 2011, which is particularly weak quarter. Although marketing margins were weaker sequentially this was due to continuing rising oil prices and a weak demand environment.
Chemicals and refinery availability and manufacturing availability were both higher than a year-ago. They also improved against what was not a good fourth quarter. We’re expecting world-wide refinery in chemicals availability for the second quarter ‘12 to be in line with the second quarter 2011. These are better figures from Downstream overall, but clearly still a difficult environment and we’re just not where we want to be here.
So those are the earnings. Turning to cash flow.
Cash generation on a 12-month rolling basis was some $50 billion, including $6.8 billion of the divestment proceeds, with an average Brent price across that period $115 per barrel. Both the Upstream and the Downstream segments they generated surplus cash flow after the investment. And as a result, the gearing at the end of the first quarter sat at 9.9%. That compares with 13% at the end of the fourth quarter. And clearly we’re moving lower in zero to 30% range, as of course you would expect in strong oil price conditions.
Disposals are an important element of Shell’s capital efficiency and our overall portfolio enhancement program. And the divestment broadly matched acquisitions in recent years. And we’re making good progress this year with $2.4 billion of divestments in this quarter. We will also sign further deals but we will complete later in 2012. So as a result, we now expect over $4 billion of assets sales in 2012. That’s an increase, of course, from our previous $2 billion to $3 billion guidance.
We sold some $36 billion of assets in the last five years that have roll-over around 17% of our capital employed. And I’m particularly pleased in this quarter to welcome new strategic partner into our Prelude floating LNG venture in Australia, where INPEX of Japan, Kogas of Korea and CPC of Taiwan have now joined us. This partnership monetizes some of our Shell optionality at an early stage and are part of Shell’s plan for new growth in global gas.
Our organic spending guidance total of capital investment for 2012 remains at $32 billion, excluding as we said before, up to $1 billion dollar of spend assuming we get access to drill in Alaska this year. We continue to look for additional acreage positions in exploration and undeveloped resource positions. We spent around $0.6 billion on this in the first quarter. Quite likely there is more to come as we go through the air.
Let me update you of the progress on the growth portfolio. Production has now commenced at the Caesar-Tonga project in the Gulf of Mexico and the Pluto LNG project in Australia has reached ready for start-up status. Together, the two Upstream projects expected to add a total of 40,000 barrels of oil equivalent per day and 0.9 million tones per annum of LNG.
On the Downstream side, we just started processing crude in the Port Arthur refinery expansion project that will create the largest refinery in the United States. There are some 600,000 barrels a day of overall total refining capacity. These three projects are all part of the diverse portfolios -- some 26 projects we previously discussed that Shell is developing world-wide today. We are driving the target that we set for cash flow and production.
We also made progress, maturing new projects with medium-term growth potential during the quarter. We signed up over 77,000 square kilometers of acreage so for this year, including high potential frontier positions in deep water Nova Scotia in Canada, and Tanzania Offshore and in the Orange Basin in South Africa. In the Gulf of Mexico, we had good drilling results in the Appomattox prospect and this is a Jurassic reservoir, so new to the industry, we are just learning. So we are now estimating half a billion barrels of potential in this field and will proceed further upside potentials as we will drill new wells in the area.
Earlier this week, we announced an intended cash offer for Cove Energy plc in the UK and this was recommended by Cove’s board. This is part of a strategy to build up our presence in East Africa and Cove would mark our entry in Mozambique gas, and also new exploration potential in both Mozambique and Kenya. And the total cost for Shell is expected to be just below $2 billion. That includes the price to Cove shareholders and an estimate of the capitals gain tax charge.
So, good progress on the growth portfolio. Cove will be complete; we will add some comments on dividends. Shell has a strong track record on dividends; dividends are the company’s main route to return cash to shareholders.
Over the last 10 years, we have paid more dividends than any of our sector peer group, and absent further changes to the state of dividends we will still be the largest dividend payer in LP peer group. We haven’t cut our dividend for decades, and I would just like to reiterate, we maintained our dividend across the credit crisis despite the pressures we were under.
We used the balance sheet to maintain both the dividend and the growth spending in 2009-‘10 and that was in the period when many investors worried we would be forced into a cut. We have reduced our costs. We are delivering growth, and it is this structural improvement that is driving the increase in dividends that we confirmed today; that’s a return to growth after a pause in 2010 and 2011.
Oil prices have almost doubled since 2009 whereas refining margins and US gas price clearly have remained low or got lower. We as a company must look through the short-term volatility when we plan for dividends, and we take decisions on a long-term policy basis. There is no simple mechanical formula.
The resumption of the measured, affordable dividend growth that we’ve confirmed today reflects the improving underlying financial position of the company and the delivery of our strategy in line with policy.
So just let me summarize before we go to questions. First quarter earnings have increased from year-ago levels driven by operating performance, new projects and strong oil prices and this is despite the continued challenges for our industry in the Downstream and in North American natural gas pricing.
With $2.4 billion of divestments in the quarter, we’re increasing the divestment target for the year to over $4 billion. Our underlying oil and gas production increased by 4% in the quarter; we’re starting up new projects in Upstream and Downstream for further growth.
The dividend for quarter one will increase, with our strategy delivering sustainable financial growth and we continue to mature growth options and growth mostly in the Upstream. So making good progress against targets to deliver a more competitive performance.
With that, I would like to move to your questions. Operator, and please can we just have one or two questions each, so everybody have the opportunity. And operator, please could you poll for questions. Thank you.
Thank you, sir. (Operator Instructions) The first question comes from Teplan Justalingram from Nomura International. Please go ahead.
Teplan Justalingram - Nomura International
Two questions please; firstly, a very good number in integrated gas. And I am being greedy, but is there anyway to disclose the spilt between GTL and LNG or put in another way, could you give us maybe the delta quarter-on-quarter for LNG and some comments on whether you think result is sustainable going forward?
And secondly, dubbing the media headlines this morning that your intentions in Mozambique. Could you confirm whether you’ve already been in discussion with some of the existing players in Mozambique before you made a higher bid for Cove? And is it right to guess that you are pretty confident you are going to increase the stake beyond Cove? Thank you.
Integrated gas is indeed the main driver of the improved Upstream earnings performance and cash flow. It is of course the strategy playing as in action; we’ve been saying for sometime, this is core to Shell strategies, so we have increase of $1.35 billion or so in the earnings. Both projects are responsible for about 60% of that. The remainders is spilt roughly equally between additional volumes out of Nigeria and Russia, better pricing and better opportunities from cargo diversion, simply because we have more LNG to work with and of course the markets been fairly tight in the quarter.
So it is strategy coming into actions so in the same macro and the new asset would be basically sustainable. It’s also fairly robust given that as you’re aware probably aware majority of the LNG volumes and obviously the GTL volumes are oil price linked, so very little exposure by definition in the integrated gas segment to lower prices for example in the US or spot prices in Europe.
Media headlines on Mozambique and Cove. I must say, I have not read them, so I can’t comment specifically, but what we have said is firstly, the bid 8.5% effectively over the Rovuma area of one license. And it is agreed by the Cove Directors, but clearly there is a period to go before we can close that deal. So we are hopeful that we bring not only the right price to the Cove shareholders, but also the right capability to get the government approval which we need.
8.5% remains, comes a little low for a Shell presence and well hopefully will quite a large LNG development and we will remain interested in increasing from that level of involvement. I really can’t comment on whether we have or will hold discussions with individual members and the existing consortia either in that area or elsewhere. I will just confirm that, yes, of course we are interested, but one at a time; we must close the Cove deal first.
Teplan Justalingram - Nomura International
And can I just come back to your comment on LNG and Q1, you talked about it being a tight quarter and do you see that going into Q2 and beyond the 2012 please?
In general yes, although it is a bit seasonal. So the demand can come off a bit across the summer; depends on how warm it is in countries with lots of air conditioning. So in general, the demand is higher than it was a year ago. We will see Pluto coming on and a couple of other smaller projects like it would come on during the year, but most of the volumes already sold into long-term contract either various Chinese re-gas terminals opening up capacity expanding in the areas. It’s fairly strong in its demand for LNG at the moment, so as we look across the variety of markets we do expect the market to stay pretty tight.
Thank you. The next question comes from Jon Rigby from UBS. Please go ahead.
Jon Rigby - UBS
And just two questions; the first is, I noted your what looked a very pointed remark about your Downstream, that what sounded like a remark that suggested you wanted further improvement and I just wondered whether you could talk about what you can do excluding any kind of rebound in refining conditions albeit that of course they have improved in the second quarter. I say that in the context of a refining business and I think those barely make money in any quarter since 2007 or 2008.
The second is just on your commentary at the end on the dividend and the balance sheet I think you brought that is I take your point about where oil prices are, but as you said Downstream is not great. Are you generating a kind of a level of cash flow now which is pretty similar or in line with the kind of number that you aspirationally want to do mid cycle. So what are you thinking about how you will deal with what is a very impressive level of free cash flow generation that you now are starting to throw off? Thanks.
Thanks Jon. And Downstream, fundamentally the comment is driven by the fact is that further the capital employed in this quarter is (inaudible) of the earnings, so but the reference to that's not really where we want to be in the Downstream. We certainly seen some challenges in refining margins, but clearly we don't necessarily control those. Our aim in the portfolio has been, remains and probably will be to be in large complex refineries that are geographically well suited at Port Arthur for example and then in Rheinland (inaudible) but there are clearly still some challenges at the periphery and refining. Our marketing businesses typically have held up well, but there is weak demand to be fair in developed market. We need to make more of the positions we have. We need to ensure that we are meeting customer requirements at lower cost.
And I think there are an element of optimization of margin delivery around trading supply refining envelops, as we’re adjusting to feeding pretty much the same marketing demand with a lower refining capacity. So the some optimization we can do. Uptime in the quarter availability 94% in refining, so we've actually got better availability and we’ve had for quite sometime, the challenge is actually utilizing all of it in the challenging markets. And also just highlight as we go forward, clearly Port Arthur and Raízen contributing and hopefully going to contribute more over time because both of those effectively growing in the business.
Unfortunately there is no silver bullet, hence the longish answer, we have pull all of those levers to get the returns back to where we need it to be. And dividend point, as over the past in fact past 12 months and the previous quarter, the 12 months leading up to that our cash flow from ops excluding the divestments were 43 billion which coincidentally was the target that we set for 2012. Bear in mind now $10 billion nearly now $11 billion dividend plus the ongoing net capital investment expectation of 13.
And gearing is coming down we’re all doing a little bit of buyback. And clearly, we need to keep a couple of billion in the bucket for Cove assuming it goes ahead. And but just to be clear, the dividend is linked to the underlying structural cash flow is not linked to the gearing. And so put the gearing in the balance sheet to one side. So the underlying cash flow is coming through, but there is more to come as not more to come fleets through and then as we have said before the board has the discussion every quarter and it is sensitive to the comments they hear. So, let’s say as we go forward, no projection for when we consider a further growth.
Thank you. The next question comes from Iain Reid from Jefferies. Please go ahead.
Iain Reid - Jefferies
Just come back to the dividend statements, you just made. You probably see what Exxon announced the other today and Chevron and historically yes you have been the biggest dividend payer. But you are not going to be now with Exxon's increase and obviously they have got substantial buyback as well.
So I take your point on the kind of historical levels of what you paid out. But it looks like you are slipping behind some of your competitors now in terms of what’s going on today. So does the board take into account these kind of competitive pressures that obviously investors can switch their attention from kind of one dividend payout to another because obviously the announcements you have done, is looking at other companies in the same peer group. And secondly on US gas, is it possible to say how much of the US gas you are producing at the moment is non-liquid related i.e. pure dry gas and what’s your plans for investments in growing that number while Henry Hub is sort of leveled.
Okay. My arithmetic could be wrong but I think we still are the biggest payer, get to be competitive now and I accept that. We are still pretty high in the payout ratio and I think the moves we see are quite (inaudible). It starts at the level of the playing field a bit and the majors now that payout ratios are converging and so I guess it means game on for all on the same payout ratio, then we better stop growing the earnings and cash flow competitively, so good to say that we are in more of a level competition.
Iain Reid - Jefferies
Like if you add any buybacks, it wouldn’t be that level?
I am talking about the dividend buybacks are primarily the management of gearing and the balance sheet issue. So underlying cash flow growth will be the driver of our competitive position and that will directly flow through into dividend. And straight to your question, does the board take this into account, absolutely they do and they have been asking how do the Americans get away with so much lower payout and yields for quite sometime.
And US gas percentage in LRF, we have not a lot of production in the liquids-rich shales at the moment, almost all of our US gas is in practice dry gas production, the liquids-rich shale and associated production at the end of the quarter was just over 10,000 barrels at the end of the fourth quarter, sorry at the end of the year. At the end of the quarter it was around 40,000 barrels. So we are growing that quickly in the Eagle Ford area.
That figure does include the gas that comes with the liquid. So our aim as we go through the year, we are 240,000 barrels. So in terms of the first quarter onshore unconventional activity production, gas and liquids we expect that to grow through the year, but we are basically still in the process of switching drilling activity from dry gas to wet gas or liquid and difficult to project exactly what the outcome is, but the net impact is probably less volume in 2012. We will probably in 2013 and I will give you an update more specifically, I expect later in the year.
Thank you. The next question comes from Martijn Rats from Morgan Stanley. Please go ahead.
Martijn Rats - Morgan Stanley
Two questions from me; the FAS 69 disclosure in the 20-F shows that in the Upstream production cost excluding taxes went from broadly $11 on a per dollar basis to roughly $13.5, so that went up to something like 23% from 2010 to 2011. I was wondering whether you could comment on what is driving the change; are you already seeing significant costing insulation coming through or there are mix effects going on driving that OpEx per barrel figure?
And secondly, again in the 20-F there was a comment in the CEO statement from Mr. Voser where he writes, I believe we can get more value out of our assets at the time our processing facilities could be greater and there are significant savings to be realized in our supply chains. And I was wondering whether you could make any comment over the sort of broadly the order of magnitude of the additional value that he is talking about there and also sort of broadly the time horizon over which these additional savings and that additional value could be realized?
Martijn Rats - Morgan Stanley
Thanks Martijn, there are some homework there. Production increased 11% to 23% and fundamentally there are some mixed effects there. For example, oil sands comes on-stream so the first cost coming in gas and our cost per barrel and for example the onshore activity that I just talked about, the onshore gas is fundamentally higher and there's also some foreign exchange impact.
So all of those put together are really driving the costs. And plus I think there was bit or somewhat less deepwater production from pretty much the same cost base and that was in the condo related issue. So all of those statements led to the unit costs, but also I need to recognize that almost everything I said are in areas where fiscal treatments are relatively attractive as well, so we have more access to the price up side. So cost is only one side of the margins.
And the question on more value if we could get our up-time in the right place. We views numbers internally to have this discussion; if it’s somewhere between $2 billion and $3 billion so this play roughly equally between Upstream and Downstream. And that’s a gross margin, so prior to any additional cost.
And that’s fundamentally above either we believe left on the table from incidents that we can’t or should prevent in an operational sense or ways of just sustaining up-time longer in a safe and responsible manner on the assets which we operate. So that’s what we’re shooting for internally.
Supply chain benefit, definitely in the billions. We spent on third party goods and services last year $70 billion in terms of contracts placed with third parties, $70 billion. There is some inflation over there, but right now internally even including last year the potential for us to improve from some of the things we’ve been implement over the past three, four years such as the global framework agreement, aggregating our demand, simplifying our standards, improving the supplier relationship, sometimes integrating into the supplier relationships. You can see on the spend the $70 billion we ought to be able to take more out than we suffer cost inflation going into that number.
So some of that shows through in lower CapEx, some shows through lower OpEx. And potential remains, the forward potential in the billions of dollars. We don’t have a specific number for it. So I hope that gives you some size of the price.
Martijn Rats - Morgan Stanley
In terms of timing, would you expect that those savings and additional value can be delivered for measure that have been taken in the past or is this very much sort of an effort that still needs to be undertaken and alone we pay off over a number of years going forward?
With 90,000 people working in Shell and it can take some time to improve and engage and motivate 90,000 people. So I think that won’t happen overnight. Sometimes we need to spend a bit of money and sometimes we just have to learn through continuous improvement on the job. So that is not a one quarter program, but it is something we would expect to see over the next two to three years delivered into the bottom-line.
Thank you. The next question comes from Michele della Vigna from Goldman Sachs. Please go ahead.
Michele della Vigna - Goldman Sachs
I just had a very good question. You mentioned Alaska; I was wondering what the key thresholds are for you to be able to start the drilling there and what kind of potential size you are looking for the exploration targets?
That is possibly the most important single milestone for this year. What did it take to drill? There are three things we are working on. One is operational effect, second is regulation and third is the legal or the litigation access.
Operationally, we plan two rigs and around 35 other vessels which will provide all the support and logistics excluding including the two rigs either (inaudible) Alaska, on its way to Alaska at the moment. So it’s that huge logistical exercise and bit like moving a fleet into the Alaska motors. So operationally, this is not easy operationally, but we are on track.
And the second point regulatory permit, significant number of permit required everything from exploration and air quality permit. All regulatory permits are either we haven’t we expect to receive in good time to be able to start drilling in the end of third quarter.
And in Alaska, we have an expected size of prospect that we have actually invested around $4 billion to-date in Alaska, so you could be fairly sure that we are looking for something big enough to justify that level of investment and that the systems that we have had to show over the five or six years in which we have been prepared to drill.
So the third challenge, I am afraid is a legal one and this is the US where we have well no control to not necessarily and too much of affirm due about what the outcome might be, what we have seen in previous year is that some around that have launched legal action at the last minute in quarter not are necessarily predictable and not others let the difficulties in going forward.
This year we have invited the court to consider the litigation that we expect in good time such that the due process can be considered exploration plans and other regulatory processes can be considered by the court in Alaska in good time to give either yes or a no to the plant during the third quarter.
Now that does not rule out unpredictable events in the US legal system. Having said that, we are confident that we are ready, willing and able to drill and that we can do so and as per safe and responsible manner and we look forward to a successful campaign this year.
Thank you. The next question comes from Alistair (inaudible) from Citi. Please go ahead.
Can you talk a little bit about the financial framework in which you view the Mozambique acquisition around, some indication of how you think about processing et cetera and then and returns and then secondly unrelated, can you just remind us what contribution and when you are expecting from the Port Arthur upgrade this year?
The financial framework around Mozambique, that's better to (inaudible) initially and the strategic framework, current LNG market is 240 million tons per annum. We expect growth in the next 10 years basically to 400 million tons per annum and there are significant number of projects already filling that gap, but we expect growth beyond that potentially to 500 and beyond as a result of our assessment of the gas markets in countries that are likely to import LNG. It’s a huge market. It is growing.
Our current capacity is 21 million tons per annum. Our amount under construction is seven and we are looking at 15 million tons per annum excluding Mozambique of new potential projects. So we need to do a significant number of new projects in addition to our projects already under construction, just to keep the market share and what is a fast growing and attractive business witnessed the $2.4 billion in the integrated gas segment in the previous quarter. So there's great returns, good project, long life cycle and Shell is clearly a significant and very competitive player, the largest private player in this attractive industry.
So financial framework got to be said in that context. If we’re successful in entering Mozambique and the project goes ahead then we would be looking at ranking that against other LNG opportunities. We can't do everything I have just talked about but we will do the better ones though. So it actually provides a bit of diversification in the portfolio away from Australia for example where all our projects under construction today are actually in Australia although many of those we’re now looking up or not such as Canada, Indonesia and hopefully now Mozambique.
And pricing in return there is no reason why Mozambique should not be as good as if not better than our current LNG projects. Clearly the entry cost is only going to be a small part of the overall investment because a large LNG development has huge capital investment associated. And we don’t need to figure for that, you need to ask the operator. But they took a 17 to 30 TCF and potentially 30 million tons per annum of LNG. So would be significant investment that would need to rank against other alternatives.
On the balance sheet in general clearly the 2 billion is affordable, but the increase in the asset sales is not entirely unconnected with the potential to add new assets to the portfolio. So as we monetize either non-core assets and always dilute them, smaller shares and important asset under construction, that enables us to recycle and expand the diversity in the portfolio. And so that you can say it both strategically and financially.
At Port Arthur and some of the Downstream units are working, already with finished product, the distillation unit has crude cycling at the moment and the hydrocracker will start up by the end of the quarter. Collectively probably not a huge impact on the second quarter, should start to see some contribution in the third quarter.
Please just do remember it's actually embedded in a 50:50 joint venture with Saudi Aramco. So we just see the equity share of earnings in multiple joint venture. At the moment the margins may be not that attractive in the Gulf Coast but over the cycle we expect Port Arthur to be a significant contributor to the Downstream earning.
Thank you. The next question comes from Rahim Karim with Barclays.
Rahim Karim - Barclays
Two questions, if I may. The first was just around the cash flow for the quarter and on an underlying basis, as to working cap, we saw a small decline year on year. It seems to do with cash paid. I was wondering if you could just give us a bit more color on that and how you see that moving forward, whether we should expect an increase in the cash tax rate. I mean, whether that relates to power or anything else, if you can give us any color on that. And then secondly on the Gulf of Mexico and actually apologies for the pronunciation, if you could perhaps give us some color on when we could expect FYD, what potential upside in terms of resources there?
Two important questions. The CFFO for the quarter at $13 billion basically the same as it was last year excluding working cap. The primary difference there is actually the tax paid, you are absolutely correct. Tax payments tend to run in line with previous year's profit. So it goes in 2011, the profit was higher than it was in 2010. So there is an element of, yes we paid them all, but then last year we earned more.
Going forward and it is not impacted by things like Qatar although Qatar is clearly in a profitable situation at the moment and paying tax. So what can you expect going forward while the quarter or quarter variations won’t be so high and over rolling twelve month basis, the cash tax paid catches up with broadly speaking the earnings.
There are also some one-off effects where divestments don’t always carry the same overlaid tax rate effective, effective tax rate as the underlying earning. So it should structurally improve going forward. Gulf of Mexico exploration, we talked about Appomattox doubling the potential resource there up to 500 million barrels, but we are just reflecting, we are bringing Caesar Tonga onstream. Well in fact Anardarko brought it on stream forward in March. We are building [Mozambique] and Cardomom and also BC-10 Phase 2 in Brazil.
And we have three opportunities in the Gulf of which Appomattox is actually largest, but Stones and Vito are on the other two that we are currently appraising ahead of hopefully FIDs in the not-to-distant future. Appomattox is the largest, is also probably the most uncertain because it is in that new East Gulf area in the Jurassic Play. We are appraising, we will, we have just appraised the driver of the doubling. We will drill hopefully another couple of wells in the area and we already have the Vicksburg discovery also in that area. We 75% or 80% Shell working interest and quite a bit of acreage in the area and we are fundamentally aiming to appraise and understand that area. While we progress all three of those prospect towards FID.
Our aim generally in the Gulf is to create the production line of assets where we design and won't build many, in terms of the surface and sub-surface facilities. And we are doing everything we can to bring investment decisions forward but probably so potentially large and uncertain that we are probably several years away from investment decisions.
And worth also saying on the Gulf actually, we stemmed the decline post-Macondo. We have not started to grow it again, but primarily Perdido stem the factor there. We are now 90,000 barrels of oil equivalent per day in Perdido, which is good to see. And still further growth to come peaking probably next year on Perdido. So thanks for that. Good opportunity just to get over a few end of the Gulf. A very important area of 50,000 barrels a day below where we would have hoped to be. It’s being slower to get back to operation there but we do have five floaters drilling at the moment, four platform rigs, one floater new deep-water rig and a testing mode, and we've got another along the way. So by the end of the year, we hope to have seven floating deep-water rigs.
Thank you. The next question comes from Peter Hutton from RBC. Please go ahead.
Peter Hutton - RBC
Hi, Simon. Couple of quick questions, actually both in the U.S., one in the Upstream, one in the Downstream. The possibility in the U.S., the low $10 a barrel pricing. Now, you’ve spoke about reducing the investment in tight gas. Are we seeing any adverse impact in the volumes yet? And what else might be is in those numbers that might be affecting this quarter? I wonder whether any of the costs associated with Alaska is showing its operating cost. Was that -- is that fully features CapEx at this stage.
Second question is you also told us about the squeeze on demand for oil products, and this is particularly visible in Europe, where I think year-on-year it was down about 8%. We haven’t seen that in the reported numbers in the States, and I am assuming that that is due to exports possibly, but there is a big difference between -- you see a big difference in the reported sales in the U.S. compared to Europe and I am just trying to explain why that might -- understand why that might be. Thanks.
I’ll try and help, Peter, thanks. The oil products, I will start at the backend demand products and interesting factor, and the Rhine River, it hasn’t rained enough. It was low. Therefore it was difficult to move products. Therefore we sold considerably less than what we might have hope to do in both commercial and trading and a supply sense. At some point, it was beginning to threat to the supply security, and fortunately it started to rain again but had quite of impacting in the quarter. So that explains Europe against the United States. Our own volume in the U.S. being generally maintained but the market is flat. It is not clear. Is it going up or is it going down we’ll see as we go into the driving season.
And profitability Upstream in the Americas, they are absolutely right but it is somewhat less than we might have wish for and there is some of the Alaska spend going into OpEx. We don’t capitalize until we drill. But other factors that were quite significant in the quarter, we have quite some significant maintenance activity in the oil sands in Canada. We’re seeing higher depreciation and amortization partly as a result of early production in the onshore gas or liquids-rich shales carried quite significant unit depreciation because we are quite slow and conservative to actually recognize proven reserves there.
And clearly, the gas prices over natural gas prices had quite an impact, and in Canada in particular, the WTI discount has an impact on crude realized prices. So all of those factors are keeping the Americas earnings low, which is unfortunate but otherwise not at all sustainable issue we go forward. We are switching out of gas into liquids-rich shale. That is having, as I mentioned earlier, not too much volume impact now. It may have 20,000-30,000 barrels a day impact by the end of the year relative to where we might otherwise would be.
But as we switch into what is essentially an appraisal activity on the liquids-rich opportunities in Canada and the U.S., we won’t replace it with production -- liquids production this year but it will create the potential for liquids production next year. So it will be a value upgrade assuming light-to-light drilling activity. So we’re just managing this within the overall capital for our operational capability. We are running about just under 40 rigs at the moment, of which we are shifting probably more than half towards the liquids opportunities. And so, hopefully that covers everything. Thanks Peter.
The next question comes from Kim Fustier from Credit Suisse. Please go ahead.
Kim Fustier - Credit Suisse
I had a couple of questions if I could. Firstly, could you just give us an update on your latest strategy in North American gas, particularly your plans to build a large scale GTL plant at Louisiana, and how that would compare to economics on LNG exports? I mean, clearly you are bullish on the LNG market long-term. Is that something you’re eventually going to consider? And secondly, could you comment on your latest thinking in Australian LNG. Again there is some headline saying you are prepared to cooperate with other players on Queensland coalbed methane and how are the economics there would compare to Mozambique? Thank you.
Thanks Kim. North American gas strategy and fundamentally we are looking at 40 tcf plus of gas and which in a $2 would -- we probably would prefer to monetize something other than natural gas. So we are looking at 4 different ways of doing that of which LNG and GTL are two. The other two are gas direct into transport and LNG used as fuel for trucks, ships or rail or organic chemicals which essentially is a methane player in the Pennsylvania region. Gas-to-liquids, yes we are looking to replicate what we have done in Qatar on the Gulf Coast, not necessarily Louisiana. We are looking in Texas as well as Louisiana, essentially looking for a brand filled opportunities, existing infrastructure access to the gas and the gas network, and looking at -- what have we learned in Qatar is to bring the cost down and increase the yield, increase the efficiency.
It will take sometime, a year or two to work that through and then several years to construct. So we are some time away from making a decision on gas-to-liquids and more likely towards the end of the decade before we get production. It does look attractive and does it compare with LNG export?
Well it depends of course on the answer to what would be the cost be and what would the yield be. But there is not a lot of difference there we see at the moment. And LNG export, we would expect and are giving priority to exports from Canada on the West Coast to Asia and we are working with our Asian partners and our potential customers, of course, Kogas, Mitsubishi and PetroChina. So our focus on LNG export is primarily on Canada. As of the US, it’s possible but looks a little expensive in terms of getting access to facilities, so focused on Canada.
CSG, Coal Seam Gas or CBM in Australia. Just to reiterate, there are four projects planned, three under construction plus our LNG project where the LNG is in the FID process, potential FID maybe the end of next year.
Clearly, CSG is not like Sakhalin, we started up Sakhalin on a handful of wells and it runs in full capacity on nine wells. To run big LNG and on the CSG basis you may need several thousand wells which you can’t just start and drill, and start upon day one. So it is clearly a challenge for all the projects to have enough gas available to run the trains economically.
What I said this morning, I am not saying what actually has been reported was that we have plenty of gas to train projects. Where we are prepared to choose our timing of FID to minimize the potential impact of inflation and in the meantime if and as we develop production capability, we are open to discussion with other projects on provision of gas into other people’s facility. That doesn't mean it’s going to happen, but we are open for discussion.
Just to be clear, we are value driven here. We are not in any particular hurry. We will develop the Upstream and the Midstream according to what makes best sense and getting the right balance between production cost and ultimate market access. So we are programmed around the FID potentially FID end of next year. Hopefully, that’s very clearly.
Thank you. The next question comes from Jason Kenney from Santander. Please go ahead.
Jason Kenney - Santander
So have two points of clarification, I am sorry if you covered this already. But was the tax charge lower than expected at 42% I think its 45% in 2011? And can you just tell me what the tax charge might be this year? And then secondly on the exploration expense, I think its $360 million which looks low and that is the lowest since Q1 2009. So presumably, a one-off low charge but what would you see as a run rate for the rest of 2012?
Thanks Jason. Tax charge is not really lower than expected. We’ve got fundamentally we’re shifting earnings from high-tax regimes the low tax regimes which will show overtime, Qatar, US and Canada are relatively low tax. And just to note we didn’t publish some of the country tax revenue payments yesterday. And difficulty to forecast because it does depend on maintaining that mix, but no surprise, they were more one-off last year than they were this year as the divestments carried more one-off issues.
Exploration expense; we expect to spend $5 billion on exploration this year, a couple of billion on the onshore type activity, $3 billion on more traditional primarily offshore type activity. I would expect the higher run rate in a few $100 million.
We’re on-track to spend that money, some of that what we spend in the first quarter was in fact was acquisition which we don’t expense; we don’t expense acquisition, we don’t expand drilling and most of the rest gets expensed unless it’s associated directly with successful efforts. So it’s a just question on phasing of activity and the type of activity in the current quarter.
Thank you. The next question comes from Lucas Herrmann from Deutsche Bank. Please go ahead.
Lucas Herrmann - Deutsche Bank
Just a couple of points for clarification perhaps, Athabasca Oil Sands, can you just expand on the Mason’s comments and give us some indication when you might perhaps be moving towards your capacity on that project? And secondly, I just wonder whether you can make any commentary at all about the acreage that you have actually acquired in the States and what your initial appraisal activity suggests in terms of which acreage is more or less attractive?
I presume Lucas your second question is about the liquid rich shale?
Lucas Herrmann - Deutsche Bank
Yeah, sorry it is liquid.
In the first quarter in Canada in the oil sands we have unplanned maintenance. We are still learning a bit about managing some of these assets and they have contribute, some of the numbers I’ve talked about earlier in terms of the potential value left under table. We are however improving.
When we will be at capacity? Well, we have shown every individual piece of the value chain works at capacity. In fact, we upgrade, as we work above capacity. What we have not yet done is deliver that capacity on all parts of the value chain consistently overtime. So we are not only at capacity, but actually above capacity at both the mine sites and Upgrader.
So we have ongoing, both short-term maintenance activity, but most importantly, the debottlenecking project which will not only increase the overall capacity, they will help improve the reliability. It’s typical just for information, the mine sites to be built for some reason, with target, reliability and availability in the low 80%. And given that we manage better than that in rest of our portfolio that’s what we’ve been working on over the past two to three years. And we are steadily lifting that towards (inaudible).
Acreage purchased in the US and Canada, liquid rich shales, we tend to look at that globally as much as just North America. But specifically, in North America, we picked up acreage obviously in the Eagle Ford, which we are drilling and that’s the most advanced and a material production for us, but we have acreage also in the Mississippi line and several plays in Canada including Alberta back and the Duvernay play which is the geological name of the company.
We currently operate nine rigs in appraisal and development and another four in exploration. We expect that to increase over the coming months and those are the areas that we are focusing on. We have other acreage that we may not get the rigs there as quickly, but we are certainly pushing the boundaries of all our existing acreage and to produce there.
Lucas Herrmann - Deutsche Bank
And when you talked earlier about 40,000 barrels a day from the Eagle Ford gas and oil, can you give us some sense as to what the proportion of that 40,000 comes from liquids?
It’s not just Eagle Ford by the way; the 40,000. But it will depend on how the plays play. Just one comment worth making on the LRF play; they are not the same as each other, they are not even the same if we are drilling wells a kilometer apart, we get point different results and that’s exactly the same with the rest of the industry. This is an immature activity; it is not as mature as the gas and it’s very difficult for anybody to project specific outcomes based on what we know about reservoirs and that includes the Williston Bakken as well.
So it remains uncertain, it's an expiration play, its early appraisal. So 40,000 might be 50:50, it's probably not going to be a long way away from 50:50, but it should come in more specific at the moment. As we drill these prospects out and as the industry drills the prospects out we will see more room I think in expectations, both cost to recovery and ultimately the asset prices that people are paying. Almost all our acreage is what we call emerging or practically none of it is mature to the extent of having a high level of production.
Lucas Herrmann - Deutsche Bank
And Simon sorry, can I just ask you one another on chemicals, can you give us any idea what proportion of profit now is coming from the US relative to say a year ago and again just to get a sense of how Europe, rest of world has moved at a time when prices are being going up and demand is probably being weaker whilst US is being supported by faltering input costs and ongoing steady demand.
I can't give you an exact percentage but it's certainly better in the US compared to a year ago. Europe is down partly because of (inaudible) and partly because we, or Asia is also down, there's been some destocking and sales down a bit but, so the US is up, the rest of the world down, but primarily that just reflects strategic choices that are playing out and well it's still an attractive market medium term and we think we are in a lot better position than we were previously.
Lucas Herrmann - Deutsche Bank
So this is split 50:50, 60:40?
I can't really give that Lucas.
Thank you. The next question comes from Robert Kessler from Tudor, Pickering, Holt & Co. Please go ahead.
Robert Kessler - Tudor, Pickering, Holt & Co.
Question on your Marcellus spend, a partner of yours in the area apparently is chosen not to consent to incremental drilling in the region there by implying your net CapEx should increase in the short term. That to me begs the question, how do you manage your budget in the Marcellus, do you manage to a dollar spend or do you manage to an activity level?
I have to say I don’t manage it at all, I manage more on the portfolio level and the guys on the ground manage it. So you are absolutely right, well informed that there are non consent partners in the Marcellus and of course if we drill that acreage, the backend costs are a multiple of the original cost. So effectively we’re acquiring acreage by drilling it or acquiring a high share in the acreage by drilling it. We will indeed do that where it makes sense and the Marcellus is certainly an area where we see low cost and high potential overall, so we’ll continue to do it. In the short term clearly, it does increase the CapEx. Our actual drillings spend in Marcellus not that material for the group. So technically we leave it with the guys who run the onshore operation to maximize value rather than worry specifically about number of wells or number of rigs.
Robert Kessler - Tudor, Pickering, Holt & Co
In general, would you expect your activity level to be flat for the balance of the year or increase, decrease you know kind of qualitatively?
I think net activity will increase, but it will increase on the liquids and exploration in Brazil. We’re moving rigs away from Haynesville and (inaudible) basically flat in Marcellus and Grand Birch and increasing everywhere else.
The next question comes from Irene Himona from SocGen. Please go ahead.
Irene Himona - SocGen
I had a couple of questions please. So first on income statement, I see the interest expense at $552 million. On an annualized basis, about 6% of your debt and that compares with only about 3% of last year. So I just wonder if there is something going on here, is there any guidance for what we can expect?
Secondly, you make reference to good contribution in your Downstream of the Brazilian JV Raízen. I wonder if you can give us some visibility on how material that is and also the JVs look into, perhaps acquire BG's stake in Comgas, how does it fit in the strategy, what is the game plan there? Thank you.
Thanks Irene. Interest expense is higher as a percentage of the debt in the earnings this year because we are capitalizing less interest. A year ago, we were capitalizing more interest into projects, such as Pearl in Canada. We typically only capitalize interest into very large projects and I think that’s the primary driver there. Raízen materiality, it is hopefully several hundred million dollars per quarter. It is being driven or helped at the moment by good sugar and ethanol prices.
So far we had a successful operational start and as I mentioned it is not always easy bringing together two cultures, but we found very good strategic alignment. Cosan is a good partner and we see more synergies, more opportunities than we had originally envisaged in the operation which is being good so far.
The Cosan independently and separately have indeed made a bid to purchase the stake 60% plus stake in the BG holds in Comgas where we hold most of the remaining share of Comgas, a little bit of it is actually on the public markets in Brazil. However I can’t say what our reaction because it is the deal in process, might be but this is not necessarily here a multi-party squeeze out of BG. This is a Cosan-BG deal. This is not a Shell deal. Longer term of course the Cosan's interest are basically for them to determine and need talk to them about, but if their interests are in the energy sector development in Brazil, the clean energy sector development, these are the statements they make and Comgas is not only well placed being in São Paulo state and close to a lot of the current activities, it has potential longer term for synergies with Raízen, but there are no plans to merge or take the strategy together.
Irene Himona - SocGen
Okay thanks. Can I just very quickly ask about going back to the point on the potential for GTL in the US, obviously the life of such a project is 30 year plus, it is a free market. The project's economics do depends on the oil to gas price differential. Isn’t it a little bit of risky to sort of bet that the current differential remains in place for that time period?
Fair question, but I would push back on. It doesn’t actually depend on the differential, it depends on the difference between oil price and cost of gas if we are producing our own gas. It only depends on the differential if you are buying the gas. What you give up is, depending on how gas price were to go to $10 or $11 again would be the opportunity cost of course. And so what it does actually derisk portfolio from just being a pure natural gas by converting some of the natural gas to oil. So it's a play on what do we see the long-term oil price as long as we got low cost gas in our own portfolio. So that’s how we think that is. So the question we need strategically to consider which being considered.
But if I have an answer, I would probably be looking to share within the strategy discussion what is the proportion of the total gas resource base on which we want to effectively develop liquids-related pricing exposure. And it’s not necessarily a 100% but I don't know what the number is. But the priority we are giving at the moment, as I mentioned earlier, Canadian LNG and we are looking at GTL. That may not use a whole significant demand to the 40-plus Tcf that we actually have but something that we will always strategy will evolve as we see, get a better view of the cost and the economics and the relative attractiveness.
Thank you. The next question comes from Neill Morton from Berenberg. Please go ahead.
Neill Morton - Berenberg
Thank you. Good afternoon. I have a couple of questions. First is on the Q1 earnings. I might be sort of reading too much into this but your opening line was emphasizing that these were the snapshots as part of the long-term strategy. I just wondered whether perhaps you felt that Q1 was probably a little bit ahead of where you would expected it to be perhaps trading or cost seasonality, perhaps you can comment on that. And then secondly, when you are commenting on Alaska, it sort of reminds me that both Exxon and Eni have actually advanced their offshore plans in Russia given a change in the tax regime. Could you perhaps update us on your plans there please? Thank you.
Thanks Neill. I think you maybe reading something in that that might be not intended but the snapshot are essentially the same price we had in Q4. We don't lose a lot of sleep if we have a particularly bad quarter as long as our strategy is being delivered. We don't celebrate too wildly with a good quarter. And we have to look through the cycles. So, yes Q1 looks like a particularly a good quarter, but than if you book the last six months together, that’s perhaps more represented where we see we are only the overall delivery journey.
Alaska, or Arctic more generally, our focus clearly is in the U.S. on Alaska and Greenland, where we would do further study work this year, looking to drill in the not-too-distant future. We have Russia as a whole big country, lot of acreage. Some of the acreage, they’ve been taken up. We’re always open to discussions with Russian partners, but it needs to be -- we need to be able to find an outcome that suits both their advantage and that’s not yet been possible for us, but we have good relationship with both Gazprom and Rosneft. And maybe that will ultimately lead to further opportunity but in the short and the medium term, we have quite a lot of Arctic exposure, quiet of lot of Arctic experience and that’s why we would be focusing our efforts.
The next question comes from the (inaudible) from Bank of America. Please go ahead.
Hi there, Simon. Just a quick question regarding gas pricing in China. Given your unconventional position there, I just wanted to see if you could give us a sense as to how much the Chinese are using that to promote gas-on-gas competition in the country and whether that’s beginning to affect LNG prices and the sorts of levels that you are beginning to -- that you are achieving on that new contracts that you are signing out there?
It’s a good question but you are probably slightly ahead of the game in terms of an answer I can give you. Just to be clear, the Chinese energy policy at the moment in the 12th five-year plan is clear. They expect to grow gas as a share of primary energy demand from 4% in 2010 to 10% or higher by 2020. So probably tripling or more of the total gas demand in country. As a result of, meeting the energy demand that is growing, but also for a cleaner form of energy.
So it’s got quite strong support already in the policy and that policy was predicated mainly on imports, either pipeline or LNG. LNG typically affecting market prices on the coast further inland the prices tend to be a netback against those coastal prices. There have been a policy to raise prices from the current level which are certainly higher than North America at the moment anyway towards the import parity overtime essentially what you say the gasoline gas competition. But prices are set differently for different consumers as well.
So everything you say, your estimate is very valid, but all of the answers come not from Shell, but from the government and I am sure that they will be taking into account exactly what is the potential at Shell gas? We don’t know that yet. That’s why we are trying to help establish together with PetroChina at least in the acreage we are working together.
So we completed 11 wells last year. We hope to complete quite a few more this year, maybe around 25. So by the beginning of next year, we will have much better feel for what’s the real volume potential or what is the cost of producing not volume and when we say that and possibly more broadly across the country, I am sure the government will consider long-term policy that will encourage the development. Now what the outcome of that actually is in pricing terms, we just don’t know yet. So great question, but at least 12 months if not 24, too early.
Thank you. The next question comes from (inaudible) from ING. Please go ahead.
One question with regard to the selling 32% of your product in the present stake to Asian partners, what are your intentions there for the future; are you trying to accelerate the exploration efforts there in that area and also with regard to LNG projects starting up there like a consortia or something like that?
I would say there are three partners, INPEX, Kogas, and TPC; two of them are clearly LNG customers for Shell and interested in LNG supply back to their home base. And so for us, that’s a typical way of de-risking an equity LNG project, but we started on 100% bringing in customers.
The INPEX is slightly different, you have noted in Q4, 2011 we agreed to enter the Abadi Floating LNG project in Indonesia which is an INPEX project. So we are doing effective design share of that project and they have come in per share of our project.
So its part of the development relationship with INPEX, so we do with [Alpha] as well as for example in Kazakhstan, so that's good. We feel it’s a good way for Shell to de-risk the project, to monetize some of the potential value in the project, but also to maintain existing relationships and other opportunities.
And the book value of $500 million I think in the quarter you said that this article fit in etcetera; what has been done on that synergy?
And the exploration activities.
Thank you. The last question comes from [Ken Merga from Market Securities]. Please go ahead.
I just had one question regarding the asset class. So can we have an update on the potential measure of the class A and B please?
Sorry, it was not easy to hear you, there's some background noise. Potential merger of the…?
Class A and B?
Okay. The question was about the potential merger of A and B shares. We discussed this a little back in February. It is something that we would like to do clearly, would simplify and remove some restrictions we have in terms of our financial and corporate framework.
Current, well, the previous issues we talked about some withholding tax charges and we would need some agreement there basically from the Dutch government, now you are probably aware that there is no Dutch government as of the weekend unfortunately. The government was unable to reach an agreement on the budget. So we do not know when the next election will be, but there is talk of maybe in six months period and then potentially months after that the full new coalition.
So from a Shell perspective, this means it’s very difficult to expect or even to try for any discussion about the conditions under which we could merge the shares. I am afraid that’s probably off the agenda relative to where we were in February. And we would hope to be able to raise that when there is a new government in place in Netherlands.
Okay, thank you.
Okay, I think that’s all the questions. So, thank you very much to all of you for both listening and for your questions. I hope that was helpful in your understanding of our business.
Second quarter results will be released on the 26th of July and Peter and I will talk to you all and the intention is to make that a face-to-face meeting in London. So quite literally, I look forward to seeing you all again in the near future. Thank you for today.
Thank you. This concludes Royal Dutch Shell Q1 Results Announcement Call. Thank you for participating. You may now disconnect.