Peter Voser – Chief Executive Officer
Simon Henry – Chief Financial Officer
Theepan Jothilingam – Nomura International Plc
Martijn P. Rats – Morgan Stanley
Iain Reid – Jefferies & Company, Inc.
Irene Himona – Société Générale SA
Hootan Yazhari – Bank of America Merrill Lynch
Peter W. Hutton – RBC Capital Markets
Jon Rigby – UBS Ltd.
Lydia R. Rainforth – Barclays Capital Securities Ltd.
Robert A. Kessler – Tudor Pickering Holt & Co. Securities, Inc.
Michele della Vigna – Goldman Sachs
Fred Lucas – JPMorgan Securities Plc
Jason Gammel – Macquarie Capital Ltd.
Alejandro A. Demichelis – Exane Ltd.
Jason S. Kenney – Banco Santander South America
Royal Dutch Shell plc (RDS.A) Q2 2013 Earnings Conference Call August 1, 2013 8:30 AM ET
Welcome to the Royal Dutch Shell Q2 Results Announcement Call. There will be a presentation followed by a Q&A session. (Operator Instructions)
I’d like to introduce your host, Mr. Peter Voser. Please go ahead.
Thank you, operator. And ladies and gentlemen, a very warm welcome to you all. We have announced our second quarter results today, and Simon and I will run you through that. We will operate you on the key portfolio and strategy development in the company, and of course, at the end there will be plenty of time for your questions.
Let us start with the disclaimer first. Firstly, on the results, our second quarter 2013 underlying CCS earnings were $4.6 billion and cash flow from operations was $12.4 billion. Higher costs exploration charge is the worst exchange rate effect and challenges in Nigeria have hit our bottom line. And there are many factors driving these results, some of it is the world around us, and some is our performance. But the bottom line of all of this is that these figures are clearly disappointing for Shell and for myself.
Dividends, our Shell’s main route to return cash to shareholders, and we have distributed more than $11 billion of dividends in the last 12 months. Our share buybacks have set to offset EPS dilution from script. So far this year, we have repurchased more than $3 billion of shares and we are on track for $4 billion to $5 billion of buybacks in 2013, underlining our commitments to return for shareholders.
Earnings volatility is a fact of life and we are looking through that. We have a long-term strategy making multiyear investment decisions and we are delivering on that strategy generating profitable growth for shareholders. Now, 2013 and 2014 should see the stock off of a large number of new projects, of which the largest five should add over $4 billion to our 2015 cash flow, which is placing the [brochure] LNG and Qatar stock.
We don’t have oil and gas production targets. We have retired our outlook statements on production today. Our recent portfolio moves make the production target less and less relevant. New place like the Repsol LNG and the Basrah Gas still don’t have any production in site (inaudible) for example, and overall we are targeting financial performance at Shell.
We have build up substantial new options for the company in the last few years, and a larger exploration portfolio. We have reached critical mass with our 2015 plus option set and there will be decisions to make on which options to take to final investment decisions. We are entering a period where there will be a higher rate of asset sales, for example, in Nigeria and North American shales and in other parts of the portfolio too, as we work through these choices.
Fundamentally, we are driving sustainable through cycle financial growth in the company, measurable through our cash flow and we can achieve that growth through a number of pathways and production outcomes. We are 18 months into the financial program we set out last year, and there is no change to those targets. $175 billion to $200 billion of cash flow from operations for 2012 to 2015 combined in a $80 to $100 oil price scenario, and we have to limit $70 billion of CFFO in the first 18 months of that program.
Now before Simon takes you through the numbers, let me just make a few comments on Nigeria. We have seen a marked escalation in securities problems best in Nigeria in 2013. The SPDC joint venture has had shutting on major oil pipelines and the gas pipelines that’s key to the Nigerian LNG plant, due to sabotage. This has all been compounded by tax disputes between the Nigeria LNG joint venture and the Nigerian Maritime Administration and Safety Agency, which resulted in a blockade on exports from NLNG for 23 days ending on the 13th of July.
Oil theft and sabotage in Nigeria are resulting in substantial revenue loss for the Nigerian government and widespread environmental damage. On an annual basis, this could actually be an earnings loss of $12 billion for the Nigerian government and society. For Shell, we had a second quarter 2013 shortfall of around 100,000 barrels of oil equivalent per day, 150,000 tons of LNG and at least $250 million of lost earnings as a result of all of this. Shell and our partners are all working this, the government of Nigeria as well as foreign governments, on solution to what seems to be endemic issue. We had shale to play our part, but we cannot solve this own our.
Now with that, let me hand over to Simon on the results and I will then come back on portfolio and strategy. Over to you, Simon.
Thanks, Peter and good to talk today. I’ll start with the macro environment. If you look at the macro picture compared to second quarter of 2012, Brent oil prices were $6 lower than year ago, narrowing the differentials between Brent and the North American markets. Our unrealized liquids prices declined by around $10 per barrel Q2-to-Q2, so that’s more than the market. However, natural gas realizations increased from a year ago. On the downstream side, refining margins were weaker in Europe and the Gulf, slightly higher in Singapore, and then the same in the West Coast, and North American margins were reduced by the narrow at WTI differential.
In chemicals, margins declined from a year-ago levels and the weaker industry margins in Europe and turnarounds in our own operations. Our quarterly results are important and this is a price you’ll recognize after the first quarter whether that high or low. But they are really just a snapshot of performance in the volatile industry and we are implementing a long-term through cycle strategy.
In our second quarter, CCS earnings current cost of supply excluding the identified items were $4.6 billion, earning per share decreased by 21% from second quarter 2012. Our reported CCS earnings included $2.2 billion of identified items, and these are with the downstream in Italy, where we announced the intention to sell asset, but much more substantially in the Upstream Americas business with an impairment of some of our liquids-rich shale position reflects the latest insight from drilling and production data, and a lot of ways this is similar to an exploration write-off.
The clean depreciation in the quarter was $3.9 billion, from that, $2 billion higher on an annualized basis compared to 2012 due in part to IFRS 11 effect and also new project ramp up and the amortization rate on the resource plays. And the ongoing depreciation will not be significantly impacted or decreased by the second quarter impairment, because we’ve also increased the amortization rate for the non-productive leases as we go forward in the North American resource plays. This reflects increased some uncertainty following the recent drilling results, and that effect offsets the reduction in depreciation on the impaired assets.
The second quarter 2013 DD&A also include an impact of $80 million for catch-up effect in non-producing lease amortization. That was not taken as an identified item. We announced the $0.45 per share dividend for second quarter 2013, that’s 5% higher than a year ago. The share buybacks in the quarter were $1.9 billion. And as of last night, we were $3.2 billion year-to-date, and remember, we’re using those buybacks to offset the dilution from the script dividend, it’s more than just offset the likely script dilution for the year.
The headline oil and gas production for the second quarter was 3.1 million barrels of oil equivalent per day. It’s an underlying increase of 2% excluding the impact from Nigeria, from PSC price effects from divestment. Volumes were supported by growth from Pearl gas-to-liquids and Pluto LNG project in Australia. But the Nigeria security problems reduced production by some 65,000 barrels per day on a relative Q2-to-Q2 basis.
We had some 40,000 barrels per day of Q2-to-Q2 maintenance and performance impact, that’s negative, and that was spread across a number of assets such as oil sands in Canada, the UK North Sea and the Brazilian deepwater. Also continued impacts in the Mars corridor for the Mars-B hookup and the Gulf of Mexico production overall was similar on a year versus year basis. This quarter’s production was also reduced by 30,000 barrels a day from a reclassification of royalty entitlements, that impacts reported volumes on an ongoing basis. And going forward, it has no impact on current or future earnings or cash flow.
LNG sales volumes were up 2% Q2-to-Q2, driven the growth in Pluto in Australia. But partly offset by the around 150,000 tons a day loss in Nigeria, where the feed gas supply was disrupted by the security picture and also by the blockade that Peter mentioned.
In the Downstream, chemicals and refinery availability were both similar to a year ago. The sales volumes were impacted by accounting changes and divestment. Although the underlying sales volumes of oil products did decrease as a result of lower trading volume, while our chemicals product sales decreased as a result of maintenance activity in Europe on our own efforts and expiring contracts.
(inaudible) in the U.S. ramps up refinery production from new facilities that goes off the refinery, and that’s closed the capacity now during the quarter. But we’re still looking forward to a higher financial contribution there.
This chart shows you the main drivers of the result this quarter compared to 2012 Q2. The microenvironmental role was broadly neutral, looking Upstream and Downstream margins and the uplift from LNG joint venture dividend receipt. So as a result, we’re impacted by a series of external environment factors that were in aggregate $0.7 billion negative for shareholders. That’s the lost revenues in Nigeria due to the sabotage and the blockade of LNG, but also an increase in the deferred tax liability, which is a foreign exchange effect, due to the weaker Austrian dollar. Growth projects and the portfolio mix made a positive year-over-year impact, obviously with a strong contribution from TTL in (inaudible). The underlying depreciation and amortization increased by some 20%, driven by Upstream project ramp up acquisition and exploration and abandonment provisions.
Exploration charges were $1.2 billion pre-tax, an increase in line with our higher exploration expanding overall and a higher level of well write-off in this particular quarter in Egypt, in North America, and in French Guiana. Operating expenses increased by 9%, primarily in the Upstream and that’s with increased cost for maintenance and for growth and the portfolio in general. The feasibility study costs for the new option such as Common Creek, gas monetizations options in the Americas, (inaudible) in Iraq, Cambodia, Indonesia (inaudible) in Nigeria, and they are totaled around $400 million pre-tax in the quarter.
They might remember that the bulk of our Alaska spending is being expanded this year rather than capitalized simply, because we’re not drilling. This charge around $19 million post-tax this quarter comes through as an operating cost. We will see some pointers for the third quarter on the slide too.
Now, let me highlight, in the Upstream, we are expecting similar exploration chargers to the second quarter of about $1.3 billion under our continued impact from the Nigeria security and LNG blockade. We’re expecting 35,000 barrels a day of higher margin, maintenance, and asset replacement impact, Q3 versus Q3. This includes the Auger platform in the Gulf of Mexico where the hook up underway for the Cardamom tie back, but also the BC-10 project in Brazil and several North Sea fields, that’s a normal plant turnaround activity, but higher than last year.
In the downstream, refinery availability overall is expected to be inline with Q3 2012, and that includes the turnaround at Scott Ford and Western Canada, and the chemicals availability is actually expected to increase. So those are the comments on the earnings and moving on the cash flow. Cash generation on a12-month rolling basis was some $47 billion, that includes $3 billion of disposal proceeds, and that’s against an average Brent price for the 12-month period of $109 per barrel.
Both upstream and downstream generated surplus cash flow, although the surplus for upstream has declined somewhat. The free cash flow, that’s cash generated less investment, was $3.3 billion in the quarter and $9.3 billion over the last 12 months, and for obvious reasons, we’re managing this cash cycle very closely, particularly in the volatile macro that we see.
A number of you have asked us for more details on Upstream Americas financials, this slide is a snapshot of the key metrics that hopefully will help. On a Q2-to-Q2 basis, the underlying earnings fell from around $100 million of profit to some $300 million of loss. We saw a 30,000 barrels a day low volumes from the highly profitable deepwater, around 10,000 barrels a day reduction in heavy oil and 60,000 barrels per day higher production from the shales. So the net result is higher volumes overall, but with growth and lower margin production. In addition, there was $750 million pretax increase in costs, DD&A and well write-off. Taking a longer-term and more strategic look at this, I think it’s important to say that we are managing these businesses, the three businesses there, in their own right and we’re not running the portfolio to drive a particular Upstream Americas P&L income.
The Upstream Americas business did generate $5 billion of cash in the last 12 months, although with negative free cash flow after investment and earnings slightly negative. The deepwater business is making solid profit and we have seen fall in production there, as a result of the (inaudible) delays and the more recently the downtime at Mars and Auger as we work on the hookups for the new project. Perhaps that’s resulted in a shrinking contribution from the high margin deepwater fields in the Gulf, where production in 2009 was around 250,000 barrels oil equivalents per day, and was 177,000 barrels oil equivalent per day in this quarter.
And the Gulf of Mexico volumes are likely to remain low in the second half of 2013. However, this trend should reverse during 2014 and 2015, with the new growth from Mars-B and from Cardamom and later on from Stones. The three projects alone were a total of around 170,000 barrels a day at peak per shale and this is an important earnings and cash flow driver for us.
And looking at heavy oil, also currently profitable, but with less near-term top line growth, the focus here is, as we said before, current operating performance, debottlenecking capacity and controlling the costs. Resources plays at the Shell, we are seeing the impact of low gas prices, but also the startup costs, the exploration charge and the effect of the higher lease amortization, it’s not unusual or unique to Shell to see this kind of financial profile in the growth business.
Feasibility cost category mainly covers pre-FID options, such as integrated gas project, particularly Alaska, these are basically the option for the future. Under the current macro condition, we expect the Upstream Americas business to remain in a loss for at least the second half of 2013.
As resources plays losses and the ongoing [free deck] outlay the profits we expect in the deepwater and the heavy oil. The growth and the oil production we should come from deepwater and from the liquids-rich shale should drive a returns profit in 2014. Although Upstream Americas is in and we will remain in a growth mode, so this will fundamentally be a cash flow story to Shell rather than earnings for quite awhile to come.
Let me update you on the progress of the portfolio in the quarter. We made more progress with accessing new investment opportunities, and we are working the portfolio hard to drive capital efficiency. In the Upstream engine, we were selected to develop the Bab Sour Gas builds in Abu Dhabi. We are adding new opportunities and equity in the integrated gas. We’ve made new discoveries and taken new FIDs in deepwater and in Nigeria this quarter.
In July, we announced the final investment decisions with BC-10 Phase 3 deepwater project in Brazil and the redevelopment of Bijupirá/Salema in the same country.
Now Peter will review more details in a moment, but we have also launched strategic reviews of our Nigeria onshore and our North America resources or shale portfolio, both of which should lead to more divestment income and more focused investment spending going forward.
Turning now to the financial framework, our business strategy aims to grow cash flow on a sustainable basis through the macro environment cycle. we have clear targets for financial growth underpinned by consistent and appropriate capital investment that is subject to strict investment hurdles all linked to add value for shareholders, and the balance sheet itself underpins its overall financial framework.
We delivered $77.0 billion of cash in the last 18 months, $63 billion excluding working cap, and in the same period, we’ve invested $49 billion on a net basis. And you can see chart on the left, the red line, the free cash flow has grown in the last few years from a negative position 2009 to $9 billion over the last four quarters. The gearing is now down around 10%.
Now, let me just say few words on capital spending. If I remember, we’re in an 18-month program, but we’re 18-month into a full-year program and that requires us to invest up to $130 billion on a net basis, not driving the cash flow growth, any given quarter or in deed, any given year is only a snapshot of where we are in that long-term trend. We’ve taken on incremental new project this year where we see good opportunities above what were our base plans. And these include Elba Island LNG export in the U.S., the gas transport project also in the U.S. We are investing in project offshore like Stones, which is effective now in the 100% basis, rather than a lower percentage.
In addition, we’re making good progress with the Repsol transaction, which could close in the second half of this year and that’s earlier than we have expected. Putting all of this together, we are expecting net spending for 2013 to be around $40 billion. And this figure includes around $3 billion of non-cash items, such as FPSO and LNG ships leases.
Asset sales divestments could reach $3 billion this year. And it depends – the actual thing will depend on the timing of one or two transactions we currently have in hand. And as Peter told you, asset sales will increase in the 2014, 2015 period. And we don’t have detailed guidance for you at this stage. But it’s likely to be towards the top end of the assets sales range that we delivered in the last three years. And it’s all part of managing the net spending around $130 billion in 12 to 15 period.
As you know, the dividends are our main route for returning cash to shareholders. The script dividend uptake in the second quarter was 28%. We’ll be offering the script dividend again, and for the Q2 dividend, 28% is above the going rate, which is on average 30%.
Now, we’ve increased the pace on the share buyback program this year, which is designed to offset the script through cycle. And we’ve already spent $3.2 billion on buyback so far this year. So just about offset the likely script dilution for the year. And we remain on track for the $4 billion to $5 billion buyback program that we previously announced.
With that, Peter, back to you.
Yeah, thanks, Simon. Let us look at the strategy. We are driving investment and innovation in Shell’s human resources along a series of strategic themes. Downstream and our mature Upstream positions, we call them our engines, generates strong free cash flow for the company today.
The growth priorities are in integrated gas in deepwater and in the resources plays shale, and we have good positions in longer-term plays like heavy oil, Iraq, Kazakhstan, and Nigeria. We fills up new options, more choice for where to invest our dollars, and by implementing hard capital ceilings, we are driving tough choices in the company.
As I said before, Shell is capital constraint rather than an opportunity constraint, and there will be choices to make as we take final investment decisions on some of these options and exit our dilute orders.
So let me update you on progress in some of our strategic themes. Let me start with deepwater and the Gulf of Mexico. We took that finally, final investment decision on Mars B during the Macondo moratorium in 2010, because we saw a cost opportunity and Mars B now is making great progress. Potentially the leg platform was floated out to the field in July, and we are firmly on schedule on November this year.
In May of this year, we took final investment decision on another deepwater field, which is Stones and Simon has mentioned it. This is Shell’s second lower treasury development in the Gulf, and our first FPSO there. Stones has substantial upside potential from the application of innovative technology. The field is estimated to contain more than 2 billion barrels of oil in place. The first phase of development is for 50,000 barrels per day for more than 250 million barrels of recoverable resource.
Now, let me update you on the resources plays in North America shale. We are making some important decisions on what I’m convinced is going to be a success story for Shell. Exploration in Shell is a dynamic activity with production at an early stage of the cycle. We have built the substantial position here with some $24 billion for North American resources plays on the balance sheet.
We are now entering a period of focusing our portfolio down to our best liquids plays, whilst maintaining key dry gas assets for longer term integration value. We have some nine operational theaters in North America. I think you can take that this will reduce to about half that number overtime as you focus down this portfolio while growing our business.
We expect to see a step-up in asset sales for North American resources plays in the next 18 months. Now we have reduced spending overall in this theme with less activity on dry gas and more in liquids-rich plays, and maybe some further small acreage build around our core assets or areas to achieve our desired scale, but the major acreage fees are behind us now.
So let me turn to our long-term plays in Iraq, Nigeria and Kazakhstan. We are pleased to update that the Basrah joint venture in Iraq is up and running. This JV uses associated gas that would otherwise be flat from oil fields and converted to LPG and natural gas for local customers.
In Nigeria, this remains a complex and difficult environment for the international oil company. SPDC’s new investment has been focused on pipeline upgrades to reduce sabotage and theft flares, and flares reductions, feed gas for LNG and some selective oil projects. SPDC has been divesting parts of the joint share portfolio, concentrating its operations into a smaller more contiguous area and supporting the government’s policy of encouraging investment by indigenous companies. Since 2010, Shell has sold its 37,000 barrels per day interest in eight SPDC licenses for a total of $1.8 billion. We have recently launched a review of Shell’s interest in SPDC licenses in the eastern part of the delta. This could result in divestment of some 80,000 to 100,000 barrels per day Shell share of production as we continue to refocus the portfolio.
Let me turn to Kazakhstan. We are expecting first oil production from the Kashagan field in the second half of 2013. Now, this is a giant field, 3 billion Boe are being developed in Phase 1. This is a two-train development that will be ramped up over a two-year period to the design capacity with an average 300,000 barrels per day production.
JMG and Shell has been delegated to jointly manage production operations of oil phases, hand over of the assets to production operations will take place when stable production has been reached. Kashagan is one of the series of large new startups in Shell in 2013 and 2014. The five largest of these projects out of 17, you can see them on the slide, should add between a $0.5 billion to over $1 billion each to our cash flow or over $4 billion in total once they are fully on-stream. These five start ups will mark another growth step for the company and we are entering an exciting delivery phase here.
And with that, let me summarize for you. Earnings volatilities (inaudible) and we are looking through that is a long-term strategy making multi-year investment decisions. We made capital allocation decisions on a global basis investing in the best projects, taking a value chain approach and redesigning or exiting from positions that don’t meet our return and match reality thresholds. We have distributed more than $11 billion of dividends in the last 12 months. We are on track for $4 billion to $5 billion of buybacks in 2013. All of this underlines our commitment to shareholder returns.
With that, let’s take your questions. Please could we have just one or two each, so that everyone actually has an opportunity to ask a question. With that, operator, please poll for questions, and Simon and I are happy to take that.
Thank you. We will now begin the question-and-answer session. (Operator instructions)
Let’s do the first questions.
The first question comes from Theepan Jothilingam from Nomura. Please go ahead.
Theepan Jothilingam – Nomura International Plc
Talk about why the change in view in terms of – for 2014 and 2015? And just a point of clarification on that, if the asset sales go up, does that mean the net investment numbers goes lower. And then in that context, have you gotten your sort of target range on where you think caps are not in new [shipping] for the Shell Group? Thank you.
Okay, I think you didn’t come through at the beginning, but I think we got the question. It was all about the CapEx for 2014, 2015 and after that. So, I’ll pass it on to Simon.
Thanks, Theepan. The – what were the one target that we have understanding the CFFO delivery over four years and the net CapEx required to deliver back and on future growth remain unchanged. So $175 billion to $200 billion aids you to a $100 oil price. And remains the expectation and the intent and up to 130 net capital investment also remains intent. What we’re seeing this year is extra project coming in, and a Head of dilution or divestment, what you hear around the strategic reviews in North America and Nigeria is the expectation that the divestments will kick up above the divestment level. But we’ve previously stated, we expected that the organic capital would be in the mid-30s, that would meet that overall balanced financial framework and there’s no real change to that guidance today.
This is a full-year program through cycle delivery to have sufficient free cash flow to grow the dividend, to offset the dilution from the scrip, but also to invest at a level that creates sustainable growth in the cash flow going forward for years to come, which will support continually growing dividend. That’s the structure and no change to the targets within there and there’s no real point in talking the individual moving part, Theepan, and on the ground that this is a full year program to balance the cash in and out.
Thanks, Simon. And send the next question, to the next question.
Thank you. The next question comes from Martijn Rats from Morgan Stanley. Please go ahead.
Martijn P. Rats – Morgan Stanley
I have two questions if I may, first of all, looking at the delivery of operating cash flow so far, over the last, excluding working capital, the last 12 months you’ve seen about $40 billion of operating cash flow delivery. First it did sort of the 50-year run rate implied by the $200 billion target. Now I do appreciate that the retro will kick in and that there are five projects, which is delivering around about $1 billion or even slightly more billion dollars of operating cash flow at some point. But did the gap between the last 12 months at 40 and the future at 50, it still seems to be quite large, even in that context, can you provide a little bit more detail on how that will ultimately be reached? And the second question that I wanted to ask relates to the impairments in the U.S. I was hoping you could be a little specific on exactly the sort of which basins and what regions and what place have lead to the revision in the asset value.
Yeah, I’ll take the second one and Simon takes the first one.
Thanks, Peter. Thanks, Martijn. There’s one specific issue in the CFFO to get to 12 months rather 18, and that is the tax payments versus tax charges, some of which is related to the tax payment on divestment and some of which is just timing related to last year’s profit otherwise the current year profit. So that’s a $3.5 billion movement year-on-year in the quarter. And working capital, of course, will remain flat or reducing from very structural activities and more flat macro, and the real world, everything in is $70 billion six quarters. We know we could have done better in some operational areas behind us, but there is a lot of growth to come ahead of us.
And we’re talking about the five projects, so five out of 17, and the overall project growth is expected to deliver, we’ve said before, $9 billion of cash flow growth 2015 versus 2012, and there are performance improvements as well in addition to that. It was always a steady growth through the program and that’s what we remain on track to deliver, give or take some of the operational instance we talked about and Nigeria doesn’t help obviously. But it’s a relatively small number compared to 200 and the ambitious target we remain in place and that’s the intent.
On your second question, let me first say in general, we are driving an expiration appraisal acreage on the LRS side and therefore, it is normal at this stage that you focus on the bank reservoir, but actually as we have done over the last two years from new acreage, and you actually move on when the plays are not that successful as you want them and specifically if they are not scalable to the extent people would like to have. And that’s really what we have done over the last months looking at the portfolio results, the weather results, which ones are working, which have to scale, and then actually we have taken some write-off while we are moving and the portfolio down from nine to four areas.
So some of the things will have to go, that’s where the asset sale is coming. We have done, we have had a very rapid growth and therefore, we had a lot of new well valid results and (inaudible) this one.
Now, I’m not going to go basin by basin, what goes and what stays on. I think you will understand, this is commercially interesting for us to keep that to ourselves and we will write it that way. But all in all I think we are seeing readily positive areas for us, we are driving those, and that’s where the investments go, will go in.
Just to give you some investment numbers, we had $9.9 billion of CapEx last year, it’s around $5.7 billion and it dropped to 60% LRS and 40% is dry gas. So that’s how we are driving the change from that into LRS quickly assessing, moving away when it is not to our scale and focusing on those, which we want to see, I think I leave you down. Operator, next question.
Thank you. The next question comes from Iain Reid from Jefferies. Please go ahead.
Iain Reid – Jefferies & Company, Inc.
Yeah hi, good afternoon, guys. I was wondering given the focus you got on cash flow rather than production, whether you are considering, reducing your CapEx going forward, i.e., taking the foot off the pedal perhaps and some of the options you’re taking about for 2015 onwards. And giving a hard ceiling if you like the CapEx even maybe reducing CapEx somewhat, and I’m expecting the past future production might be a little bit lower. Is that a kind of option you’ve thought about, in the kind of strategic delivery that you’ve been talking about there?
Thanks, Iain. I think over the last few years, we have talked quiet a bit about increasing our optionality in the funnel, so that we can actually drive harder choices in terms of returns, but also when do this actually through a hard capital feeling, which we rise internally. Simon explained and how these all fits together with the financial framework, and in that sense, we’re driving around $30 billion net capital for the four years. And we’re very careful of letting the right project come through for the post 15 growth area.
Now, the one thing I’ve learned over the last four years, to predict CapEx three, four years out, that is always quiet challenging thing to deal, because it has a lot of macro and other impact, and oil price and gas price impact et cetera. I think I will just leave it at that stage – at this stage, we’re driving the return and the discipline very hard.
And therefore, we’re driving growth in cash flow. And as you know, our production target in the past, we’re always called a proxy for cash flow growth. Now, in discussions with all of our shareholders, we have clearly come to the conclusion that working on our portfolio and getting some assets up for sale and actually dropping the production target and focus on the cash flow growth target is what is, is one to buy the shareholders and that will be our driving.
I think what you will see going forward is a very hard focus on the right projects coming through and others will go out either those will give us cash flow even today, because they are less profitable in going forward, and out of that, you will get as a consequence, you will get the capital numbers, which then fit into our financial framework. I think I leave it at that rather than forecasting ups and downs on capital, because even three years ago, when we said we are coming out of our big projects, we never said we are going to reduce capital, because we see profitable growth and that’s just about now to come again with our big projects and the cash flow growth. So I rather have to just caution around that (inaudible).
Thank you. The next question comes from Irene Himona from SG. Please go ahead.
Irene Himona – Société Générale SA
Yes, good afternoon. You signaled that North American Upstream is likely to remain in losses at least for rest of the year. You’ve also switched to financial targets only. In the first half this year, return on capital is down. I wonder if return on capital is a financial target or whether we should anticipate that to continue to weaken, and I also had a question in exploration if I may, you budget is $7 billion a year, we’ve had some disappointments in French Guiana, can you talk a little bit about exploration results in the first half and what high impact wells you are planning for the rest of the year? Thank you.
Okay, thanks, Irene. I think I can pass to Simon, but I take on the first one just from a strategic point of view, yes, returns is part of our financial target set, which we are driving internally, but quietly that we are on the path of increasing our returns. You can measure those returns on average capital employed. That’s a medium long-term target, which we have and we drive that clearly inside. It’s not an external target because I think the financial framework targets, which we have are actually the ones, which are driving our overall returns to the shareholders, and this has more details on the first one from Simon, but then also exploration.
Thanks, Peter. Thanks for the questions, Irene. The returns growth balance is something that is easy to talk about in terms of strategic themes than it is for Shell overall. and technically, we don’t have an overall return target, we do have a cash flow growth target, and we do have a capital investment constraint. So for Shell as a corporate entity, if the cash flow growth is delivered and we only invest the program of the 130, then by definition, returns will go up by a couple of percentage points whatever the macro environment is.
So there is an embedded returns target, but not an explicit returns target and there is a clear linkage, royalty is not an independent metric. It would maybe the wrong thing to do to make it so even, because royalty is essentially delivered by at least as much by portfolio choices, if not more by portfolio choices as and it is in the individual assets or project level. So within the main strategic things, clearly the Upstream engine in the material business is a very high return business. The Downstream is a returns focused business, you’ve heard us say that before, it will continue to be and returns are slowly beginning to edge up there.
The deepwater, the integrated gas, are growth areas, but they already have good returns 15% plus. The aim there is to grow and maintain the returns at that level. The future opportunities, the Iraq, Nigeria, Kazakhstan heavy oil, at the moment the returns are relatively low there, but there is a program in place, all projects coming on stream that will make a difference there. And just following-up one of the earlier questions, the capital not currently presented is about $65 billion. In the next few couple of quarters, the project that Peter talked about, the five projects will bring over $15 billion into productive use, that is currently on the balance sheet and not yet in production.
So over time, the delivery of one target leads to improvements in other metrics and that’s how we think there. And the exploration program $7 billion per annum is $4 billion on the conventional activity, $3 billion on the unconventional of which about $2 billion is in North America, $1 billion is in – were primarily China and Alaska. So unconventional as far as China we progress, we can see beginning to see line of sites through economic developments, requires cost come down a bit, better knowledge of the production rate and the reservoirs, and a clear view on the gas price, but progress is positive.
In the North America itself on the exploration side, you can tell from the results that we produced, there have been some pluses and minuses on that almost all activities actually on the liquid-rich side at the moment. So some of it has not been successful, but some are.
Obviously, you will see developments there going forward. On the conventional side, we’ve had successes so far. We talked about Australian gas and Pittsburgh in the Gulf of Mexico, which will certainly help the economics of the (inaudible) development. Second half, coming up we have Albania, where we are on production test at the moment. We are drilling in gas oil, the gas, on the Queen and current wells in the Gulf of Mexico that overall target. We’re about to spend, I believe in (inaudible) deepwater when – the rigs now will then move on to Gabon deepwater in the second half of sub-sell prospect West Africa.
So those are the key prospect with a potential high impact as we are headed forward through the years. That is more also in Australia, in both Brunei and Malaysia, and we’re just taking new acreage in the North Sea. So it’s a very full program over the next couple of years. And we look forward to sharing with the outcome.
Thanks, Simon, and thanks Irene. Now, next question, operator.
Thank you. The next question comes from Hootan Yazhari from Merrill Lynch. Please go ahead.
Hootan Yazhari – Bank of America Merrill Lynch
Good afternoon, gentlemen. I just wanted to focus on the North American business, if we may. First of all, I just wanted to understand whether there have been any price reviews in your impairments with regards to the North America. And given where we are with liquid-rich shale pricing, if you haven’t looked at pricing whether there are any risks, when you undertake any reviews there for further impairments?
The second things I wanted to see is really how the asset disposal program in the North America onshore business will interact vis-à-vis your onshore strategy in the Downstream, i.e., with regards to gas to transport LNG and GTL. Whether you having to accelerate any positions there to get more clarity and what assets you can sell in the like there? Any clarity there would be much appreciated. Thank you.
Thanks, Yaz. For the question, Simon takes the first one, I take the second.
And Peter, the pricing expectation for gas have changed, but mainly that was an impact in 2012. Q3, we took smaller impairments by $600 million in Colorado and Louisiana that reflected a lower expectation for gas prices. The recent impairments, the current impairments, they are driven more by understanding of the assets based on drilling results both what it tells about the subset as for those are the production rates that we’ve been seeing and while they have not much mapped out to expectations and that had an impact on potential development project and clearly that also reflects the lower price that we reviewed last year and our latest expectation for the realization of prices of liquids themselves and NGL condensate or whatever within the North American Continent.
It’s primarily driven by operational results not price reviews this year. What happens in the future well some of the portfolio remains exploration with some appraisals to go. We have done a scrutinized review of the entire portfolio almost molecule by molecule over the last six months. This reflects our best view taking values either the current value in use or the potential sales value, nothing has been written off to zero, it’s held a value we say appropriate. And as we go forward, we are still subject to exploration results on some parts of the portfolio, but the $24 billion of remaining capital employed as of today, looking forward, has been economic development prospect. Peter?
On the second one, I think you need to distinguish in the divestment strategy between gas and the LRS. So what we’re announcing today is much more focused on LRS rather than gas. The integrated projects, which you are pursuing, which is gas-to-chemicals, potentially gas-to-liquids, and gas in transport and also LNG exports, some of them are already under design construction, which is more on the LNG and the gas to transport side. They continue as normal, we are looking at or moving forward on gas-to-chemicals and gas-to-liquids at the normal pace.
So no acceleration, we just do that, which is by the way one of the drivers of the higher feasibility expenditure, which we have in the America. Then once we take those integrated projection decisions, then we will look at gas molecules again, will decide how much is third-party, how much is own gas molecules, which we will use, and then we take it from there in terms of Upstream assets. If nothing goes forward, then we will have another close look on what we do with our own gas assets in that. So that’s pretty much our strategic theme at the moment and we are moving forward on all of these for the time being and we’ll get to a decision point over the next 12 to 18 months.
Thanks for the question. Next one, operator.
Thank you. The next question comes from Peter Hutton from RBC. Please go ahead.
Peter W. Hutton – RBC Capital Markets
Hi, thanks for question. Can I just ask on the status of two areas really, Pearl, that was ramping up and I think at full capacity for the quarter, gas volumes in MENA were up 33% now as we understand it, those volumes of MENA gas are amongst the higher margins particularly in Pearl, but we sell profits about down. Were there any specific cost relating to the final start of the Pearl or this underlying profitability in Q2 as we would expect to see that going forward? And the second question is, can you just give an update on the status of the repair to the Kulluk rig in Korea, I think is true to that, you may need up to 12 months to get permit. So for summer drilling in 2014, it’s starting to get on the critical path, so visibility on the availability of the Kulluk is coming more to the form? Thank you
Okay. Thanks for the question. I’ll start with the second one. There is no update at this stage in Alaska. As I said, we are not willing, we are waiting for some of the reports out of the external and internal investigation in order to take the learning. The Kulluk is, as you say, over in Asia like it’s the scope for discoverer and this will be assessed in parallel in order to actually get to the right decision towards the end of the year. The permitting of all of this will play a role, but remember that both were actually permitted previously and therefore, you have got a certain advantage because of that factor they were permitted. On Pearl, I think, we are progressing well, but Simon may have some numbers there as well, but I think we are ramping up. It was a good second quarter and from that point of view, I think we are satisfied that we are working ourselves up to the capacity rates. But Simon may have some numbers on that.
Yeah, thanks, Peter. We talked on the gas projects in Canada, about 400,000 barrel a day potential and that’s where we are similar to the first quarter. It was a good quarter operationally. The comparative quarter a year ago unfortunately, we have the (inaudible) and one of the separate units you may remember. So we had relatively high downtime a year ago and that’s one of the reasons for the step-up year-on-year, but so far the progress has been pretty reliable. There is still more we can squeeze out of the margin in terms of availability, but we are on track for where we expected to be this quarter.
Thanks, Simon. Next question operator?
Thank you. The next question comes from Jon Rigby from UBS. Please go ahead.
Jon Rigby – UBS Ltd.
Hi, yes, thank you. Two questions actually; the first is, one on your cash flow targets that you’ve got now, can you perhaps just go back into them and tell me what needs to go right and what needs to go wrong materially around the risking going forward to meet what you need to i.e., was this the big levers still left?
And then second, just going back to the removal of productions target, you referenced the fact that you’ve made choices – value choices to go into things like Iraq and the Repsol LNG that didn’t have production attaching to them, which is fine. But can you maybe turn it around the other way and say, what in the last 18 months have you chosen not to invest in the Upstream that would have contributed to make that 4 million barrels of targets in 2017, 2018? Thanks.
Thanks, Jon. I’ll start with the second one, on the production targets, I think apart from having invested into few areas like you have mentioned like Repsol like gas. We also have as you heard today increased our potential divestments, which will have an impact in that as well. I think over the last 12 months, we have not made the choices, which obviously would have put the target on the risk, but we have clearly slowed down in a few areas, but we have actually also accelerated in a few other areas. But I think what comes to mind is where we took very tough decisions on postponing or getting out of projects like in ROE, we postponed, because of the high prices. we took a slower kind of development in some of the North Sea project, for example one in Norway and other one further down there. So we have actually slowed down projects in order to not spending to the high areas.
They would have had production, but we had other things coming through, which would have delivered the cash flow, because remember we studied the proxy for cash flow growth quite clearly. We have invested in LNG and transport, which we see as a long-term business, which again will give us mainly margin and cash flow rather than the other thing like production volume.
The last one I would like to mention is we have clearly taken the decision to move from gas to LRS, and we made it very clear. Therefore, we have deliberately slowed down the gas side, which would have delivered a lot of gas volumes over the years to come. We switched into an exploration appraisal strategy on the LRS. We have now taken even some further pace out that’s got by focusing more and that over deal so has an impact and that was again, was an economic choice behind it, and the results or rationalization going on there.
So I think there are plenty of things, which we have down over the last few years like postponing refocusing strategy, investing in non-barrel producing type of field, which have obviously given us, let’s say, a good reason now to take that off the table. But the major one is still that we had good discussions with shareholders and they clearly focusing on financial performance over the years to come, is the preferred scenario, because there was a perception we are chasing revenue targets and that’s not what we are doing. We are chasing value targets in the bottom line. We start over to Simon on the cash flow.
Good segue, the financial target. Thanks, John. It’s best to give a full-year update really when we get to the end of the year and have some more clarity, but some indicators as you have – hopefully will help. First of all, the five projects that we noted, the ramp up there and the successful delivery over the 2014, 2015 period is quiet key. There are bunch of other projects as well such as (inaudible) project in Italy, Malaysia, et cetera that will also come on. But fundamentally those are the bigger plays.
It would help to execute clearly that switch into the right development projects in the Shell in North America and then show that we generate cash from those and that’s again what we talked about today. So that’s on the growth side, embedded in our target, our improvement in performance – underlying performance particularly in the downstream. And there are some very strong signs in the performance. Cash flow actually have been working cap as we roll forward every 12-month period, the downstream is slowly but surely delivering those. Although is also an embedded expectation on sum up take on the refining margin environment as well.
And that’s our ability to capture those additional refining margin opportunities is very much part of the delivery what we need to deliver particularly in North America and then through Motiva. So the combination of improvements, the combination of right focus in the investment, but primarily, it’s the deliveries safely and successfully of the project that’s already in late stages of completion and run purpose stage of production as expected. Hopefully, that helps things to watch for. We are not dependent at all by the way on any exploration success, that’s for the next period.
Thanks, John. Next question.
Thank you. The next question comes from Lydia Rainforth from Barclays. Please go ahead.
Lydia R. Rainforth – Barclays Capital Securities Ltd.
Thank you and good afternoon, gentlemen. A couple of questions if I could, one just a follow-up on John’s question really, are you now starting to look at there being an optimal size of production in terms of the Shell’s rig? And then secondly, just going back to the North America and the Nigeria divestments that you are looking at, can you give us an indication of how long you think it will actually take to execute on that front? Thank you.
Okay. I’ll start with the second one. I think I mentioned Nigeria and North American divestments specifically, but I also said around others. So I think you should know that if you just focus on those two, there is more in the pipeline quiet clearly, and as we have to make choices and as we already made choices and they are now coming into the frame over the next two to three years. So I think if you look forward, your divestments will be accelerated and higher in the timeframe 2014 to 2016, and therefore, you have to look at those years because, as you know, you can predict divestments, that really comes instead of the 20 December it comes the 10 of January and you may see it.
So we cannot plan it as exactly like that, but over the next few years, you will see that acceleration given the fact that we have a very long portfolio option pipeline now and we have got these projects coming on stream. So our cash flow visibility and the growth if we go to next few years and also the outlook of post-2015 in terms of cash flow growth through the new project coming on-stream is now higher and needs we kind of actually take some tougher choices in terms of what’s stays in the portfolio and what doesn’t stay in the portfolio.
And on production, internally production will still be a key figure, which we are looking at. As I said, we are value-driven and not absolutely top line driven.
So I don’t have kind of a matching production number. That’s not the way I look at this. We will look at the best project with the best NPVs, the highest IRRs, the best long-term type of returns you can expect and we slated, as Simon said, we look portfolio of the strategic scenes like the port to integrate the gas and how we optimize those returns. And then that will give you as an outcome, then the production, which we are managing. I think I’ll leave it at that rather than to try to have a number here. Thank you.
Thank you. The next question comes from Robert Kessler from Tudor Pickering Holt. Please go ahead.
Robert A. Kessler – Tudor Pickering Holt & Co. Securities, Inc.
Hi. Good day, gentlemen. I’ll try and make this fit as two questions, the first one being clarification on North America shale write-down and the asset sales corresponding to that, how much of this was triggered by moving asset to a held for sale categorization? It seems like you need an event that trigger a broad-based review for a write-down or was it just your annual view process. How much is of the write-down is in Canada versus the U.S. if any? And then for the asset sales, how many or how much that you are considering for sale might be in producing areas as opposed to just non-producing acreage.
Robert, thanks for the questions. I think I’ll give both of them to Simon. There are some embedded accounting questions here as well.
Thanks, Robert. As you are probably aware that question because we normally hold that value erosion review or test for impairment time in the third quarter of each year. Now, what’s triggered this, it is not moving assets that are held for sale, none of the assets are held for sale. Although some of them have been impaired down to a fair market value. The trigger is essentially, three years ago, we started building this portfolio. Then we started drilling it, then we started producing it, and production takes nine, maybe more months, to really understand the production characteristics of what you have, which together with the G&G gives you a much better feel for the quality of the asset and the likely development costs and is that cumulatively, which basically we’ve been talking about this with you for six months.
Then it’s really the Q4 results, and this triggered the bottom up review asset by asset. You may also appreciate that we changed our organizational characteristics around this activity at the same time, the beginning of the year. So we’ve taken a fresh look, fresh pair of eyes, different look at the integrated value, right from exploration through to production, and the cost level that we were able to achieve on drilling and facilities, which actually is improving very well, and pretty competitive across the basins we operate in.
And this is not really cost driven, it’s subsurface driven, plus the production rates would be driven. That’s more accumulative trigger than a single trigger and we haven’t given any indication of specific assets and partly that’s for commercial reasons. There will be poor failure actions, and that’s not in our interest of that individual assets. But by and large as the Canadian assets, we said before the gas asset is looking in good shape. This is not a gas player in most of the LRS activity. On the radar screen has been in the U.S., so I can’t say more than that really. And, yes, some of it might impact as we go forward. When we sell, it may impact production, which of course, would not primarily impact production, but might have impact as the margin on cash generation, but our stat is probably going to be at the margin in the period that we’re talking about.
Thanks, Simon. Next question operator?
Thank you. The next question comes from Michele della Vigna from Goldman Sachs. Please go ahead.
Michele della Vigna – Goldman Sachs
Good afternoon. Thank you for taking my question. We saw the (inaudible) you have added upstream assets with no associated production. I was wondering if you could quantity how much cash flow you expect from this business on a timeframe of three to five years.
Thanks, Michele. We don’t breakout area after area. I think that the Repsol, for example, I mean you have got good competitive information put on the pervious owner or still owner but passing it on to me. We also said actually when we made the deal that we expected $1 billion out of this one on an annual basis, so that gives you a good indication where this is going to end up, so just to give you a reference on how cash accretive these are especially in the Repsol, if you compare it to what we actually paid or going to pay portfolio assets if you exclude the leases for ships, which I think you should. Thank you very much. Next question, please.
Thank you. The next question comes from Alex (inaudible) from Citi. Please go ahead.
Yeah, good afternoon, Peter and Simon. Can I ask just again about the CFFO delivery, I mean, your promising growth, but equally you did promise growth and cash flow in the past. And I think if you look at first half 2013, pre-working capital and disposal proceeds, you’re running it about $5 billion lower than you did in the first half of 2011 in a very similar Brent oil price scenario. So, can you help me explain the difference and particularly what you think has happened to the contribution from Pearl and (inaudible)? And secondly, a very good question, is anyone approached you on assets in North America or asset held-for-sale in North America?
I think on the second one, Simon just said he hasn’t put them actually or treat them as assets held-for sale, but its’ a very old market and I’m positive on this. As I’ve said, these are not or you will close dry assets, these are actually at the slow rate – the Group’s low rate, but may not meet our economic scale of economic development, which we want in order to actually fully take advantage of the cost advantages, which we are building into our operation model, business model, and in this whole area.
Now on your first question, I think I give you the number and Simon can then actually give his views on the cash flow as well. But you specifically asked for carbon, there was a car together actually excluding working capital in 2012, they delivered $5.4 billion of CFFO. I think that gives you which is 12% of 2012 plan. They have produced 370,000 barrels in 2012, which is 11% of our production. So I think they are contributing exactly to what we said.
There are many moving parts I think when we talk about our targets a lot of people always forget that we have sold significant assets over the last three years. We sold $7 billion every year and with quite a bit of production involved in that as well and quite of bit of cash flow. But I think you need to take the totality into account. And we are moving towards our cash flow targets and I think, Simon has explained that very well, on how this goes on. And we have never promised that we will have four times 50. We are working on the project to increase our cash flow and specifically, as we always said from the beginning they are back-end loaded as the 17 projects of which the five we have talked a lot about today come on-stream. And these are little bit of help on the downstream side. We are on the journey for our cash flow target. So I think you always need to look at the whole package and not just the pure comparison. Anything to add Simon?
And maybe just some on the mechanic. Just on the first point Alex, I think the answer is no, not when we started this call, but as it’s now day time in Central U.S. who knows whether there have been any inquiries by the end of the call. The CFFO delivery, I mentioned the tax is about $3.5 billion year-on-year is one factor to show half year on half year. And we are at the low point in terms of the Gulf of Mexico production and actually the UK North Sea production in terms of the liquids, the oil and they will get better going forward anyway irrespective of the large projects that should be on-stream by next year. Quite significant fact is that and the final fact obviously is Nigeria. It’s not producing the same cash flows this year as it did last year and we’ve been through the reasons there. Now, there are both operational and more of timing of payments issues, but reiterate the more general track and the points I made to John’s question about the triggers or the indicators of whether we will deliver going forward.
Thanks (inaudible), and next question.
Thank you. The next question comes from Fred Lucas from JPMorgan. Please go ahead.
Fred Lucas – JPMorgan Securities Plc
Thanks. Two questions guys. First of all, can you step us through the moving parts that’s get you from a net CapEx this year of 33 to a figure of 40, so can you breakdown all the increment post of a negative? And can you explain why if you are accelerating divestments, and Peter, you said you will see high divestments in 2014 and 2015 within the full year program period, why if you go great divestments and you are shedding assets, which will presumably also shed some CapEx obligation. The net CapEx figure of $130 billion for 2012, 2015 is not coming down?
Thanks, Fred, I think on the first one there are a lot of moving parts, but the simplest way to look at this is 33 didn’t include actually the Repsol deal, which has a kind of $6 billion plus take it against the (inaudible) some is cash and some is no cash. That’s an easy way to get too close to your 40. And we have said there are a few moving parts around new project, which have come in like the Elba and gas to transport and I think that’s the rest of it. To be very transparent, we don’t know yet how much the Repsol deal will be at the end, so we’ll see that, but I think is around the net 40, and that’s the right number to take this. We started the year when we announced the deal be more or less steady mostly probably going to the early year.
Now we have changed our views, because it’s progressing well as it goes into this year. I think on the 30 net, that’s the targets, which we have, which corresponds to the financial framework. Again, over 4 years, we are 18 months into it. There are a lot of moving parts. Yes, we do accelerate our divestments. We also made some acquisitions last year, which we have just observed in those targets like we built the Permian, we built some other things.
So I think overall, we are on the right track on the capital side. And I think, as I said, there are a lot of moving parts around there and we will manage this to this number quite clearly, and we see that we have more choices now to make, which we have made now to accelerate some of the investment, if you talk about more investments in 2014, 2015 that’s going to come. We’ll see what impact that all has at the end. Next question, please.
Thank you. The next question comes from Jason Gammel from Macquaire. Please go ahead.
Jason Gammel – Macquarie Capital Ltd.
All right, thank you. Two more on LRS if I could, please. First of all, I appreciate the analogy you’re trying to make to exploration with the LRS. But the primary cost that you have so far would really be related to acreage acquisition. And what you written down here would be at best hundreds or thousands of acres. So I suppose the question is, do you think that you simply moved too quickly in acquisition in an effort to catch up with the industry? And then my second question is really more related to specific acreage positions in the Delaware Basin, Wolfcamp and the Eagle Ford, which appeared to be two blocks on your map. Your acreage does appear to be outside of what the industry has defined as the core of those plays thus far. So are you prepared today to say that you have any LRS plays that you’re confident will be both scalable and economic?
Thank you. I look towards Simon, as well he has stored the number of wells, which we have drilled over the last one or two years. But in the meantime, I would not say that we have moved too far in. We made it very clear last year and actually the year before that we’re moving to exploration appraisal, we don’t move into let’s say the producing areas with one exception and that works very well, which is the Permian, which we have done last year and that’s where we have taken advantage over a special situation of one of the competitors on both these ones. So we took the risk of moving in there. And as you know, for me, this is exploration risk, if it works and we have done so where it works, we have quietly added actually more acreage before the whole thing becomes a hype.
So that’s where we are now going to focus on those areas where we have added acreage and some of the other stuff, which is showing good flow rates and we will just get out of it, because we can not afford and I don’t want to really give green lights to spend the capital, because we have other options as well. So it needs really to meet our hurdle criteria, otherwise it goes out. And I think Simon said it very well, that we have got acreage in the portfolio, which is actually prospective, but we just don’t want to develop it ourselves and use own capital for it. And I think that’s the way we are moving. So I’m looking at Simon if he has got some numbers there, if not then we can always deliver that later on, because I think it’s important that we are not writing off acreage, but we actually have done the work. So…
Thanks, Peter. We drilled about 150 LRS wells last year and we are on about the same track this year, but obviously, focusing on the more effective prospects now, as we see and identify what they are. and in practice, I would say 30% of this year as well have had initial production rates that are very attractive. There is quite a significant talent of potential in the prospects that we see. It can’t be more specific than that, yes, we see successful LRS developments ahead of us.
Okay. thanks, Simon. Thanks for the question. We need to speed up a little bit, so choose the last two. Operator, next question.
Thank you. The next question comes from Alejandro Demichelis from Exane.
Alejandro A. Demichelis – Exane Ltd.
Yeah. Good afternoon gentlemen. Just one question, in terms of the reposition of the LRS portfolio, when we said that you’re expecting these to be on a break-even position either from a cash flow perspective or from our own perspective on the new parameter?
Okay. Thanks for the question. But I think you need to let us work this through first, before we just give any further insight. I think we will be clear in the quarterly or the half-yearly calls going forward on where we are. We have got very good performance in some areas like a permanent center, let us work it first and before we got too specific on setting a costly target for this.
Thanks. Next question.
The next question comes from Jason Kenney from Santander. Please go ahead.
Jason S. Kenney – Banco Santander South America
Hi, just one question going back to an earlier theme. First, on your non-barrel producing positions, and particularly, Iraq natural gas, I mean, is there a risk here that these positions become kind of a black box financial modeling exercise and by implication could get missed in your corporate valuation, but guidance are a concerted effort, try to be transparent on the potential contribution.
Jason, thanks for the question. I hand over the black box to Simon.
Good question, Jason. And the potential, yes, but the good news for you all, it will remain different in the next one or two years, Basrah gas and all the other gas to transport for monetization options that we talked about. So the only thing I can say is, as we go forward and we bring them Onstream and they start to have a material impact. We will need to find the way that will help transparently to understand where the value is being created. A lot of it will sharpen the integrated gas, I expect that you see the earnings of today. But your point is well made and we will need to think about that as we go forward, but it isn’t going to make a big difference in the next year or two.
Thanks, Simon. And also for me Jason, I think we have shown over the last few years that we have been rather transparent on these type of things and I think you have seen it today again in the presentation. We get quite the number of details on these various moving parts, but also in the long-term cash flow outlooks, and I’m sure that that will continue in order to actually make sure that our numbers are fully understood.
I think with that, I’m closing the call. So thanks for all your questions and thanks for joining the call today. The third quarter results will be released on the October 31, and Simon will take your questions there and will take to you. Summarizing from my side, a complex quarter to explain, I’m not too happy about it. I normally like other quarters, but it’s a snapshot, the underlying journey we are on is positive. We’re moving towards a lot of choices to be made as we have good growth outlook, and pleased with $12 billion cash flow in the quarter, which I think if I look around us, is a very competitive cash flow, and the $70 billion over the last 18 months as well.
And with all of that have a great day and hope to see you soon again. Thank you. We’ll close the call operator.
Thank you. This concludes the Royal Dutch Shell Q2 results announcement call. Thank you for participating. You may now disconnect.
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