Royal Dutch Shell Management Discusses Q4 2012 Results - Earnings Call Transcript

Jan.31.13 | About: Royal Dutch (RDS.A)

Royal Dutch Shell (NYSE:RDS.A)

Q4 2012 Earnings Call

January 31, 2013 9:30 am ET

Executives

Peter R. Voser - Chief Executive Officer and Executive Director

Simon Henry - Chief Financial Officer and Executive Director

Analysts

Alejandro Demichelis - Exane BNP Paribas, Research Division

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

Peter Hutton - RBC Capital Markets, LLC, Research Division

Martijn Rats - Morgan Stanley, Research Division

Rahim Karim - Barclays Capital, Research Division

Irene Himona - Societe Generale Cross Asset Research

Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Jason Gammel - Macquarie Research

Colin Smith - VTB Capital, Research Division

Hootan Yazhari - BofA Merrill Lynch, Research Division

Frederick Lucas - JP Morgan Chase & Co, Research Division

Operator

Good afternoon ladies and gentlemen, and welcome to Etc. Venues St. Paul's and to the Shell Fourth Quarter 2012 Results and Strategy Update. I'm just going to take a brief moment just to run through some little health and safety review.

There is no expected fire alarms. If you do hear it, it is the real thing. It works very similar to an airport, so it starts off with a series of bing-bongs and then it goes to a voice-activated system.

The nearest emergency exit is out of this room and turn right. Make your way down all of the stairwell out onto ground floor. Come out of the emergency exit and then again turn right, and you'll come along this street just through the windows here called Albion Way. Just congregate down there and then you'll be met by the representatives from Shell who will then roll-call you back into the room.

If you do need the facilities at any point during this afternoon, please come out of the main suite and then turn left. Alongside that, the team coffee machines are located outside of this room, alongside, any more water, just in case you do need it.

As a little bit of a sort of general reminder, really, all personal belonging should be kept with you and anything of value. Also, as well, just if you have anything that you've not put into the cloak room, tuck it underneath your seat. Just so we don't -- we want to ensure that nobody does trip up over anything.

Okay, I'll leave you to it. So enjoy the rest of your afternoon with us.

Peter R. Voser

Ladies and gentlemen, a very warm welcome to you all here in London, and also to those of you joining by phone or on the Web. We have announced our full year results today. We will run through that. But we want to spend most of the time today updating you on the portfolio and on the strategy and showing you where we are with the targets that we have set for Shell a year ago. So Simon and I will talk to you about 2012 performance and the outlook. And of course, at the end, we will have plenty of time for questions. The disclaimer first, before we move -- start.

We are 1 year into the strategic targets we set out a year ago, and we are on track despite some headwinds in 2012. Our targets are unchanged, 30% to 50% higher cash flow in 2012 to 2015 than the preceding 4 years, funding sustained investment for future growth and a competitive dividend for shareholders.

Global energy markets are seeing continued high levels of volatility. This is the interplay between robust structural growth in energy demand and geopolitical events that impact both supply and demand. Shell has the scale and the portfolio choices to manage a through-cycle investment strategy for sustainable growth. Innovation and a competitive mindset are at the heart of what we do.

Our strategy is delivering results. 2012 CCS earnings were $27 billion and cash flow from operations was $46 billion. We distributed some $11 billion of dividends in 2012, which is the largest dividend in our sector, and the dividend is expected to rise again in 2013.

Shell has some 12 billion boes of resources on stream and another 20 billion boe of resources potential in our development funnel, with new barrels added in 2012 from exploration and acquisitions.

Our growth priorities are clear. We are maintaining strong positions in our base Upstream and Downstream businesses. We call them engines. But we want more Integrated Gas, more deepwater and more resources plays such as shales.

Now the strategy is paying off. Start-ups since end 2009 added substantial cash flow in 2012, $6 billion, or more than 10% of the total, and with more growth to come.

I'm pleased the way our project funnel is developing, and we have built up important new options in Shell. This gives us more choice as to where we invest, which in turn, actually helps us to get the best returns at the right risk balance for shareholders.

Now making sure that we have safe and reliable operations is at the heart of everything we do. We are making progress, and you can see the trackers here heading in the right directions. However, the statistics don't tell the whole story. We still had fatalities in 2012 and other incidents last year. We have to make further improvements. We look at these incidents and take the learning across our global portfolio with a continuous improvement mindset.

Now let me turn to the macro. The rapid economic development in non-OECD countries is driving sustained and long-term demand growth for all forms of energy. Energy demand overall could double in the first half of this century from the year 2000 to 2050. This growth will require huge industry investment, perhaps $15 trillion over the next 10 years.

Higher volatility in energy prices and volatility in our quarterly results is a fact of life. We are looking through these short-term effects and implementing a long-term strategy.

During the last few years, Downstream has been affected by excess industry refining capacity, which has dragged on industry margins. This overhang, currently some 4 to 5 million barrels per day, looks set to continue. More recently, the rapid growth in North American resources has led to depressed prices for natural gas and inland crudes such as WTI and WCS. We expect to see a narrowing of liquid differentials as new industry infrastructure comes into play, although this could take several years.

Low North American natural gas prices look set to stay, which is a major opportunity for Integrated Gas projects like LNG, GTL and Gas-to-Chemicals. Now, Shell is one of the few companies that gets the full value here from integration along the total value chain.

Shell's activities provide affordable, safe and reliable energy supplies for our customers worldwide. In Upstream, we are investing for growth, with a strong focus on deepwater, Integrated Gas and resources plays. In Downstream, we have taken out a lot of capacity in the last few years. Now we are optimizing this reshaped portfolio to maximize profitability, with some very selective growth themes.

On climate change, we're investing in natural gas and biofuels, which have a CO2 advantage, and we see mitigation opportunities in energy efficiency and CCS. For example, Shell is participating in construction of 2 carbon capture storage facilities, storing 4 million tonnes per year of CO2 in Canada oil sands and in Australian LNG.

On the financial side, we are planning for a balance between attractive payout for shareholders today and investing for shareholder value in the longer term.

Now let me remind you about the agenda we set out a year ago. There is no change into the outlook for cash flow, CapEx, gearing and production. And there is continued growth in the dividend. We continued to build out new options in the company, more choice for where to invest our dollars. And by implementing hard capital ceilings, we are driving tough choices in the company.

Our drive to increase our options set means that Shell today is capital constrained rather than opportunity constrained. I think this is a rather different position than many other sectors in the market today, including our competitors. Strong capital rationing means we can prioritize the most attractive opportunities and re-scope or exit from other priorities or positions.

Let me give you a few examples. In 2012, we walked away from Cove on evaluation grounds and went ahead with an attractive acquisition in the U.S., the Permian. We slowed down on North American tight gas drilling and stepped up the liquids-rich plays. We slowed the pace on new FIDs for LNG in Australia, where there is cost inflation pressure. We are taking more time on Gorgon Train 4 and Arrow. In the North Sea, we postponed the Linnorm FID in Norway, where there were cost pressures, but went ahead on the other side with Fram development in the U.K. These are real examples of dynamic decisions, which we can do given the breadth of the portfolio we have in our play.

So let's look at the performance since 2010. Our CCS earnings have increased by some 45%, and cash flow from operations has increased by some 70% to $46 billion. Underlying oil & gas production and LNG volumes have both increased as we deliver our growth plans. And for shareholders, our TSRs, or total shareholder return, was around 40% over the last 3 years, with a softer year in 2012.

Now we have been working hard to improve Shell's operating performance, which is a key driver of those results. Unplanned downtime in Downstream and the reliability of facilities, such as LNG, are now amongst the best in our industry. And on the contracting and procurement side, our Projects & Technology division continues to drive a top-quartile wells performance and to extract value from the supply chain. So remember, we spent roughly $64 billion last year on contracting and procurement alone.

I'm pleased with the project flow over the last few years. We have started up 18 new projects since end '09, which delivered $6 billion cash flow in 2012, over 10% of the total and nearly 20% of our production. And all of these Shell-operated projects here had more than 1 billion man-hours with just 170 lost-time injuries, and I think this is a very good performance.

Now the 3 largest of these developments, Pearl Gas-to-Liquids, Qatargas 4, LNG and AOSP, oil sands in Canada, produced over 400,000 barrels per day in the fourth quarter 2012, and Pearl completed its ramp-up with both GTL trains actually reaching over 90% of utilization rate at the end of the quarter.

Now as you all know, these plays will generate cash flow for shareholders for decades to come. So good progress, but a lot more to do. I think I will pause here for a moment. Simon will give you more details on 2012, and then I will come back and give you the wider outlook. Over to Simon.

Simon Henry

Thanks, Peter. Good afternoon. Thanks for joining us today. Important to reflect the whole context today as we're 1 year into a 4-year financial growth program, and it's good to give you the chance to update on that. But first of all, look at the results that we published this morning. I'll start with my personal disclaimer.

Quarterly results are important, but they are only a snapshot of a much longer period. And I've been asked about this in good quarters or bad quarters. It's the same message. Looking at the full year picture, earnings, excluding identified items, were broadly similar year-over-year, $25 billion; cash flow from operations increased 25% to $46 billion.

The macro effects were, in aggregate, a positive in 2012. Growth projects were a key driver of both earnings and cash flow, some offsets from depreciation costs and higher exploration charges. Cash flow is growing faster than earnings, as you would expect, from the increased depreciation as the growth portfolio comes online.

For Q4 2012, reported current cost of supply earnings, CCS, were $7.3 billion. But excluding the identified one-off items, CCS earnings were $5.6 billion. Earnings per share increased by 14%, and that's compared with the fourth quarter of 2011.

On a Q4-to-Q4 basis, we saw lower earnings in Upstream, but higher results in Downstream. At the divisional level, excluding identified items, the Upstream earnings were $4.4 billion. That's a decrease of 14% against the same quarter last year. The oil & gas price movements in aggregate were a negative Q4-on-Q4. We also saw some increased costs -- increased feasibility expenditures on the new opportunities, higher depreciation and higher exploration charges.

The earnings of course, benefited from the previous investment, the contribution of Integrated Gas, and that reflects the ramp-up of the Pearl GTL project in Qatar. We did see, for a second quarter, a slight loss in the Upstream Americas business, and that's built up basically from a loss in the onshore gas business, profits in the heavy oil and the deepwater businesses.

For the first quarter of 2013 in the Upstream, we should see the impact of growth projects, but let me just highlight that we are expecting some 35,000 barrels of oil equivalent per day of maintenance impacts and exits on a Q1-to-Q1 basis. So less than last year, 2012. And most of that is in high-margin North Sea fields.

Turning now to the Downstream, excluding identified items, the Downstream earnings increased sharply from year-ago levels, step-up in Oil Products, good fourth quarter relative to last year. And that's partly offset by a down -- a relative downturn in Chemicals. That Chemicals lower earnings was mainly due to higher operating expenses and supply constraints of advantaged feedstock, i.e. gas in the United States.

Oil Products' marketing and trading environment was more positive than year-ago levels, very negative year ago, of course. The industry refining margins were firm at the start of the quarter, October-November, as we had seen in the third quarter, and that's supported by industry downtime from competitors. However, by the end of the quarter, refining margins had softened quite significantly, and they started 2013 at very low levels. We've also seen pretty weak demand for Oil Products and Chemicals so far in the first quarter.

Repairs to the crude distillation unit at the Motiva refinery expansion at Port Arthur, they're now complete. Motiva restarted the refinery in January. We are, overall in the portfolio, expecting refinery and Chemicals availability for the first quarter to be below the comparative levels in the first quarter of 2012, due to major turnaround activity that's planned in the Gulf Coast in the U.S. and in Germany.

Our cash generation, excluding working capital, in 2012 was $55.0 billion, if we include the $7 billion of divestment proceeds. Average Brent price, $112 a barrel. Both Upstream and Downstream segments generated surplus cash after reinvestment.

You know, we had a clear strategic target to rebalance cash flow in 2012. We have rebalanced to a positive free cash flow position. The cash flow -- there was a cash flow surplus after investment, the debt programs and the returns to shareholders in 2012.

We did take advantage, towards the end of the year, of attractive debt market rates to add $4.2 billion of new long-term debt to the balance sheet ahead of some repayment obligations in the first half of 2013.

The year-end gearing, 9.2%, that's similar to the end of the third quarter and relatively low in the 0% to 30% range because you would expect that in strong oil price conditions.

The 5% increase, expected dividend increase, that we've announced today reflects both the improving cash flow position in the company, the underlying cash flow, and of course, the confidence in future growth. So we do expect to continue to grow the dividend over time in measured, affordable steps. This is, of course, the policy.

Improving capital efficiency is an important part of the strategy, getting the dollars, investment dollars, to the best new projects. No hard target here, but the value of acquisitions and divestments roughly has balanced over time.

In the last 3 years, we sold $21 billion of assets. That's about the size of a mid-cap oil & gas company. We've refocused the Downstream, fewer markets, fewer refineries. In the Upstream, we sold over 130,000 barrels per day, including late-life positions, assets that just don't fit the strategy, and we shared some of our exciting growth positions with new, strategic partners.

At the same time, we've made $17 billion of acquisitions, and basically, we're recycling Downstream assets into the Upstream. 2012, we've added growth potential in the Permian Basin in Texas and in Australia. We increased our stakes in fields we know well -- for example, in the North Sea -- and where we can add value from expertise and technology. So good progress overall on capital efficiency.

A quick word on proved reserves, SEC reserves. We'll report the details in the 20-F filing, as usual, in March. However, we'd expect to see a 3-year average headline proved reserve replacement ratio to be around 84%, and that figure was 44% for the year of 2012. On a 3-year basis, the average reserve replacement ratio, organic excluding acquisitions, divestments, oil & gas price impacts, that was around 115% over 3 years or an 85% in 2012.

Now the next slide is perhaps more important because it relates to the volumes that are currently active, producing, being constructed or in design. So resources is how we manage the business. And we have a substantial oil & gas resource base in Shell, obviously.

This is only a subset of the total, it's the bit that's being worked. This total subset represents 32 billion barrels of oil equivalent or about 26 years of current production. 12 billion barrels of that is onstream producing today, similar position to last year, but of course, 40% higher than it was 3 years ago.

We have a further 20 billion barrels of oil equivalent or so of resources either under construction or in options under -- and basically in design or in FEED. They should drive the cash flow and the growth in that to the middle of the decade and well beyond in practice. You can already see how this is flowing through into results. You can see the names of some of the projects here.

Now return on capital, on the right-hand chart here. Return on capital in service was 20% in 2012, and that's a satisfactory level of return. But that underlying figure that we see reduces by 7 percentage points to 13% when we look at the capital on the balance sheet not yet employed in productive activity. That accounts for nearly 30% on the balance sheet or $58 billion. Now that overall percentage is reduced slightly in 2012 as projects come onstream. That helps to lift our headline returns, but is, given the investment program, not a number that's going to reduce hugely as we go forward.

Now we started to see a more competitive performance from Shell in the last few years, and we believe firmly that there's a lot more to come here. If you look at the picture for 2012, we have to go only to the third quarter 2012, for we don't yet have information from the competitors. But we have led the sector in growth of earnings and in cash generation, driven by the investment decisions, by the operating performance and the underlying performance improvement programs.

Now part of this reflects the fact that back in 2009, we took the decision to maintain growth spending programs and the competitive dividend, despite the downturn in the revenues and the overall macro environment that we saw. More recently, you can see here, we see other companies in the sector having to increase their spending to levels similar or even higher than Shell's. And in an industry where, we all appreciate, lead times can be 5 to 7 years before you really see the benefit of investment, that should give us a growth advantage for a period over the competition. However, let's wait and see on that. So with that, let me pass you back to Peter on the outlook. Peter?

Peter R. Voser

Thanks, Simon. Okay, let me update you on the strategic priorities. And you will see that we are keeping the momentum on the strategic drive we have had in the company over the last few years. As I said, a year ago, we set the new priorities for the company to grow our cash flow by 30% to 50% for 2012 to '15 compared, actually, to the previous -- the preceding 4 years in an $80 and $100 oil price scenario. And we're also set to use that cash flow to fund $120 billion to $130 billion of investment and to pay a competitive dividend for shareholders. These are ambitious and exciting targets. And we know we've got more to do to get there.

Now I'm really driven by this challenge. It's a unique opportunity which we have, and I think so is the whole Shell company and the leadership teams.

Now we have taken a fresh look at how we manage our portfolio. We're driving capital choices, innovation and human resources along a series of strategic themes, which are really global, rather than just country-level or regional. Each theme has distinctive drivers: Special technology, markets, investment profiles and returns characteristics. Downstream and our mature Upstream positions -- we call these engines -- will see around $12 billion of spending in 2013 or about 1/3 of the organic CapEx. These engines are generating strong free cash flow for the company today, about $11 billion in 2012.

Now here, we are looking to extend asset life through technology and selective exploration in Upstream and working hard on profitability and selective growth in Downstream. The growth priority is in Integrated Gas, where we are #1 IOC, in deepwater and in resources plays, which is both tight gas and liquids-rich shale, where we want to be a global leader in this new, exciting trend. Our organic spend in these 3 themes will total some $18 billion, spread fairly evenly between the 3. You will also see a long-term, what we call future opportunities category here. These are reserves-rich plays, typically oily, but where there is a -- where there is going to be a slower development pace, driven by local conditions, communities and environmental considerations.

So now, let me walk through some of the portfolio, looking through these new lenses. Let's start with Downstream. Now Downstream accounts for some 15% to 20% of our capital investment, and about 1/2 of that is on maintaining safe and reliable operations, with the remainder going into selective growth projects.

We're making good progress with the Raízen biofuels joint venture in Brazil, which has a 35,000-barrel per day ethanol production capacity. In its first full year of operations, Raízen contributed over 10% to our 2012 Oil Products earnings. We're also working on new Chemicals capacity in North America and in Qatar, which would be integrated with Upstream gas for feedstock. These are pre-FID projects, and the Qatar opportunity entered FEED in 2012.

Now overall, we continue to have quite a measured approach in Downstream manufacturing, relatively small stakes in new manufacturing assets, building just 1 or 2 a time and positioning for low-cost advantaged feedstock and markets growth potential.

Now let me turn to Upstream. We are managing the company to get a steady flow of final investment decisions, construction and startups as we replace decline and deliver financial growth over time. We started up 5 new developments in 2012, totaling nearly 200,000 barrels of oil equivalent per day of peak production potential.

We have taken final investment decision on further 7 developments over the last year, bringing the total number of projects under constructions to around 30, which should unlock 7 billion barrels or boes of resources and nearly 1 million barrels per day of peak production potential.

Now 15 of these new fields will come onstream in the next 2 years, and you can see some of the larger ones here: Kashagan, Shell will be the operator from first production. This is a 300,000 barrels per day high sulfur development. Iraq, where we should reach 175,000 barrels per day, the first commercial production on Majnoon in 2013, and we will also have the startup of the Basrah Gas joint venture. And also new oil and gas production coming in Asia Pacific, which is Malaysia and Australia. So putting all of this together, we expect a slight increase in production in 2013 compared to '12.

Now looking a little bit further into the future, we are working on another suite of new fields, which should come to FID in the next few years, with over 30 potential investments on the drawing board and perhaps another 1 million barrels per day of peak production. We are maturing these and other options, and we will launch new projects according to portfolio fit, the profitability of these projects and the affordability, which is, of course, partially linked to the development of oil prices and Downstream margins.

Now let me just take a few minutes to show you what we are up to in some of these projects, some major Upstream themes. Let me start with the engine, the cash engine in Upstream. This category covers Shell's older, more mature positions, mainly in Europe, the Middle East and South Asia. We are working hard here to maximize value by extending the life of oil fields in a safe and reliable way and investing in new production.

In Europe, we have made several portfolio moves in the last year, with increased stakes in growth projects and new equity in older fields where we see technology plays that can add value. This should all result in relatively stable production in Europe for Shell, in what many people see as a declining oil and gas province.

Let me turn to the first growth area, Integrated Gas. Now Shell is the leading IOC here, that's LNG and GTL. Integrated Gas, which is LNG and GTL, earned over $9 billion in 2012, which is around 40% of our bottom line, and generated $12 billion of cash flow or about 20% of our total. We have 22 million tonnes per annum of LNG capacity onstream today, with 7% growth in 2012.

The next tranche of LNG growth for Shell is coming from Australia, with 7 million tonnes per annum under construction, which will lift our capacity by over 30% by 2017. And we have been working hard to diversify Shell's Integrated Gas optionality, so that we can go ahead with the most attractive projects for the next tranche of growth. So we have more than 20 million tonnes per annum of new LNG options under study today, potentially another 70% uplift to capacity after 2017.

Now let me show you some details here. Now here, you can see there's 20 -- more than 20 million tonnes of new options in Australia and North America. We have got more options here than many of our competitors have onstream today. It's a great opportunity set for shareholders as well. Today, there is a lot of discussion in the industry about the cost and price structure for new LNG in the future. Now we don't claim to have all the answers on this one, but I believe that LNG prices will remain dominated by oil price linkages, with some elements of Henry Hub in some contracts. Remember though, that Henry Hub landed in Tokyo Bay today, could cost over $10 per MMBtu. But that's not that far away from recent LNG prices and with higher volatility.

On the development cost side, Chevron recently announced the cost overrun at Gorgon in the overheated Australian market. None of the partners like to see that, and this starts to impact our thinking on the pace of new FIDs in Australia. And we have slowed down there, concentrating really on Prelude, which is being built in South Korea. Abadi in Indonesia, which is also floating LNG, may well be Shell's next LNG project in Asia Pacific. In North America, we are continuing to work on a range of integrated options. LNG for transport is going well, and we have 0.3 million tonnes per annum of integrate -- sorry, under construction there.

Now you may have seen we recently announced the joint venture with Kinder Morgan for a new 2.5 million tonnes per annum LNG facility at Elba. This will use low-cost MMLS technology, and we are working with our partner to reach FID. We also have other gas to transport GTL chemicals and export energy options on the drawing board. This is an exciting opportunity set for us, but also for our shareholders. But it's too soon to say which will go first, because this will still take some time.

Now let me turn to deepwater. Shell is one of the pioneers in this industry in deepwater. We have some 330,000 barrels per day of production today with a strong growth outlook. We are pushing hard on the exploration side and I will say more about that in a moment. We have new -- we have 9 new fields under construction in the Gulf, Brazil and Southeast Asia. The key here is to standardize the development concepts, to control costs and speed up the development pace.

So for example, we have installed 5 tension leg platforms, TLPs, in the Gulf of Mexico since '93. Our latest tension leg platform is Olympus for the 100,000 barrels per day Mars B development. Now as you may remember, we took FID on this one in 2010 during the moratorium after BP Macondo when we saw a cost opportunity with spare capacity in the supply chain. Today, the Olympus TLP has moved from South Korea to the U.S., and we are working on the topsides. Mars B is on track for the late 2014, early 2015 startup.

Mars B and Cardamom are just 2 of a number of projects underway in the Gulf. We have been working on 3 further developments, which is Stones, Vito and Appo. Appraisal drilling at Vito and Appo has gone well, and there is potentially more upside at Appo as we're drilling to the Vicksburg area there this year.

Let's move to some of the longer-term opportunities. Now this grouping covers countries and plays where Shell has access to very large resource positions, typically oily, but where there are surface issues that can slow down the development pace, things like community and government relations, security of our staff and evolving local, fiscal and environmental regulations and legislations. We are in these provinces for the long-term potential and we expect to continue to see a measured development pace.

For example, in Canada oil sands, we're investing in debottlenecking and carbon capture and storage to improve the efficiency and the environmental footprint of this asset. We're permitting, same time, for further large-scale expansions, but there are no immediate plans to take an FID, this is for the longer-term.

We also have growth projects underway in Kazakhstan, Iraq and Nigeria. In Iraq, I already said, reaching first commercial production at the time Majnoon field this year, 175,000 barrels per day is the objective. 2013 will also mark the official start of the Basrah Gas Company, where Shell, the South Gas Company and Mitsubishi will capture flared gas and condensate. So since the initial agreements were signed in 2011, this partnership has already increased associated gas capacity from 240 million scf per day to around 400 million.

Now let me make some comments on Alaska, which is the longer -- which is also in the longer-term category. Now this is not a new area for the industry. Over 100 offshore wells have been drilled in the U.S. and Canadian Arctic today. Alone in the Alaskan Beaufort and Chukchi Sea, some 35 wells have been drilled starting in the '80s, including Shell. And there is some near-offshore production underway by our competitors. Since '05, 6 oil and gas companies have taken up 569 exploration licenses further offshore in Alaska, in the Beaufort and the Chukchi. Shell is the leading acreage holder there and we began drilling operations in 2012. As we said from the beginning, we are taking a very cautious approach in this environmentally sensitive area. We have committed to have 2 rigs in the theater for relief well contingency, and each well will have 4 pressure barriers available to avoid oil spills. We halted the 2012 program early when we realized that the fourth of these barriers, the Arctic Containment System, would not be ready in time.

Despite making some progress, we have run into some problems in the last few months. Our rigs will need work if they are going to be ready for the 2013 drilling season. One, the Noble Discoverer, needs a series of upgrades; and the other, the Kulluk, ran aground in a heavy storm on New Year's Eve and has been damaged. There are a number of reviews into the operating performance in the last seasons underway, internal and external, and we will wait for that before deciding on the next steps in Alaska.

Now let me turn to 20 -- let me turn to exploration. We are driving our long-term growth with exploration and bolt-on deals. We have made a change to our organization in 2012, so that conventional exploration is run as a separate activity from resources plays such as tight gas. This is an actual change, as the onshore activities get larger, and it will allow us to manage the rather different skill sets you need and performance drivers you need in those 2 businesses.

We have been reloading our exploration portfolio in the last few years, with a buildup of frontier exploration acreage, as well as maintaining an active drilling portfolio in our mature heartlands. We have added 120,000 square kilometers of acreage in 2012, or in another way, 400,000 since 2008. On the resources side, we have added some 5 billion boe in the last 3 years, for a cost of around $3 per boe, which is a good performance.

Now let me look at 2012 a little bit more in detail. We added 600 million barrels with conventional drilling in 2012, we had 7 notable discoveries and appraisal successes in 2012 and had a further 20 near field discoveries. For example, the Tukau Timur well in Malaysia discovered over 2 Tcf potential, which in turn, unlocks other nearby satellites and should flow into Malaysia LNG. In Australia, we had more molecules for Gorgon Train 4 and the buildup in the outer ex-mouth, which could become floating LNG. The oil side, the Zabazaba well in Nigeria is part of the appraisal of a sizable oil find and we drilled successful appraisal wells in the Gulf after the 500 million-plus barrel Appo field.

Now let me turn to tight and shale activities. Frac-ing technologies have opened up a very exciting new resources base for our industry, and we want Shell to be a leading player here. We are now in play -- in the play in 13 countries. You can see the buildup of acreage and resources on this slide. I think it's also important to highlight that we have been doing -- what we have been doing to build up our operating capabilities in these plays. We are working to reduce costs in the supply chain, and you all know about our joint venture in China, with PetroChina's service company, the Great Wall Drilling. Managing what we call non-technical risk is also extremely important and there are public concerns in many countries about the safety aspects of frac-ing. You might have seen the global principles that we have published for frac-ing operations covering things like water and community relations. So quite simply, Shell aims to set the industry standards in this area and the standards need to raise -- rise.

Let me give you a little bit more about North America. We averaged some 260,000 barrels oil equivalent per day in 2012 from North America resources plays. There is an important shift in strategy here. We took the decision to switch our drilling dollars from dry gas to liquids-rich plays around the end of 2011, due to the low near-term gas prices, and that change has accelerated in 2012. Organic spending in 2012, excluding acreage deals, was around $6 billion, about 60 to 40, gas and liquids. In 2013, we expect lower spending overall, about $4.5 billion, and dominated by liquids-rich plays, about 75% of the total. So this will mean lower near-term growth rates overall, with less gas development and more liquids exploration and appraisal.

On the liquids side, Eagle Ford is in development mode. We have drilled 148 wells and built processing capacity for around 70,000 barrels of oil equivalent per day, with production at the end of 2012 at around 20,000 barrels of oil equivalent per day and growing.

On the exploration and appraisal side, we are in 10 liquids-rich shale plays in North America and we have added, as you know, the Permian assets and further bolt-on acreage in 2012. We have had successful drilling results in 7 of our 10 plays. These are large-scale, contiguous acreage positions and we are seeing initial production rates of over 1,000 barrels per day for multiple wells. Overall, we were producing around 50,000 boe per day from LRS, liquids-rich shale, in North America at the end of 2012, with more growth to come.

So when you put all of these together, we expect to see attractive growth in Upstream in the next few years. And you can see the impact this is having on our production mix with growth in Integrated Gas, deepwater and resources plays, and more productions from countries like Iraq, Nigeria and Kazakhstan. We're looking for financial growth here, and I see production growth as a long-term proxy for financial performance.

Now project startups since the start of 2010 added $7 billion to our 2010 to 2012 cash flow, and $6 billion out of the $7 billion were in 2012. Taken together with the next wave of projects under construction today, we expect to see about $36 billion, 3-6 billion dollars of cash flow from new projects in 2013 to 2015 combined, or -- and some $15 billion, so 1-5, in 2015 itself. This growth wedge is an important driver of Shell's cash flow target. So 50% of our 2013 capital investment should be flowing through into cash flows by the end of 2015. This is all about positioning the company to have the right and most effective use of capital, getting the balance right between building long-term asset positions and generating early payback and good returns to shareholders today.

Now with that, I pass back to Simon. He will talk you through the financial framework, I then summarize and then we go for Q&A.

Simon Henry

Thanks, Peter. Important slide, that one, in terms of where the growth is coming from in the next couple of years.

So we've given you the outlook for strategy and the portfolio. Let me spend a few minutes on the financial outlook that underpins our strategy, and update you on where we are with the targets that we set a year ago.

So cash flow from operations over the past 4 years, 2009 to 2012, was $143 billion. That was at a $91 average oil price. A year ago, almost to the day, we targeted cash from operations to be 30% to 50% higher over the '12 to '15 4-year period in aggregate, and in absolute terms, that's $175 billion to $200 billion of cash generation in $80 or $100 oil price. We also assumed the cost in improving Downstream in North American gas price environment over that planned period, with more conservative assumptions in the near-term.

So as part of the framework a year ago and as stated a year ago, we targeted $120 billion to $130 billion of net capital spending over the same 4-year period, again, in the $80 to $100 scenario, higher oil price drives higher CapEx cost at the unit basis. And this ambitious outlook is underpinned by the ramp-up of the projects that we've brought onstream in the last few years and the new project startups we've just discussed.

Now last year's cash flow, 2012, from operations was $46 billion or $43 billion, excluding working capital. And then we took that back to the $100 scenario, we saw macro effects, oil price, weak Downstream, smorgasbord of North American gas and liquid realizations, in aggregate represented around a $2 billion uplift. And projects slippage, for example, Pearl and some value choices like asset sales and slowdown in North American gas drilling, were in total around a $2 billion negative effect. So despite those movements, these are the headwinds Peter referred to in practice, we are on track to deliver that overall 4-year target.

And you can also see on this chart how the outlook could be affected in today's Downstream and North America Upstream differentials continue into the medium-term. And it's pretty difficult, even for us, to make the macro forecast that far out, so we do sympathize with yourselves. But you can see it from a structural perspective, what we see today is not going to blow us off course from a free cash flow perspective.

Now we look at the free cash flow carefully, and there isn't actually a simple formula for what we do with it. I would expect, delivering that cash flow, that we consider incremental CapEx, debt management and payout back to the shareholders, they all play a part, although I want to be clear that we see share buybacks as a tool to offset the scrip dilution rather than the primary route to return cash to the shareholders.

Now we delivered pretty robust underlying production growth in 2012, with around 3%, with the growth barrels comfortably ahead of the decline, the natural decline. We are still on track for around 4 million barrels a day of oil and gas in 2017, '18, and that's after assuming 250,000 barrels a day of asset sales and license expiries, some of which we've already done, of course.

So however, there are quite a few moving parts out to 2017. It's still 4 and a bit years away from today. So things like asset sales, the choices we make about the pace of drilling in North American onshore, and of course, we're always subject to uncertainties around the security and the fiscal position in Nigeria.

Oil and gas production is a reasonable proxy for financial growth, but it does not give you the full picture. For example, the Basrah Gas Company in Southern Iraq and Elba LNG export project announced this week, both of these should be profitable, both will provide cash flow, neither of them comes with any Upstream production. So we look at the oil and gas production levels as an outcome of investment decisions on a long wavelength basis and not a primary strategic driver for the company.

Now cash flow should continue to grow more quickly than production. Out to 2015, we're expecting strong growth in cash flow from deepwater and resource plays. We should get an uptick from some of the longer-term players, growth hopefully this year, Kazakhstan, Iraq. And a bit further out, Integrated Gas starts to come back in, drive new growth as the projects build up in Australia. So it's a good balance, good diversity in the portfolio.

Now exploration, it remains the lowest cost access to new resources, and we are a global exploration company. If you put conventional activity, resource plays and the bolt-on deals we've done, over the last 3 years, 2010 to '12, we've invested $36 billion in the exploration appraisal activity. We've added around 12 billion barrels of potential resources, prospective resources. And that's been at a cost effectively, $3 per barrel of oil equivalent.

Now a lot of our activity in the past few years has been about acreage buildup. You saw the slide Peter used, the new basins, early opportunities and assessment. But in 2013, we expect the emphasis to change to drilling. Core exploration and the spending in the conventional exploration will run ahead of the resource plays. We will be spudding some important new wells in the next 2 years. Oil prospects in the Gulf, French Guiana, West Africa, gas plays in East Africa, Asia Pacific, and of course, we'll also continue with resource plays, more drilling in Argentina, China, Ukraine, and of course, we will continue in the U.S. and Canada.

Now we will continue to take a long-term view on oil and gas prices, and we've reviewed the assumptions that we made back in 2008 for both prices and costs. For Brent, we've adjusted our outlook that we used for decisions to $70 to $110 per barrel range, that's an increase from the $50 to $90 that we have been using. And for the Henry Hub gas pricing in the U.S., we're now using a $3 to $5 per million BTU range, which is more conservative. We were using $4 to $6.

By refreshing these markets, we can continue to position the company for oil price upside and of course, the lowest cost gas. The costs do move broadly in line with prices, so the strict hurdle rates that were applied to individual projects are not really changing here.

Our net investment 2012 was $30 billion, 3-0 billion, and that's pretty much in line with the guidance a year ago. And we've taken 7 new final investments decisions in 2012 and actually, 24 in the last 3 years, so that's a good ongoing rate. Spending on these new projects is now building up. You can see that trend through 2012, particularly in Q4, that will nudge the net CapEx figure, including divestments, up to $33 billion in 2013. And I'd just highlight here that about $1 billion of that will reflect an increase in capitalized leases, so it's not actually a cash-out in the year 2013. We will also book around $2 billion of acquisitions in 2013, not only completing deals that we've already announced in the market during the calendar year 2012. And those include, for example, the $1 billion of injection in the Basrah Gas Company and the purchases in the North Sea, Beryl and Sakhalin. So we are allocating broadly similar levels of spend to each of the main strategic themes that Peter discussed in 2012 and '13, and I'd expect this to be a fairly steady trend over the next few years.

The core exploration, and through exploration and appraisal activity that's allocated by theme within these charts, 2012, we gave you a guidance of $5 billion, excluding Alaska. In the end, we reached just over $6 billion, $6.4 billion in 2012. That figure will rise to $7 billion in '13, excluding any acreage acquisitions, and that covers conventional and resources plays, it's roughly 4 on conventional, 3 in resources, and does reflect more drilling.

The returns on these projects, they are attractive for Shell and for you, the shareholders. The portfolio of projects we have underway, that's 30 projects that Peter talked about, has an oil price breakeven on a net present value basis of around $60 per barrel, and that's because we set tough investment hurdles in the company. The primary financial driver for investment decisions is discounted cash flow analysis. We look at how much value we create from every dollar spend in different macro scenarios. Now for every dollar of that CapEx invested, we'd expect to create $1.30, at least, of net present value, technically, present value, excluding the CapEx.

So the outcomes, of course, vary. You don't deliver that on every project because things happen. Project execution, the real macro conditions that we run into and how the projects actually perform when they come onstream. In the end, there isn't actually a simple formula. We have to look at those risks upfront and we take judgments on overall exposure to technology, to country risk, to the capital requirements that we have and the track record that we see in any particular part of the business, the strategic themes. So over time, as the projects come onstream, we expect that these attractive full-cycle returns will translate into a competitive return on capital employed and that in turn drives a competitive dividend. So just let me sum up before the Q&A.

Our business strategy requires very significant levels of capital investment. We have not made any secrets of this. There should be no surprises. We're saying exactly the same things about investment today that we said 1 year ago. This is designed to grow earnings and cash flow through the business cycle. We are on track to deliver that $175 billion to $200 billion of cash flow for 2012 through '15. That will require funding, $120 billion to $130 billion. But as the price is over $100, it will be towards the top end of that range. And that's a net investment program. That in turn drives the availability of free cash flow to pay a competitive dividend. We are on trend to generate cash and to invest at the top end of both of those ranges. Spending levels, any given time, they will be driven by the investment choices we make, but also the macro environment. We will keep a conservative balance sheet to underpin through-cycle reporting. We didn't cut in 2009. We do not wish to cut it, if similar circumstances pertain. And the dividend is linked to the underlying financial performance. With that, let me hand back to Peter just to sum up.

Peter R. Voser

Now, thanks, Simon. We have covered a lot of ground so let me be short in the sum up. Energy demand could double in the first half of this century. Meeting this demand growth with clean and affordable energy will be challenging, but it is an important and major opportunity for Shell. Now Shell is on track for the growth targets we set in early 2012, access to oil and gas resources is a key challenge for the -- our industry, and I think we are doing well at Shell. But we are not shy to sell positions which don't fit our strategy or where others can actually make more value. We have sold some $14 billion of Upstream assets over 130,000 boe per day since the start of 2010. We are using our improving cash flows to increase our investments in future growth. So an ambitious program and lots to do. The expected dividend increase announced today reflects our confidence in the delivery of the strategy and Shell's commitments to pay competitive returns to shareholders. Now shareholders, you, you're investing in Shell for a profitable growth and so do we. So with that, thank you very much for your attention. Let's go to the Q&As, which Simon and I will take together.

Question-and-Answer Session

Simon Henry

Okay, ready.

Peter R. Voser

Okay, good. Let's go here, then here and then there.

Alejandro Demichelis - Exane BNP Paribas, Research Division

Alejandro Demichelis from Exane BNP Paribas. Just one question, that financial framework that you mentioned, how do you see the cost evolving for the company as a whole?

Peter R. Voser

You can take it.

Simon Henry

It's a good question. I'd say our operating expense over the past 3 to 4 years has barely moved. It's just over $40 billion, relatively flat. As projects come onstream, it does go up. And we have actually been spending more on feasibility, choice expenditure, but we've been driving cost through efficiencies. Speaking of the Downstream, our new Downstream director is with us today, and there's a lot of effort gone in, both on the portfolio, but also underlying performance improvement. We cannot offset the cost of, for example, technical resource going up pretty quickly at the moment. And -- but the impact on the ongoing cash flow and earnings can be mitigated through ongoing efficiency and performance improvement. It's a different answer in capital costs, where a lot of their next 12, 18 months is locked in. But the further out you go, the more exposed we are to inflation in the industry and then it comes backs to portfolio choices, avoiding the hotspots.

Peter R. Voser

Okay. Just hand it over there and then go back and come into the front here.

Unknown Analyst

Two questions. The first is on the U.S. A note, actually, that in your new gas scenario, actually, the fourth quarter was inside your $3 to $5 per million BTU, and yet you still made a loss in North America Upstream. And it looks like it's because of a huge amount of capital that's gone in there. And I guess this links back to the point that you make that 1/3 of your capital is unproductive in any one time. I think that was the indication you were making. I mean how do you come up with that judgment about how much capital you are prepared to carry and dilute your returns over time and how fast you want to get that back off the balance sheet? And the second question is more specific. You clearly have line of visibility across the entire LNG world. In a $5 U.S. gas world, what does an LNG export scheme out of the U.S. look like competitively versus one that you might do, greenfield somewhere else, ex Australia?

Peter R. Voser

Okay. Let me cover on the first one, the strategic emphasis we have in North America in total, and then Simon can give you some numbers, which bring some of what you were asking for a little bit more to light. I mean, we are looking at North America as our growth engine for the decade to come. I mean, as the debottleneck, which we went through, it has the gas leg, which we are looking into how much we actually drive into the integrated value chain. And we have slowed down the drilling so we are -- we know the molecules are in the ground. We have -- we both, most of them actually have been on immature stage, so we didn't pay too much for it. We have invested some of it and Simon can give you a little bit more insight. So we are clearly slowing down there and we can wait and for strategically to take these resources out, either when the price is right or when we go further down the value chain. We have switched over to oil -- to tight oil or liquids-rich shales, and that's going well. Again, we have chosen the strategy there to go into the early phases of the emerging basins, which therefore, gives you a different revenue cost amortization and investment profile. Again, Simon will give you some numbers there. We did that deliberately because we didn't want to pay upfront too much money for actually going into some of the very well developed resources, which are also priced at that level. And then the third leg, which clearly, we are driving is obviously then some measured increase in production in the North, which clearly is oil sands stream and et cetera. So I think that's the overall strategy. So maintaining all those projects does carry also some costs and you see that in our yearly results, but we are happy to take that forward for the while because we quite clearly see the integrated value as a key driver of future cash flow growth. With that, I stop here and pass on to Simon to answer that one.

Simon Henry

Thanks, Peter. It's a good question and probably worth taking a few minutes to help you understand how this fits together. We have invested, now on the balance sheet, there's $28 billion of capital employed on the balance sheet related to North American shale unconventional resource plays. When we buy a piece of acreage, some of that amount is allocated to the producing assets and some is allocated to what is known as the nonproducing leases. Over time, as we develop the nonproducing leases, they move into producing and are depreciated on the unit of production basis. In the meantime, we amortize the pool, but at a lower rate, depending on what we expect the future outcome to be. You saw the 11 billion barrels of resource roughly. That's what we're talking about relating to the $28 billion on the balance sheet. Of the $28 billion, it splits 50-50 between producing and nonproducing leases at the moment, so $14 billion in each. The annual depreciation is currently running. This is basically the producing assets, $3 billion per annum. And it's that depreciation rate, against what the 260,000 barrels a day or so that is driving the losses today. We are also in 14 basins. Most of them, exploration and appraisal. That's not an efficient process while you're actually spending that money. So it's about feasibility or exploration. There's money going into being in many different basins. We haven't got manufacturing efficiencies yet. But where we are developing in places like Groundbirch and Marcellus for gas, we can produce economically at a $3 gas price. On the liquids-rich shales, we are now -- actually, it's about 75% drilling spend and it's actually 33 rigs in total that we're running -- 38 rigs at the moment, of which 30, 31 are actually running on LRS. So it's basically 3/4 of the rigs running on that. It was the other way around a year ago. And of course, we ended the year, liquids-rich shale, with over 50,000 barrels a day of production. We started it with 10,000. So there is growth coming, but because a lot of the activity, 150 wells last year were in E&A, exploration and appraisal, against 450 of the total. That E&A on the liquids-rich, which mostly where it was, will move into development as we take development decisions. It's not going to make a difference to Q1, Q2, maybe not Q3. But over time, we will see liquids production coming back in according to the investment proposals -- plans that you've seen outlined there. Now we haven't made some of those decisions yet, so I can't give you any more details. But hopefully, that gives you a feel for the shape, the kind of depreciation we're seeing. It is still cash positive, just, even including that feasibility-type spend, but it is earnings negative today. Upstream Americas overall delivered over $6 billion of cash, albeit only $1 billion of earnings in 2012. You can imagine this, even from the fact, I even know the figures, that it gets a lot of attention from the 2 of us, and from Marvin, and we're doing everything we can to get the rigs in the right place, get the costs down and work those earnings into the right place. So hopefully, that's helpful. There was a question about $5 world and exports.

Peter R. Voser

Yes. On the LNG development on a worldwide basis, I think we all know that transportation and liquefaction cost, if you add to that, then you are in the $10, $12 range in Asia, for example, and based off today's Henry Hub prices. So that's what we need to keep in mind when we look at this. Now the way we look at all of this is actually much more that we take this LNG into our pool, in our worldwide global energy pool, which we have. And therefore, we can obviously allocate the LNG in different ways. We can substitute some Middle Eastern or other LNG, which comes to Europe goes to Asia, and some American goes to Europe. So we are optimizing a global LNG portfolio and that gives us much more flexibility and allows us actually to optimize our supply sources in a very different way. So we are most probably different to most other players, which have much more a 1:1 relationship when they actually take some LNG in, let's say, North America, and then they go to one customer. We have much more flexibility of that. And therefore, what we just announced a few days ago, that's just LNG which comes into pool, which gives us much more diversion, flexibilities and delivering it either to Europe, where you need to add $5, $6 to the price, 4x worth in liquefaction. Then you have more or less, European prices. I think what the U.S. at the moment shows is an advantage on the cost side like also some others, like in East Africa, which goes a little bit to the detriment in Australia, where we have high cost. But I would warn now, if too many LNG projects and too many crackers are coming into the construction phase in the U.S., you will see cost going up very fast. We have seen this in the past, that certain areas in the U.S. didn't go up. So for us, it's important enough where the most recently announced [indiscernible] comes into it to be ahead of the curve in terms of infrastructure and other supply or, let's say, construction costs and get the LNG in that and actually where it is more needed in the market. So we are looking at that very carefully. Okay, all right. So I go front and then I come back there. So, Theepan?

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

It's Theepan from Nomura. Three questions. Just quickly, could you just talk about how the accounting treatment on Alaska and your spend there, is all of that spend capitalized or not? And secondly, you mentioned $2 billion as a cost for sort of project slippage from 2012. How confident are you can recover that, that amount in 2013 and is it largely a deferral from Pearl? And then thirdly, Peter, you mentioned that you're not shy on disposals. I think I've asked this question before, but every year, you talk about $2 billion to $3 billion, or more recently, $2 billion to $3 billion of disposals and then you exceed that number. Again, with the macro conditions towards the top end, particularly in terms of oil prices, I'm just wondering whether actually you should be accelerating disposals at this point in time in the cycle.

Peter R. Voser

Alaska numbers, I think Simon can give them. On your second question, there are -- there were 2 or 3 things. Pearl was the biggest contributor. That's why I said it's now above 90% capacity, I think we have started it up, so that will come in and should produce actually at the full capacity rates. Now let's just be clear, Pearl will not run at 100%. That's a very complex refinery system, which we have. So most probably -- it's even a little bit more complex than a complex refinery. So the availability will be in slightly below top quartile of a refinery system. But it's now up and running and that has contributed quite clearly to those 2 billions and that's the major factor, I would say. So otherwise, we would have been further ahead. On the disposals side, it's an interesting question because this -- portfolio management is key for us. And we do disposals and we do, from time to time, also acquisitions. Now when you look at the chart, you'll see the $7 billion, the $7 billion for quite a few years where we developed that. I think and Simon has shown you the total amounts of, I think, $21 billion versus $17 billion over the last 3 years. We have a very strict policy and drive for portfolio optimization. When we see opportunities, we will go for them and divest, et cetera. So there is actually no kind of limit in our target internally. We give you that number because we just want to make sure that you know actually that we are kind of turning our investment portfolio around. And we are getting out of stuff where we think we cannot add too much value or the market is paying more. We have a few of those assets. We will judge the situation when it is best to get out of it. And we have proven over the last few years, even if you have a production target or a cash flow target, if you can get more money by selling it, we will sell it and actually and tell you as investors that we are actually making more money for the shareholders. So I think it's a reasonable figure to have 1% of your capital employed as part of a target externally, but we actually look at a long list of potential assets which we could divest, et cetera. And we will take them when the price is right or the opportunity is right, using it for a swap or whatever. So it's really part of our capital discipline structure and we run this in a very structured approach with our businesses. So it's steered by the 2 of us in order to make sure that we have got enough discipline in the organic, but also in the divestment and the acquisition books. So...

Simon Henry

Thanks, Peter. Alaska first, just again, you might want to get your pens out. It was around $5 billion spent since 2006, of which $2.9 billion remains on the balance sheet. Of the $5 billion, $2.2 billion was on the original bonuses. That's now been amortized down to $1.7 billion. The other $1.2 billion is capitalized activity, including the drilling since we took on the acreage. We took a $40 million charge for salvage in Q4, which is in the results. One of the reasons, UA was in a loss. And we can see another $50 million, basically in January, associated with that particular operation. But we haven't yet recognized because we don't know any cost of repair for the Kulluk or the activities going forward. So we are capitalizing that which contributes to the asset of 2 top holes at the moment, and the total on the balance sheet included in that total capital, not yet productive, of course, for Alaska is $2.9 billion.

Peter R. Voser

Okay. Go back there.

Peter Hutton - RBC Capital Markets, LLC, Research Division

Peter Hutton from RBC. The net CapEx guidance that you give obviously includes the mix of the divestments, organic CapEx and inorganic CapEx. Now given that there is inflation and you say that beyond the 12, 18 months, we've seen inflation to which you are exposed and we appear to be at near peak cycle in terms of the oil services, but yet a lot of companies in the sector are not -- have asset values, which are not at peak cycle implications. Can we expect any switch in the balance between organic CapEx and inorganic CapEx, in that they both come within that net CapEx category? And then that leads onto the next stage, which is a number of people that we speak to will say, "Well, at the -- you know, on these new CapEx numbers, Shell appears to be much closer to free cash flow breakeven and therefore similar to a lot of your peers." But the reaction is, "Well, yes, exact you've got 9% gearing, the very, very low end of your range." Given that low gearing, should analysts, investors expect you to maintain that sort of conservative gearing and therefore free cash flow breakeven? Or actually, for growth at the moment, is this an opportunity to be using some of that gearing to invest for growth and therefore, people should be more comfortable with a period, over the next few years, of negative free cash flow, which translates into growth?

Peter R. Voser

Okay. Let me just repeat on the net CapEx side. We will share some of that, because obviously, he is the [indiscernible] of the balance sheet and the gearings. While I can talk a little bit as well. So we have 34 organic growth versus the 32 we had in 2012. That is not inflation-driven. This is activity-driven. We have, through our P&T organization, we have actually maintained a very rigid control of the costs and what we have seen by taking early FIDs, but also early kind of long-term contracts with our -- with rigs, et cetera. We have actually controlled, let's say, the cost quite significantly. By taking our $65 billion spend and putting them into enterprise framework agreements with selected suppliers, getting discounts from anything from 10% to 40%, 50%, that's how we are driving actually our cost or at least controlling our cost so they don't go up. And then getting -- then we have the 2 -- and in that 34, by the way, there's $1 billion noncash leases, yes? So it's actually a 32, 33 in that sense. So and that is reason we have more activities. Now I've said this many times. We think that is actually what we have in our targets, we have significant cash surplus to come. Now if I look at all your models from time to time, I cannot recognize the cash flow numbers, but okay, I leave that challenge to you. So I'm not looking, together with my CFO, at the cash surplus, which is actually breakeven or negative. So therefore, I think we are delivering on the value propositions which we have given that we are actually balancing the shareholder returns through dividends and long-term value by driving a disciplined capital program. Using the balance sheet, yes, you would expect to be very low gear at the moment because of we are at the higher end of the cycle. I hear some of the noise that some of the service suppliers start to say it's coming down. I can't see that we are actually now in our industry stopping investing. I think we are actually pretty much going to the peak at this stage, at least from where we sit. I think you might have heard this number. There's $650 billion going to be spent in our industry over the next 12 months. And I can't see that actually slowing down at the moment. So I think having a conservative balance sheet, that's what I expect from Simon, but I now move it over to Simon and he can tell you how we actually, we manage that a little bit either looking very forward. So...

Simon Henry

The fundamental of the starting point, we don't plan the balance sheet on $110 oil. If that happens, it happens to be advantageous and it creates opportunities for us in the event that the oil price does fall, because we will have the financial firepower to continue organic investment and who knows what opportunities come up for the more stronger financial players in that environment. So the gearing is more an outcome of where we are in the cycle and the choices we make, rather than the driver of how, let's say, how keen we are to spend the money. Small acquisitions of either assets or on occasion, companies, will always be part of our strategy. And it's almost certain that they will be immature in the majority, because where do we add value at Shell? By bringing development capabilities with technology. So what you've seen in the Permian Basin and Australia previously, that will continue. It's obviously a little bit opportunity-driven, but it's a bit opportunity-rich out there as well at the moment. Not only are assets attractively priced, some of the current owners are financially disadvantaged or distressed. So that makes a lot of sense to do that. So we can do it, but it's not a strategy to go and do. We haven't said, "Here's a $10 billion pot. Now go spend." It doesn't work like that. We always consider, quite often, we might pay $1 billion, $2 billion to enter an asset and the follow-up is $5 billion, up to $10 billion. So we need to think that through very carefully. If you think about it, that's one of the reasons we stepped back from Cove. To get to a material acquisition percentage of that asset would have cost, in addition to the follow-on CapEx, another large chunk of unproductive capital, but we felt was just too big. And that was how we thought about that particular opportunity at the time. So it's a good example. Then we just have to balance, I guess, on an ongoing basis, our shorter term views about where the oil price is going with today's dividend and today's gearing.

Peter R. Voser

Your hand was up. Then I come over here.

Martijn Rats - Morgan Stanley, Research Division

It's Martijn Rats from Morgan Stanley. I wanted to ask you about 2 topics. First of all, over the last couple of months, we've seen a number of midterm forecasts on oil markets that have called for quite sharp builds of spare capacity and then quite rapidly falling call on OPEC. The IEA, the EIA, OPEC itself, the BP Energy Outlook all call for 6 million barrels plus the spare capacity. I was wondering how that compares to your own internal assessments, what do you think of the probability of that scenario and whether it is slowly but surely creeping into your own sort of strategic consideration and investment plans. And the second thing I wanted to ask you about is the Oil Products' result, which actually improved quite dramatically compared to the run rate of the last 2 years, plus 70% in terms of earnings. And I was hoping you could be a little bit more explicit about what the sources of that earnings improvement is and how much of that is likely to carry over in the next year or 2?

Peter R. Voser

Okay. On the first one, clearly, the growth in some production volumes led by the U.S. tight oil initial, let's say, drilling has clearly, given us oil capacity. The demand, it was somewhat sluggish. So you would agree, that most of you, will see some of that playing out in 2013. If I look at how we plan, how our economists look at it and how we look into the 5, 10 years' time horizon, we see this being eaten away very fast as soon as the macro environment starts to creep up again. So personally, I'm not of the opinion that you will actually see a falling oil price for a prolonged time because of overcapacity. I think you will get volatility and that can be up and most probably more down than up, but I think as soon as the U.S. engine, which I think will start to fire on all the cylinders pretty soon in '13 and I would expect Asia Pacific to be the same. We see already in some of the very early cycle segments, that you see some positive signs coming through, and I would expect that to be better in the latter part of the year and I have a slightly different view. I think the hype on -- of tight oil is actually overplayed in some way. Now that one hurts us in a certain way, but as Ben would say, also -- it will give us a lot of opportunities over the next few years because we are an integrated player also in the United States and that will help us. On the Oil Product earnings, that's not unusual to Jeff, so that was last year. So there's still more to come and he knows that, and I think we have good results, but we have continuous good performance on marketing and trading. And we saw clearly a turnaround on the refining side and there was an overall margin improvement compared to the year before, but I think more important, actually, we run our refinery -- our refineries at the top quartile end of actual operational performance, and this helped actually to have the thing running when actually you can capture margins. And that was certainly the case in October, November when the margins were high. I could just tell you in December, it all collapsed again. So the golden age of refining this time was exactly -- I don't know, 90 days long and then it has disappeared again. It was much more driven by maintenance shutdowns, et cetera, et cetera. So I think I wouldn't count in '13 for having a refinery environment which is easy, I see it quite complicated, but what really drives the OP result is marketing and trading. And as long as the refinery is actually keep working at the top quartile end, we will capture the right margin at the right time. So it's -- we had a good year, I have to say. They really responded well to some of the operating challenges in 2012. Chemicals, very bumpy, 2 halves: first half, good; second half, macro economical drive downwards. And that clearly then gave us lower results. And then because of shutdowns in some of the refineries in the U.S., it gave us a little bit less advantaged feedstock for moving it into the Chemical side and that has kind of driven some of the results in the fourth quarter down. But that's a normal shutdown time, of course, so. Good, go over here and then afterwards, Irene.

Rahim Karim - Barclays Capital, Research Division

Rahim Karim, from Barclays. Two questions and a clarification, if I may. I'll start with the clarification. The net CapEx number of $120 billion to $130 billion, I just wanted to check, the cash flow estimate also reflected those divestments or whether the cash flow estimate of $200 billion included divestment effect. In terms of the questions, very helpful chart in terms of the cash flow growth and the new projects coming onstream out 2015. So thank you for that. Just going to ask what we should expect for the base and how we should expect that to evolve. Obviously Downstream, probably, not growing all that much, a little bit in the U.S., but more focused perhaps, on any guidance you can give on the Upstream. And then just thinking about the shale potential, you've talked about new 13 countries. You've obviously had a lot of experience from the U.S. We've talked about how capital employed has been building up there quite rapidly over a short period of time. Should we expect to see similar kinds of builds in those plays. Is there a total amount of capital that you look to play globally in the shale play or are the opportunities outside the U.S. different for various reasons?

Peter R. Voser

You take the first 2, I'll take #3.

Simon Henry

The net $120 billion to $130 billion, if you work it backwards in the assumptions on divestment, there will be further growth in the organic capital investment, is just one thing I would suggest, $35 billion and beyond. The CFFO $175 billion to $200 billion, as it plays at the moment, we would expect is never -- this has never been a slam dunk by the way. We know we need to get all of the cylinders in the engine working. And we're making progress there. So they are consistent, but every Lego brick in the wall, not all -- not all there, and I couldn't give you an equivocal assurance that the numbers add up on every asset. And as the base CFFO develops, well, you got the 15 from the new projects. Well, there is some growth in Downstream and some of it, from an expected macro, but 60% of the growth in the Downstream is -- will be on Ben's list of things to do over the next 2 to 3 years. And so there's quite some improvement potentials, still in there in terms of efficient and effective operation of assets meeting customer comps, et cetera. And almost then by definition, the Upstream base performance is the balancing number. What we do have, remember, in the Upstream, there's increasing proportion of significant long-term assets with pretty limited decline. So we are outstripping decline pretty steadily over the past couple of years in top line production terms. That is expected to go on. And we will have increasingly resource play contribution. Those liquids-rich shales will grow and they're not all in the $15 billion. That $15 billion only includes the proportion that's already under development, and these things give very early cash flow, almost by definition. So I can't give you a number. But in essence, it is the balancing figure, and overall, in aggregate, the figures are consistent. The $130 billion should lead to the $200 billion in a $100 environment. On the 13 new countries, I'll just say one thing on the numbers. Typically, in the U.S., you've put a big signature bonus on an acquisition. Typically, outside the U.S., you're not paying a big signature bonus. You're committing to invest or put a drilling or a seismic program together. So there isn't usually a big entry fee. Peter, in general?

Peter R. Voser

I think the way we start with and that's -- I've given for Integrated Gas, deepwater and the resources play, $18 billion in 2013, roughly, 1/3 each. And I think you're looking at 2 completely different developments. North America will be the driver in terms also of the spending and where the volume will come. I think the others, we are going into the exploration de-risking phase. And therefore, the kind of the higher CapEx where you let your kind of manufacturing machine and drill well off the well will come later. It's most probably China, the most advanced at this stage, going in some areas into that spending, whilst Ukraine, Turkey, Colombia or Argentina, we are much earlier in the cycles. So therefore, you will have smaller amounts which will be spent there and could then ramp up later on into the second half of the decade, but not earlier. So main growth is going to come between now and 2017 in all of these resources plays, it's still going to be North America. Irene.

Irene Himona - Societe Generale Cross Asset Research

Irene Himona, Societe Generale. Two questions please. You mentioned the change in organization in 2012, in running separately the conventionals from the resource plays. I wasn't sure if that is a change just for exploration or across the Upstream division. And if it is across the Upstream division, is it quite a major change? Does it involve shifting people, geographies and so on? And ultimately, what's -- I mean, it sounds very sensible. What do you hope to extract in terms of specific targets and objectives? My second question was specific to Russia in the Upstream, just an update on where we are with next phase cycling of resources and indeed Salem [ph]. You have some exposure, I think, to unconventionals or tight oil in that license. Is that something you may expand in the future?

Peter R. Voser

On the changes in the organization. I think we have done 2 things. One is the one I mentioned in the speech, which is really splitting the different business models. So I want the explorers to go back to where they are best to do and that's provincial exploration, and really have the business model development on the liquids-rich shale or on the gas side, actually, much more done as a value chain or a process. Because what you need to build there is the manufacturing capabilities and you need to have all of that actually under one organization. So we have an organization for the Americas, on nonconventionals and we have one for the rest of the world. But they're obviously ex -- using the skills which we have built on both sides. And then you have the 2 conventional exploration teams where I really want them to go back and work the acreage which we have bought over the last 2, 3 years now and work that very hard. Because we could quite clearly see that we were suffering somewhere on the exploration side, conventional, because everybody was focusing on the unconventional side. That's one. Is this a major change? I wouldn't say that's the major change. But we did a lot change but a little beyond the radar screen, because we wanted to sharpen the operational focus. And that's mainly between UIs or Upstream International and with P&T. So we have actually scrapped the regional organization in UI. And what we have done is we've put an operated production unit together and a non-operated production unit together, in order to really focus on the operational performance of those assets which are actually onstream, increasing that. And that is a major -- a major exercise, it is behind us now, so has all gone below the radar screen at the end of last year, over the last 4 or 5 months. And as part of that, we are shifting another 3,000 people from UI into P&T. So P&T will now take practically all projects under their wings as we have made with the big project to move already in '09, because we see the benefits of standardizing, of driving the project work actually out of one big organization. We haven't done that step back in '09. We just -- we didn't want to overload P&T, but they are now running hundreds of projects yearly, and for that, we have moved 3,000 people over. But that's done and they have their plans to deliver in 2013 and they're working on that. But it's all driven by sharpening the operational performance to get really the -- all the barrels out of the fields. Russia, not much new on Sakhalin 3. Discussions are ongoing. Pre-FEED has been done, and we are discussing that on how we can take Train 3 forward. Salem [ph] is in a big -- is in an area where there are big unconventionals around it. I would just say, at the moment, there is potential and discussions are ongoing. Now I'll come back then, while I go to the back, just for one from the Web and then I'll come back for you. Okay, can you talk on the phone or the Web?

Operator

The first question comes from Robert Kessler from Tudor, Pickering, Holt.

Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Some question on your result and then also an implication for plans going forward. On the results, when I look at the U.S. production, it performed quite well in the quarter. And clearly, that was in part the result of the contribution for some inorganic activity that, I wonder if you could quantify, say, the addition from the Permian in the quarter. And then looking forward, could you give us a well count perhaps, in terms of what you plan to drill in 2013 and maybe split it between liquids and nat gas?

Simon Henry

The Permian contribution was about around 25,000 barrels a day for 2 months, so 2/3 is what, 16, 17. The well count, the actual activity is roughly the same as we go into the year. We drill 450 wells, 80% will be in LRS or wet gas plays. It's primarily Eagle Ford Permian and the variety of exploration basins. At the moment, it's about 1/3 exploration and appraisal, 2/3 development activity. The remaining wells would -- remaining 20% of the wells would be in dry gas and that will be primarily development wells in the Marcellus and Groundbirch.

Peter R. Voser

Let me just add on production. I think the deepwater production actually was very good and very strong in the fourth quarter. We've done a good job on actually improving the operational performance and reducing the deferment or the unplanned shut -- downtime quite significantly. So good performance in the deepwater as well. Go here.

Unknown Analyst

Can I just come back to the question of North American output. If you look at that 2017 target of 4 million barrels a day, what's the contribution of the North American on the conventionals piece? And at what pricing point does that need to get to, to get an economic return? You mentioned $3 gas in the Marcellus and Groundbirch. How about a similar reference price, perhaps, on liquids?

Peter R. Voser

As we show in one of the charts, you see that some growth is going to come from North America. I think we are looking at roughly 250,000 barrels to come from liquids-rich shale versus the outgoing 50 which we have at the end of 2012. I think overall, we should be around 700 by then, approximately, but it depends all on all pricing and how fast we invest. And I think we were, last year, on 250 roughly on the liquids-rich, on the conventionals.

Simon Henry

On the total.

Peter R. Voser

Total. So that gives you a little bit the numbers on how we're looking at that.

Unknown Analyst

[indiscernible]

Peter R. Voser

Yes. You have heard what we are planning. But I think that's too early to say. A lot will depend also on how much Integrated Gas, which we are doing, et cetera. So that's too early for me to say at what price levels we will push forward. It also depends on the cost curve. So actually the learning curve, which we have in many of the liquids-rich shales will also drive that. But we have said, we are -- both numbers we are using for our planning purposes which is the 3 to 5 on the gas side and the 17, around the 10 on the oil side. Yes?

Jason Gammel - Macquarie Research

Jason Gammel with Macquarie. I'm sorry to continuing dwelling on the unconventional production. But 450 KBD of liquids-rich shale production growth between 2012 and 2017, by my calculation...

Peter R. Voser

250. Yes. 250.

Jason Gammel - Macquarie Research

250. Okay. That would require -- okay. Quick math, in excess of a 50-rig program, so can we assume this is all organic growth or is there some supplementary acquisition growth that would come in that? Also bearing in mind that if gas is an analog, the best plays, generally, are driven by sweet spots that are released pretty early on in activity. Second question if I could, 40 high-impact exploration wells, I think, over the next 2 years, can you talk about how many of those wells will be directed at the Northwood trend in the Gulf of Mexico? And approximately, how long you think it will take to reach an FID at Appomattox?

Peter R. Voser

I think the first one is really around organic growth, or do we need some acquisitions. That's the way I read your question. The way I would phrase that one is clearly that we have a lot of acreage at the moment. We are de-risking some of that and I've said out of the 10, we have got 7 where we have got good prospects now. So I think we are driving that forward in development terms. I would never rule out to buy some early acreage again, especially when we find the sweet spot. Normally, if you find them early around there, you can find the rather cheap acreage which you would add to that. So that's how it is planned. As we said earlier, if the right opportunity like last year, the Permian, comes along, which we thought is good to -- by far too good to pass, we will certainly look at that. But that would not be our prime development strategy which we have. So we develop it out of our acreage which we have or maybe add, as I just described, a little bit to that. So it's not an acquisition strategy which drives that growth at this stage. Can you take the second?

Simon Henry

Deepwater, there are 5 exploration wells planned this year in the Gulf. I'm not enough of a geologist to tell whether it's the Northwood or otherwise, but those are the new ones and then the 3 appraisal wells as well. Just on the overall deepwater program, we're ramping up to 16 rigs with the potential to go to 18, that in practice reflect potential exploration success. And it's not just the Gulf. Remember, we're in French Guiana, in Brazil, West African trend. So we are building up, and some of those rigs, you may recall, the Transocean deal, 4 rigs, that will be delivered as of 2016 onwards. So we are committing out -- effectively, there are 14 drilling string years of high-tech, state-of-the-art, effectively, low-cost, high-efficiency drilling. And we're changing the way we deal with the fleet in that way. We'll have 8-plus rigs by 2016, will be either ours or committed to us for a very long period of time. And this a significant shift to the way we think about providing, at the right cost, the right capability to play out the portfolio. At the moment, more than 1/2 of those rigs are in the Gulf. But increasingly, the Gulf will be important, but it will not dominate as it has done historically. So that's why it's quite an exciting program. There's new rigs coming on. What -- we've got a new Globetrotter rig coming on, our design. It's going -- it's an exploration rig for West Africa. Ceri Powell, Head of Exploration, International, it's her rig to take with, use as appropriate. It's already been used to farm into Benin, because we have a good rig available at the right price.

Peter R. Voser

And that's why it is, from a strategic theme point of view, very important to get that to the organization. We maintain the engines, but then we focus on the 3 big themes which we have and take the slower pace on the longer-term, so which is the deepwater, the long -- the Integrated Gas and the resources plays. And you will hear us talking a lot about those 3 in the next 5 to 8 years, because that's where all the things you've just heard from Simon, that's where we are clearly positioning ourselves in order to deliver the growth out of those areas. Go here and then I'll come to you.

Colin Smith - VTB Capital, Research Division

Colin Smith from VTB Capital. Again, on the nonconventionals, I think you said you had success in 7 of your liquid-rich plays in North America. And I wondered if you thought within those, any of them have the kind of potential that the Eagle Ford has shown. And if the answer is the Permian, what's the next in the list? And the second question I got is just you talked about using share buybacks to offset the scrip issuance. But actually, given the restrictions we've got, we can see that, that's not quite what is happening. And I just wonder how comfortable you were continuing with the scrip program, given that you are beginning to suffer a little bit of share dilution, a little bit of EPS dilution?

Peter R. Voser

Yes. The second one is clearly for Simon. Now I will, a little bit be closed on your first question, because clearly, as we are in some of these plays, the first one, really go into the frontier, the emerging ones. As I just said, we want to add our, maybe some acreage around that. So I will be very careful. But if you actually look at the map and if you listen around where our rigs go, most probably gives you a good answer so -- but I will not give you the next base and we really don't want to develop that at the cost which is still affordable.

Simon Henry

Putting the ticks on the map is already a bit too much. The buybacks offset dilution, you're right. Last year, we bought back $1.4 billion. The scrip has averaged about $3 billion. So we've seen so far 2%, 3% dilution, I think, over a 2-year period. The scrip is not a short-term switch on, switch off program. It's a long-term offer to shareholders and presumably, some of them like it because they are exercising their option. We would agree with you that our restriction on capacity is leading to an outcome that would -- doesn't fit the intent, and we would like to do more buybacks within the actual framework that we see, to meet the objective of offsetting dilution. We're looking at all ways of doing that within both legal and economic framework that we can be comfortable with. So $1.4 billion was less than we would have liked to have done.

Peter R. Voser

And pushing Ben on higher Downstream results, he gets the question every week or second week, how we can improve on that, so we are on it, so...

Hootan Yazhari - BofA Merrill Lynch, Research Division

It's Hootan Yazhari from Bank of America Merrill Lynch. I've seen a lot of the talk in this presentation, focusing around the ramp up in the North American portfolio. You alluded to having a lot of opportunities in the Downstream in the U.S. to increase your Integrated Gas value chain proposition. I just wanted to focus on a couple of areas there. You obviously have very impressive growth coming from the U.S. unconventional activities. I just wanted to see what the sense of urgency is to increase the level of integration in North America is. How that has translated into ordering long lead items there? Because quite frankly, everyone's beginning do this. Everyone is talking about petrochemicals, LNG, et cetera. How are you securing E&C capacity before you start to become a victim of cost inflation there? And the second question I had is, you have talked a lot more openly about GTL, obviously, a very expensive proposition. How are we looking at this potentially being funded? I mean, is this going to be the cancellation of conventional projects? Is it going to be the disposal of conventional projects? And thus post-2015, can we see this portfolio shifting away from having or having much more of an Integrated Gas focus as we go towards the back end of the decade at the expense of more conventional assets?

Peter R. Voser

Thanks for the question. I think -- yes, there is urgency in what we're doing. But in all of these things, when you look at integrated ones, they go at slightly different pace because you need to do more or less scoping work upfront. The ones which are progressing the fastest is clearly LNG to transport. The Canadian pilot project is building. We're looking at 2 other ones around the Great Lakes and around some of the Gulf possibilities which we have. So that is progressing. The LNG export is something of which we are with the Elba deal and with some others. So I think they are further advanced. The other 2s, I would say the Gas-to-Chemicals one, we have selected the site, we are looking at sizing, scoping. That is most probably the third one in the row from how much it is at once. One of the key concerns there is that everybody -- because this is not a unique integration play in a certain way, because chemical crackers, others can build as well as, which is not the case in GTL if it's sizable. So one needs to be careful on -- we have seen this in the past, in the chemicals industry, like in the refining industry, everybody runs and builds and then for the next 20 years, we rationalize it because we have too much and it's too expensive. So we're very careful on that. And we have gone into a different area than some other players. So we are in Pennsylvania, closer to the market. And hopefully therefore, will also have a different value proposition. So we are looking at that. But we have not taken long lead items, et cetera. That's too early in the whole scoping exercise. On the GTL side, very unique to us, very sizable. We'll be more at the Gulf Coast, could be sizable GTL trains. It's too early to say. And we're looking into -- similar to Chemicals, to progress that, but we will not rush it. So I think you will not see FIDs on these things for the next 2, 3 years in that sense. That's by far too early. Now I've said in the presentation already that post 2015, you will see a certain shift of growth that are coming more from the Integrated Gas as well. Some of the projects are already aiming for that window, which are all like floating LNG and [indiscernible], et cetera. So you will see more growth coming in that area and I could see with the integrated plays in the U.S., if we go ahead, they will contribute further for growth in the Integrated Gas space, which we see as a very profitable long-term proposition. And that may switch then from some of the other CapEx requirements which we have into Integrated Gas. I think I'd go for one question more and then I stop. To you.

Frederick Lucas - JP Morgan Chase & Co, Research Division

Fred Lucas, JPMorgan. Does the size of your dividend impose a rationing effect on the size of your capital budget? And the second question is, Upstream Americas, what is a satisfactory return on capital for that business and how long do you think your long-term shareholders should have to wait before they see it?

Peter R. Voser

The first one goes to the CFO.

Simon Henry

Dividend is linked to the earnings and the cash flow generation and should grow in line with that. So it's not constrained by the capital investment, it's the other way around, if anything. The balance sheet may play into -- it could come into play. As in practice, it did back in 2009. If in fact, ongoing cash flow at the environment that we find ourselves in, it doesn't generate investment to cover both organic and the dividend. So it is a ability to afford sustainable increases that we look at first. If you take the free cash flows that we're projecting in the environment we are today, it's not really an issue, the dividend will be financeable. So we just have to be able to protect against the downside, as we did a year ago, when we expected much greater downside.

Frederick Lucas - JP Morgan Chase & Co, Research Division

So when you look at the cash available for the dividend, it comes after the capital spend. You don't...

Simon Henry

It comes before the capital spend.

Peter R. Voser

Before.

Frederick Lucas - JP Morgan Chase & Co, Research Division

Oh, that was my question so it's...

Peter R. Voser

Before.

Frederick Lucas - JP Morgan Chase & Co, Research Division

The dividend takes priority in terms of cash deployment choices to capital spend.

Simon Henry

Yes, that's right. And then the balance sheet would, at the margin, enable the investment. And before I pass over to Peter, there's about $70 billion of capital employed on the balance sheet in Upstream Americas in total. And I wouldn't want you think that anything in there says is a profit projection. It was return on capital with that number.

Peter R. Voser

Yes. Now I will not tell him which returns, et cetera. But the way I look at the American Upstream business is really, I look at it not as 1, I look at it as 3 businesses. Its a deepwater business. It's an oil sands heavy oil business, so that will include the assets which we have in California and in Canada, and then I look at the unconventional business. The deepwater, already profitable, adding new capacity, which comes onstream, as I said in the presentation, therefore, the capital does go up. But you know how deepwater works in terms of returns, et cetera. It is normally a fast return, moving fast into returns. In heavy oil and oil sands, we have done the investments. There are small debottleneckings to come. That is now about really operational performance and driving. The first oil sands we build, after 5 years, we had to payout. I think this difference in WTI and WSC will last for another, most probably, 2, 3 years. But we will work on that, making sure that we can actually help to make that go away. And we are kind of turning pipelines around, so there are new pipelines building. We're looking at our refineries to expand in certain areas. It could be shorter, but it is between now and the next 2, 3 years, where this will hopefully start to reverse, which will increase our profitability there. So there, it's really operational performance, and therefore, it's measured according to returns and profits. And I'm not really concerned that these will not actually deliver at the right time. And then you come to the third box, and I think, Simon explained that very well, where we are. And that's an earnings drag at the moment, but mainly driven by depreciation, as well. So there, I think, the focus will be on cash for a few years to come. And then we will switch over into a returns business over time, quite clearly. And most probably, we'll handle gas and liquids-rich shale in different way, ways there.

Okay. I get the sign. Yes, yes. I do understand that, that's okay. So thank you very much for coming. It was great to have you here. Thanks for the questions. We will mingle outside and design -- Well, actually there's some drinks outside, which is good. So we will stay around here as well. I will then have to leave in 45 minutes or so, because I go to New York, and we will have a similar session tomorrow in New York about that. So thanks for coming and hope to talk to you outside.

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