殼牌 (SHEL) 2012 Q4 法說會逐字稿

Good afternoon ladies and gentlemen, a very warm welcome to (inaudible) Saint Pauls and to this Shell fourth-quarter 2012 results and strategy update.

Ladies and gentlemen, 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 you are with the targets that we have set for Shell a year ago.

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 start.

We are one 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 four 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 to scale at the portfolio choices to manage its true cycle investment strategy for sustainable growth.

Innovation and the 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's paying off.

Startups in 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 track is here, heading in the right direction.

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 as a continuous improvement mindset.

Now, let me turn to the macro.

The rapid economic development in non-OCD countries is driving sustained and long-term demand growth for all forms of energy.

Energy demand overall could double in the first half of the century from the year 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 quarter 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 million 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 WSC.

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 get 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 savings.

On climate change we're investing in actual 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 two carbon capture storage facilities, storing four million tonnes per year of CO2 in Canada oil Sands and in Australia LNG.

On the financial side we are planning for a balance between attractive payouts 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 to the outlook for cash flow, CapEx, gearing, and production.

And there's continued growth in the dividends.

We continue to build up new options in the Company.

More choice for where to invest our dollars.

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 for evaluation grounds and went ahead with an attractive acquisition in the US to Permian.

We slowed down our 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 [strain] development in the UK.

These are real examples of dynamic decisions which we can do given the breadth of the portfolio we have in our play.

Let's look at the performance since 2010.

Our CCS earnings have increased by some 45%.

Cash flow from operations has increased by some 70% to $46 billion.

Underlying oil and gas production and LNG volumes have both increased as we deliver our growth plans.

And for shareholders, our TSR, or total shareholder return was around 40% over the last three years with soft 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 and technology division continues to drive our top quartile wells performance and to extract value from the supply chain.

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.

In all of this, Shell operated projects here had more than one billion man-hours with just 170 loss time injuries.

And I think this is a very good performance.

Now, the three 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 would will give you more details on 2012 and then I will come back and give you the wider outlook.

Over to Simon.

Thanks, Peter.

Good afternoon.

Thank you for joining us today.

Important to reflect the whole context today as we are one year into a four-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've published this morning.

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 an aggregate of positive in 2012 and growth projects were key driver of both earnings and cash flow.

Some of that from depreciation costs and higher exploration charges.

Cash flow is going faster than earnings as you would expect from the increased depreciation of the growth portfolio comes online.

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 2011.

On the 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 and that's a decrease of 14% against the same quarter last year.

And the oil and 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 deepwater businesses.

For the first quarter 2013 in the Upstream we should see the impact of growth projects, but let me just highlight we are expecting some 35,000 of oil equivalent per day of maintenance impacts and exits on a Q1 to Q1 basis.

So less than last year earned 2012.

And most of that's 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 relative downturn in Chemicals.

Chemicals low 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 a year ago of course.

And the industry refining margins were firm at the start of the quarter October, November as we had seen in the third quarter, and that 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.

We passed the crude distillation unit at the Motiva refinery expansion at Port Arthur, they are 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 US 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 fund price, $112 a barrel.

Both Upstream and Downstream segments generated surplus cash after reinvestment.

We had a clear strategic target to rebalance cash flow in 2012.

We have rebalanced to a positive free cash flow position.

There was a cash 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 repayments obligations in the first half of 2013.

The year on gearing, 9.2% not similar to the end of the third quarter and relatively low in the 0% to 30% range.

Of course you would expect that in strong oil price conditions.

The 5% increase expected dividend increase that we've announced today reflects both improving cash flow position in the Company, the underlying cash flow, and of course the confidence in future growth.

And 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 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 three years we sold $21 billion of assets.

That's about the size of a mid-cap oil and gas company.

We've refocused the Downstream, fewer markets, fewer refineries.

And the Upstream, we sold over 130,000 barrels per day including late life positions, assets that just don't fit the strategy, and we've 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've 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.

Quick word on proved reserves, SEC reserves.

Report the details in the 20-F filing as usual in March.

However, we expect to see a three-year average headline prove reserve replacement ratio to be around 84%, and that figure was 44% for the year of 2012.

On a three-year basis the average reserve replacement ratio organic excluding acquisitions, divestments, oil and gas price impacts, that was around 115% over three 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 and gas resource base in Shell.

Obviously this is only a subset of the total.

It's the bit that's being work.

The 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 three years ago.

We have a further 20 billion barrels of oil equivalent or so of resources either under construction or in options, 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 some of the projects here.

The return on capital on the right-hand chart here, return on capital in service was 20% in 2012.

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% of 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 has given the investment program not the 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 had to go only to the third quarter 2012 as 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've seen other companies in the sector are 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 five to seven 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?

Thanks, Simon.

Let me update you on the strategic priorities and you'll 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 said the new priorities for the Company to grow our cash flow by 30% to 50% for 2012 to '15, compared actually to the previous proceeding four years in (inaudible) oil price scenario.

And we also said 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.

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.

We have taken a fresh look at how we manage our portfolio.

We are 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 one-third 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, selective exploration in Upstream, and working hard on profitability and selective growth in Downstream.

The growth priority is in integrated gas where we are number 1-IOC, in deepwater and in resources plays which is both [tie] gas and liquids rich shale where we want to be a global leader in these new exciting trends.

Our organic spend in these three things will total some $18 billion spread fairly evenly in between the three.

We will also see a long-term what we call future opportunities category here.

These are reserves rich plays, typically oily, but where there is going to be a slower development pace driven by local conditions, communities, and environmental considerations.

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 50% of that is on maintaining safe and reliable operations with the remainder going into selective growth projects.

We are making good progress with the Raizen Biofuels joint venture in Brazil which has a 35,000 barrels per day ethanol production capacity.

In its first full year of operations, Raizen 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 one or two a time, and positioning for low-cost advantaged feedstock 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 five 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 seven developments over the last year, bringing the total number of projects on under construction to around 30, which should unlock seven billion barrels or BOEs of resources, and nearly one million barrels per day of peak production potential.

Now, 15 of these new fields will come onstream in the next two years.

And you can see some of the larger ones here.

Kashagan, where 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 Majnoon in 2013, and we will also have to start up of the Basra Gas joint venture.

Also new oil and gas production coming in Asia-Pacific which is Malaysia and Australia.

Putting all of this together, we expect a slight increase in production in 2013 compared to '12.

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 one 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.

Let me just take a few minutes to show you what we are up to in some of these projects and 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 all 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 all the 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.

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 on the study today, potentially another 70% uplift to capacity after 2017.

Let me show you some details here.

Now, here again you can see this more than 20 million tonnes of new options in Australia and North America.

We have got more options here than many of our competitors are constrained today.

It's a great opportunity set for shareholders as well.

Today there is a lot of discussion in the industry about the cost of price structure for new LNG in the future.

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 to cost over $10 per MMBtu.

So that's not that far away from recent LNG prices and with higher volatility.

On the development cost side, Chevron recently announced a cost overrun that's targeting the overheated Australian markets.

None of the partners like to see that and this does impact our thinking on the base of new FID's 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 energy 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 under construction there.

Now, you may have seen we recently announced a 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 LNG 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.

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 nine new fields under construction in the Gulf, Brazil, and Southeast Asia.

The key here is to standardize the development concept, to control costs and speed up the development pace.

For example we have installed five 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.

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 US and we are working on the top side.

Mars B is on track for the late 2014 early 2015 startup.

Mars B and Cardamom are just two of a number of projects underway in the Gulf.

We have been working on three further developments which is Stones, Vito, and Appo.

Appraisal rating at Vito and Appo has gone well and there is potentially more upside at Appo as we drill into the Vicksburg area 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 devolving 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 are investing in debottlenecking and carbon capture and storage to improve the efficiency and environmental footprint of this asset.

We are permitting at the 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 giant Majnoon field this year, 175,000 barrels per day is the objective.

2013 will also mark the official start of the Basra Gas Company where Shell, the South Gas Company, and Mitsubishi, will capture flare gas and condensate.

Thanks to initial agreements we signed in 2011, this partnership has already increased associated gas capacity from 240 million gas per day to around 400 million.

Now, let me make some comments in Alaska, which is also in the longer-term category.

This is not a new area for the industry.

Over 100 offshore wells have been drilled in the US 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, six 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 two rigs in the Seattle for relief well contingency and each well will have four pressure barriers available to avoid oil spills.

We halted the 2012 program early when we realized that the force of these barriers in the Arctic containment system would not be ready on 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 run aground in a heavy storm in the New Year's Eve has been damaged.

And a number of reviews into the operating performance in the last season is underway, internal and external and we will wait for that before deciding on the next steps in Alaska.

Let me turn to exploration.

We are driving our long-term growth with exploration and bolt-on deals.

We've made a change to our organization in 2012 so that conventional exploration as run as a separate activity from resources plays such as tight gas.

This is a natural 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 two businesses.

We have been reloading our exploration portfolio in the last few years with a build up of frontier exploration acreage as well as maintaining an active drilling portfolio in our mature heartland.

We have added 120,000 square kilometers of acreage in 2012.

Or another way, 400,000 since 2008.

On the resources side we have added some 5 billion BOE in the last three 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 seven notable discoveries and appraisals successes in 2012 and had a further 20 near field discoveries.

For example, the [Chuckao Chimu] rail in Malaysia discovered over two CTCF of potential, which in turn unlocks other nearby satellites that should flow into Malaysia LNG.

And in Australia we added more molecules for Gorgon Train 4, and the buildup in the outer ex-mouth which could become floating LNG.

The oil side to Zabazaba well in Nigeria is part of the appraisal for the sizable oil find and we drilled successful appraisal wells in the Gulf after 500 million plus barrel up pull field.

Let me turn to tight and shale activities.

Fracking 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.

We 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 service company in 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 aspect of fracking.

You might have seen the global principles that we have published for fracking operations, covering things like water and community relations.

So quite simply, Shell aims to set the industry standards in these areas and the standards need to rise.

Let me give you a little bit more about North America.

We averaged some 260,000 barrels of oil equivalent per day in 2012 from North America resources play.

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 developments and more liquids exploration and appraisal.

On the liquids side, the Eagle Ford is in development mode.

We have drilled 148 wells and built processing capacity for 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 liquid rich shales 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 seven 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 from multiple wells.

Overall, we were producing around 50,000 BOE per day from LRS, liquids rich shales, 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 production from countries like Iraq, Nigeria, Kazakhstan.

We're looking for financial growth here and I see production growth as the long-term proxy for financial performance.

Our 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 of cash flow from new projects in 2013 to 2015 combined.

And some $15 billion in 2015 itself.

This growth matches an important driver of Shell's cash flow target.

Some 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, item summarize, and then we go for --

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 that strategy and update you on where we are with the targets that we set a year ago.

Cash flow from operations over the past four 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% four-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 assume of course an improving Downstream in North American gas price environment over that time period, with more conservative assumptions in the near term.

As our part of the framework a year ago and as stated a year ago, we targeted $125 billion to $130 billion net capital spending over the same four-year period again in the $80 to $100 scenario as higher oil price drives higher CapEx cost at the unit basis.

This ambitious outlook is underpinned by the ramp-up of the projects that we brought onstream in the last few years and the new project startups we 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 a $100 scenario, we saw macro effects, oil price, weak Downstream, smorgasbord of North American gas and liquids realizations, in aggregate represented around $2 billion uplift and project slippage for example Pearl and some value choices like asset sales and slowdown in North American gas drilling were in total around $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 four-year target.

You can also see on this chart how the outlook could be affected in today's Downstream and North American Upstream differentials continue into the medium term.

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.

We'll 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'll all play a part, although I want to be clear that we see share buyback as a tool to offset the script 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 four 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 are 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 Basra Gas Company in Southern Iraq, and the 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, they're not a primary strategic driver for the Company.

Cash flows should continue to grow more quickly than production; out to 2015 we're expecting strong growth and 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.

There's good balance, good diversity in the portfolio.

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 three 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 PDUs, the new basins, early opportunities and assessment, but in 2013 we expect the emphasis to change to drilling.

Core exploration in the spending in the conventional exploration will run ahead of resource plays.

We will be spudding some important new wells in the next two years.

Oil prospects in the Gulf, French Guiana, West Africa, gas plays in East Africa, Asia Pacific, and of course we also continue with resource plays, more drilling in Argentina, China, Ukraine, and of course we will continue in the US 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 cost.

For Brent, we've adjusted our outlook that we use 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 price in the US we are 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.

Of course costs due move broadly in line with prices so the strict hurdle rates that apply to individual projects are not really changing here.

Our net investment 2012 was $30 billion and that's pretty much in line with the guidance a year ago.

And we've taken seven new final investment decisions in 2012 and actually 24 in the last three 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 $33 billion in 2013.

And I 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'll 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 into Basra Gas Company and the purchases in the North Sea barrel and scaling.

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 true exploration and appraisal activity that's allocated by theme within these charts, 2012 we gave you guidance of $5 billion excluding Alaska, in the end we reached just over $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 four unconventional, three 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 the 30 projects that Peter talked about, has an oil price breakeven on a net present value basis of around $60 per barrel.

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 of spend in different macro scenarios.

For every $1 of that CapEx invested we'd expect to create $1.30 at least of net present value, technically present value, actually 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 project actually performed 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.

Over time, as the projects come onstream, we expect that these attractive full cycle returns will translate into 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've not made any secrets of this.

There should be no surprises.

We're saying exactly the same thing about investments today that we said one 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 at a 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.

Thanks, Simon.

We have covered a lot of ground so let me be short in the sum up.

Energy demands 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 as Shell is on track for the growth targets we set in early 2012.

Access to oil and gas resources is a key challenge for our industry and I think we are doing well at Shell.

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 or 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 commitment to pay competitive returns to shareholders.

Shareholders, you are 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&A, which Simon and I will take together.

Alexander Michaels from [Xambia Beeber].

Just one question, that financial framework that you mentioned, how do you see the cost evolving for the Company as a whole?

It's a good question.

I'd say our operating expense over the past three, four years was barely moved, just over $40 billion relatively flat.

As projects come on-stream it does go up, and we have actually been spending more on joint feasibility, choice expenditure but we've been driving cost down through efficiencies, particularly in 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 costs 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 around capital costs where a lot of the next 12, 18 months is locked in but the further out you go the more exposed even we are to inflation in the industry and then it comes back to portfolio choices, avoiding the hot-spots.

Two questions.

The first is on the US.

I know actually that in your new gas scenario actually fourth quarter was inside your $3 to $5 per million BTU, and yet you still made a loss in North America, Upstream.

It looks like it's because of the huge amount of capital that's gone in there.

I guess this links back to the point that you made that one-third of your capital is unproductive at any one time, I think that's the indication you're making.

How do you come up with that judgment about how much capital you're prepared to carry and dilute your returns over time, and how fast do you want to get that back off the balance sheet?

The second question is more specific, you clearly have line of visibility across the entire LNG world.

In a $5 US gas world, what does LNG export scheme out of the US look like, competitively versus one that you might do Greenfield, somewhere else ex-Australia?

Thanks.

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 earlier a little bit more to light.

We are looking at North America as our growth engines for the decade to come.

We have the deep-water lake which we've been through, it has the gas lake which we are looking into how much we actually drive into the integrated value chain, and we have slowed down the drilling, so we know the molecules are in the ground.

We have bolt most of them actually at a now immature stage, so we didn't pay too much for it and 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 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 tight oil or liquids rich shale and that's going well.

Again we have chosen a strategy there to go into the early phases of the emerging basin which therefore gives you a different revenue cost, amortization, and investment profile, again Simon will give you some numbers there.

But we did that deliberately because we didn't want to pay up from up-front 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 driven et cetera.

So I think that's the overall strategy, so maintaining all those projects thus carry also some costs and you see that in our UAE results, but we are happy to take that forward for a 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.

Thanks, Peter.

It's a good question.

I'll probably take -- 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 and conventional resource plays.

When we buy piece of acreage, some of that amount is allocated to the producing assets and some is allocated to what is known as the non-producing leases.

Over time as we develop the non-producing leases they move into producing and are depreciated on the unit of production basis.

In the meantime we amortized 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 are talking about relating to the $28 billion on the balance sheet.

Of the $28 billion it splits 50-50 between producing and non-producing leases at the moment, so $14 billion 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 [which of] that 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 about 75% for drilling spend and it's actually 33 rigs in total that we are running.

38 rigs at the moment of which 30, 31 are actually running on LRS.

So it's basically 75% of the rigs running on that.

It was the other way around a year ago.

Of course we ended the year liquids rich shale with over 50,000 barrels a day of production.

We started in 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 is mostly where it was will move into development as we take development decisions.

It's not going to make a difference through Q1, Q2 maybe not Q3, but over time we will see liquids production coming back in according to the investment proposal plans that you've seen outlined there.

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 time spent.

But it is earnings negative to date.

Upstream Americas overall delivered over $6 billion of cash, albeit only $1 billion of earnings in 2012.

And you can imagine even from -- even though the figures -- it gets a lot of attention from the two 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.

Hopefully that's helpful.

There was a question about $5 wells and exports?

Yes.

On the LNG development on a worldwide basis, I think we all know that transportation and liquids fact costs if you add to that then you are in the $10, $12 range in Asia for example in 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 LNG 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 America 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 different to most other players which have much more one-to-one relationship when they actually take some LNG in let's say North America and then they go to one cost where we have much more flexibility of that.

And therefore what we just announced a few days ago that's just LNG, which comes into the pool which gives us much more divergent flexibilities and delivering into either Europe, where you need to add $5, $6 for the price for transport and liquefaction and you have more European prices.

I think what the US at the moment shows is 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 costs, but I would warn now if too many LNG projects and too many crackers are coming into the construction phase in the US, you will see costs going up very fast.

We have seen this in the past, with certain areas in the US didn't go up.

So for us it's important and that's where the most recently announced Elba deal 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 actually where it is more needed in the market, so we're looking at that very carefully.

Thank you.

It is Theepan from Nomura.

Three questions.

Quickly could you just talk about how the accounting treatment on Alaska and your spend there, is all of that spend capitalized or not?

Secondly, you mentioned $2 billion as a cost for project slippage from 2012.

How confident are you can recover 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 wondering whether actually you should be accelerating disposals at this point in time in the cycle.

Thank you.

Thank you.

Alaska numbers I think Simon can give them.

On your second question, there were two or three 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 full capacity rates.

Just let's be clear, Pearl will not run at 100%.

That's a very complex refineries system which we have, so most of it's even a little bit more complex than a complex refinery, so the availability will be slightly below top quartile of the 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 you would have been further ahead.

For the disposal side it's an interesting question.

Because portfolio management is key for us and we do disposals and we do oil from time to time, also acquisitions.

When you look at the chart you see the $7 billion, the $7 billion for quite a few years where we develop that.

And Simon has shown you the total amount of I think $21 billion versus $17 billion over the last three 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 can not 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 we have a production target or the cash flow target, if we can get more money by selling it we will sell it and actually tell you as investors that we are actually making more money for the shareholders.

So I think it's a reasonable figure to have a 1% of your capital employed as part of a target externally but we actually look at the 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.

It's steered by the two of us in order to make sure that we have got enough discipline in the organic but also in the divestment and acquisition.

Thanks, Peter.

Alaska just again, you might want to get your pens out, so around $5 billion spent since 2006 of which $2.9 billion remains on the balance sheet.

On 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 $40 million charge for salvage in Q4 which is in this result, one of the reasons UAE 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 assets of two 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.

Okay.

That's it.

Peter Hutton, RBC.

The net CapEx guidance that you give obviously includes a mix of the divestment's, organic CapEx, and inorganic CapEx.

Given that there is inflation and you say that beyond the 12, 18 months we see inflation to which you are exposed and we appear to be 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, given that they both come within that net CapEx category?

And that leads onto the next stage which is a number of people that we speak to say, on these new CapEx numbers, Shell appears to be much closer to free cash flow break-even and therefore similar to a lot of your peers, but the reaction is well yes, except you've got 9% gearing, very, very low end of your range.

Given that low gearing, should analysts, investors expect you to maintain a sort of conservative gearing and therefore free cash flow break-even?

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?

Okay.

Let me just repeat the CapEx -- we will share some of that because obviously the order of the balance sheet and the gearing, so I'll let him talk a little bit as well.

So we have $34 billion organic growth versus $32 billion we have in 2012.

That is not inflation driven.

This is activity driven.

We have through our P&T organization we have actually maintained a very rich control of the costs and what we have seen by taking early FID's, but also early kind of long-term contract with our with rates, 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 our cost or at least controlling our costs if they don't go well.

And then getting then we have the two, and in that $34 billion by the way there's $1 billion non-cash leases, yes?

So it's actually $32 billion, $33 billion in that sense.

So that is [reason we have more] activities.

Now, I've said this many times, we think that, that is actually what we have in our targets.

We have significant cash surplus to come.

If I look at all your models from time to time I cannot recognize the cash flow numbers but I leave that challenge to you.

So I'm not looking together with my CFO what the cash surplus, which is actually break-even 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 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're actually, 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 may have heard this normally $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 just move it over to Simon and he can tell you how we are actually managing that a little bit and -- if there's anything looking way forward.

Fundamentally the starting point we don't plan the balance sheet on $110 oil.

If that happens, if that 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 investments and who knows what opportunities come up for the stronger financial players in that environment.

So the gearing is more outcome of where we are in the cycle and the choices that we make rather than the driver of 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 whether 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 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 do it.

We haven't said here's a $10 billion pot, now don't go spend.

It doesn't work like that.

We always consider a 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 step 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 that we felt was just too big.

And that was how we talk about that particular opportunity at the time.

So it's a good example.

And 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.

[Lois Marchiratz], Morgan Stanley.

I wanted to ask you about two topics.

First of all, over the last couple of months we've seen a number of midterm forecast on oil markets that call for quite sharp builds of spare capacity and quite rapidly falling call on OPEC, at the IEA, the EIA, the OPEC itself, the BP Energy outlook, all call for 6 million barrels plus of 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 strategic consideration investment plans?

The second thing I want to ask you about is the oil products result which actually improved quite dramatically compared to the run rate of the last two years, plus 70% in terms of earnings.

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 into next year or two.

Okay.

The first one clearly the growth in some production volumes led by the US tight oil initial let's say drilling has clearly given us more capacity.

The demand 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-year 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 over capacity.

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 US engine which I think will start to fire on all 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 high point 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 opportunity over the next few years because we are an integrated player also in the United States and that will help us.

On the oil products earnings, that's not unusual as yet so that was last year so there's still more to come, and he knows that.

I think we had good results, but we had continuous good performance on marketing and trading, but 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 refineries at the top quartile ends of actually 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 can just tell you in December it all the collapsed again.

So the Golden age of refining this time was exactly 90 days long and then it has this period -- 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 refineries actually keep working at the top quartile end, we will capture the right margin at the right time.

So it had a good year, I have to say.

They responded well to some of the operating challenges in 2012.

Chemicals very bumpy, two halves, first half good, second half macro economical drive downwards, and that clearly gave us lower results.

And then because of shutdowns in some of the refineries in the US, it gave us some little bit less advantage feedstock for moving it into the Chemical side, and that has that kind of driven some of the results in the fourth quarter down.

But that's a normal shutdown type of quarter.

So --

[Dareem Kareem] 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, just wanted to check that the cash flow estimate also reflected those divestment's or whether the cash flow estimate of $200 billion included divestment's effect.

In terms of the questions, very helpful chart in terms of the cash flow growth and the new projects coming on-stream out in 2015, so thank you for that.

Just wanted to ask what we should expect for the base and how we should would expect that to evolve obviously Downstream and probably not growing all that much, a little bit in the US but more focused perhaps on any guidance you give in the Upstream.

And then just thinking about the Shell potential you talked about 13 new countries, you've obviously had a lot of experience from the US.

We've talked about how capital has been building up quite rapidly there 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 there other opportunities outside the US different for various reasons?

The net $120 billion to $130 billion if you work it backwards, and there's that assumption on divestment's, 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 -- 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 there and I couldn't give you unequivocal assurance that the number's add up on every asset.

And as the base CFFO develop, you've got the $15 billion from the new projects, well there is some growth in Downstream, and some of it from an expected macro the 60% of the growth in the Downstream will be on Ben's list of things to do over the next two to three years, so there's quite some improvement potential still in there in terms of efficient and effective operation of assets, meeting customer requirements, et cetera.

And all of then by definition the Upstream base performance is the balancing number.

What we do have in the Upstream is increasing proportion of significant long-term assets with pretty limited decline, so we are outstripping decline pretty steadily over the past couple years in top-line production terms.

That is expected to go on and we will have increasingly resource play contributions.

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 get 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 the $100 environment.

On the 13 new countries, I'll just say one thing on the numbers, typically in the US you put a big signature bonus down or an acquisition, typically outside the US you're not paying a big signature bonus.

You're committing to invest or put a drilling or seismic program together so there isn't usually a big entry fee.

But, Peter, in general?

I think the way we start with -- given for the integrated gas, deep-water, and the resources play, $18 billion in 2013 that offer one-third each.

I think you're looking at two 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 you're 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 after well will come later with most of it China, the most advanced at this stage going in some areas into that spending [wise to train], Turkey, Columbia, or Argentina we are much earlier in the cycle, 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 the main growth going to come between now and 2017 in all of these resources plays is still going to be North America.

Irene Himona, Societe Generale.

Two questions please.

You mentioned a change in organization in 2012 in running separately the conventions 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 the people, geographies as well?

Ultimately, 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 resources and indeed, sell in, you have some exposure I think to unconventional' s or tight oil in that license.

Is that something you may expand in the future?

Thank you.

Thanks, Irene.

The changes in the organization, I think we have done two things.

One is the one I mentioned in the speech, which is really splitting the different business models.

So I wanted the explorers to go back to what they are best to do and that's conventional 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 non-conventional' s and we have one for the rest of the world.

But they are obviously using the skills which we have built on both sides.

And then you have the two conventional exploration teams where I really want them to go back and work the acreage which we have bought over the last two, three years now and worked out very hard.

Because we could quite clearly see that we were suffering on the exploration cycle conventional because everybody was focused on the unconventional side.

That's one.

Is this is a major change?

I wouldn't say that's the major change but we did another change.

But a little bit under the radar screen because we wanted to sharpen the operational focus and that's mainly between UI, so 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 Upstream increasing that.

And that is a major exercise, it's behind us now, so has all gone below the radar screen at the end of last year, the last four, five months.

As part of that we are shifting another 3,000 people from UI into P&T.

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 hadn't done that step back in '09.

Because we didn't want to overload P&T but they are now running hundreds of projects really, 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 all the barrels out of the fields.

Russia, not much new on Sakhalin-III.

Discussions are ongoing, pre-feed has been done and we are discussing that on how we can take a Train 3 forward.

Salym is in an area where there are big unconventional' s around it.

I would just say at the moment there is potential and discussions are ongoing.

Robert Kessler, Tudor, Pickering, Holt.

Somewhat of a question on your results and then also an implication for plans going forward.

On the results when I look at the US production it performed quite well in the quarter and clearly that was in part the result of a contribution from some inorganic activity that I wonder if you could quantify say the addition from the Permian in the quarter.

And then looking forward, can 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?

The Permian contribution was about around 25,000 barrels a day for two months.

Two-thirds -- 16, 17?

The well count, the actual activities 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 one-third exploration appraisal, two-thirds development activity.

The remaining 20% of the wells would be in dry gas and that will be primarily development wells in the Marcellus and Groundbirch.

Let me just add on production, I think the deep-water production actually was very good and very strong in the fourth quarter.

They've done a good job in actually improving the operational performance and reducing the deferment or the unplanned downtime quite significantly, so good performance in the deep-water as well.

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 conventional piece?

And at what pricing point does that need to get to get an economic return?

You mentioned $3 gas in the Marcellus.

And Groundbirch, how about a similar reference price perhaps on liquids?

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 50,000 which we have at the end of 2012.

I think overall we should be around 700,000 by then, approximately, but depends all on pricing and how fast we invest.

And I think we were last year on 250,000 roughly on the liquids rich on the conventional gas total, so that gives you a little bit of numbers on how we are looking at that.

You have heard what we are planning but I think that's too early to say.

A lot will depend also 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 for.

It also depends on the cost curve, so actually the learning curves which we have in many of the liquids rich shales will also drive that.

But we have said what numbers we are using for our planning purposes, which is $3 to $5 on the gas side and the $70 to $110 on the oil side.

Jason Gammel, Macquarie.

I'm sorry to continue dwelling on the unconventional production, but 450k BD of liquids rich shale production growth between 2012 and 2017, by my calculation -- 250,000?

250,000

Okay.

That would require -- 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 leased pretty early on in activity?

Second question if I could, 40 high impact exploration wells I think over the next two years, can you talk about how many of those wells will be directed at the [Northlet] trend in the Gulf of Mexico and approximately how long do you think it will take to reach an FID at Appomattox?

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 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 a sweet spot, normally if we 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 with the Permian comes along which we thought is far too good to pass, we would 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 adds as I just described a little bit to that, so it's not an acquisition strategy which drives that growth at this stage.

Take the second?

Deep-water five exploration wells planned this year in the Gulf.

I'm not enough of a geologist to tell whether it is the Northlet or otherwise, but those are the new ones, the three appraisal wells as well.

Just on the overall deep-water program we're ramping up to 16 rigs with the potential to go to 18, that in practice reflect potential exploration success.

It's not just the Gulf.

Remember we're in French Guiana, Brazil, West African trend, so we are building up and some of those rigs you may recall, the Transocean deal four rigs that will be delivered as of 2016 onwards.

So we are committing out, effectively there 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 eight plus rigs by 2016 will be either hours or committed to us for a very long period of time, and it's a significant shift in the way we think about providing at the right cost the right capability to play out the portfolio.

At the moment more than half 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, those new rigs coming on.

We've got a new Globetrotter rig coming on.

Our design -- 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 being used to farm into Benin because we have a good rig available at the right price.

That's why we formed a strategic theme point of view, very important to get that to the organization.

We maintain engines but then we focus on the three big themes which we have and take the slower pace on the longer term, which is the deep-water, the integrated gas, and the resources plays.

And you will hear us talking a lot about those three in the next five to eight years because that's where all the things you just heard from Simon, that's where we are clearly positioning ourselves in order to deliver the growth out of those areas.

Colin Smith, VTB Capital.

Again in the non-conventional' s I think you said you had success in seven your liquids rich plays in North America.

I wondered if you thought within those any of them have the kind of potential that the Eagle Ford has shown.

If the answer is that Permian was the next on the list?

The second question I've got is just you talked about using share buy-back's to offset the script issuance, but actually given the restrictions we've got we can see that, that's not quite what is happening and I just wondered how comfortable you were continuing with the script program given that you are beginning to suffer a little bit of share dilution, a little bit of EPS dilution?

Thank you.

The second one is clearly for Simon.

I will a little bit be close on your first question because clearly as we are in some of these plays the first one to really go into the frontier the emerging ones, as I just said we want to add maybe some acreage around that, so I will be very careful.

But if you actually look at a map and if you listen around where our rigs go most probably gives you good answer, so I will not give you the next basin.

We want to develop that at the cost which is still affordable.

Putting the ticks on the map is already a bit too much.

(laughter) The buy-backs of said dilution, you're right, last year we bought back $1.4 billion.

The script has averaged about $3 billion so we've seen so far, 2%, 3% dilution over a two-year period.

The script 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're exercising their option.

We would agree with you that our restriction on capacity is leading to an outcome that doesn't fit the intent.

And we would like to do more buy-backs within the actual framework that we see to meet the objectives of offsetting dilution.

We are 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.

I'm pushing Ben on higher Downstream results, we get the question every week or second week how we can improve on that, so we are on it.

So --

Hootan Yazhari, 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 US 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 US unconventional activities.

I just wanted to see what the sense of urgency is to increase the level of integration in North America, as how that has translated into ordering long lead items there because quite frankly everyone is beginning to do this.

Everyone's talking about petro-chemical's, LNG, et cetera, how are you securing ENC 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?

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 much more of an integrated gas focus as we go towards the back end of the decade at the expense of more conventional assets?

Thank you.

Thanks for the question.

I think yes, there is urgency in what we are 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 coping where it got from.

The ones which are progressing the fastest is clearly LNG to transport, Canadian pilot project is building.

We are looking at two other ones around the Great Lakes and around some of the Gulf possibilities which you 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 two, I would say the gas to chemicals one we have selected the site.

We are looking at -- we have sizing, scoping, that is most probably the third one in a row from how much it has advanced.

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 which is not the case in GTL if it's sizable.

So one needs to be careful and 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 again because we have too much and it's too expensive, so we are 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 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 are looking into similar to chemicals to progress that but we will not rush it.

I think you will not see FIDs on these things for the next two, three years in that sense, it's by far too early.

Now, I said in the presentation already that post-2015 you will see a certain shift of growth coming more from the integrated gases.

Some of the project are already aiming for that window which are all like floating LNG, and Prelude, et cetera.

So you will see more growth coming in that area.

And I could see with the integrated plays in the US 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.

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 the 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?

This one goes to the CFO.

Dividend is linked to the earnings and the cash flow generation, and should grow in line with that.

Not constrained by the capital investment, it's the other way around if anything.

The balance sheet may play into -- come into play as in practice it did back in 2009 if in fact ongoing cash flow at the environment we find ourselves in doesn't generate investment to cover both organic and the dividend.

So it is an 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.

So when you look at the cash available for the dividend, it comes after the capital spend.

You don't look at --

It comes before the capital spend.

That was my question.

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

That's right.

All right.

And then balance sheet would at the margin enable the investment.

And before I pass over to Peter, that is about $70 billion of capital employed on the balance sheet in Upstream Americas in total and I wouldn't want you to think that anything he now says is a profit projection.

(laughter) Return on capital with that number.

I will not tell him which returns, et cetera -- the way I look at the American Upstream business is really I look at it not as one, I look at it as three businesses.

It's a deep-water business, it's an oil sands heavy oil business so that includes the assets which you have in California and in Canada, and then I look at the unconventional business.

The deep-water already profitable, adding new capacity which comes on-stream as I said in the presentation.

Therefore the capital does go up, but you know how deep-water works in terms of returns, et cetera.

It's normally a fast return, moving fast into returns.

In heavy oil and oil sands, we have done the investments, the small de-bottlenecking's to come.

That is now about really operational performance and driving.

The first oil sands we built after five years we have to pay out.

I think this difference in WTI and WSC will last for another most probably two, three 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, new pipelines building, we are looking at our refineries to expand in certain areas.

It could be shorter, but it is between now and the next two, three 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 this 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.

Most probably we'll handle gas and liquids rich shale in a different way, ways there.

Okay.

I got the sign -- 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 the sign was actually there 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.