殼牌 (SHEL) 2011 Q4 法說會逐字稿

Good afternoon, ladies and gentlemen.

It gives us great pleasure to welcome you to the [Granish] Import Hotel.

(Operator Instructions)

I wanted to just take a second to remind everybody that today this conference is being broadcast.

So there are people participating that are virtual on the phone or on the web.

So when it comes to the question-and-answer session please take the time to raise your hand.

Somebody will provide you with a microphone.

And then just state your name and please speak clearly into the mike.

And thank you, everyone.

Ladies and gentlemen, a very warm welcome to you all and also those who are joining by phone and on the web.

We have announced today our full year's results and we will run you through that.

But we want really to concentrate and spend most of the time today updating you on portfolio and strategy, and discussing a new agenda for the new tranche of growth for Shell.

So we will review what we have achieved since 2009.

Then let's look at the growth agenda going forward and then the financial framework.

And of course there will be plenty of time for questions.

You know this page.

The global economy and energy markets are likely to see continued high volatility.

This is the interplay between robust structural growth in energy demand and unprecedented geopolitical events such as the Arab spring, the eurozone crisis, or the Japanese earthquake.

Shall has the scale and portfolio choices to manage a through-cycle investment strategy for sustainable growth.

Innovation and a competitive mindset are at the heart of what we do.

We have delivered the strategic drivers that underpin our 2009 to 2012 targets, cost takeout continuous improvement, and 14 successful project startups.

Our 2011 underlying earnings increased 37% to $25 billion.

And cash flow from operations excluding working capital actually reached $43 billion.

Our balance sheet now has improved and has a position of 13% gearing at ends 2011 compared to 17% at the end of 2010.

Our improving financial position gives us room to announce a measured increase in both our investment levels and cash returns to shareholders today.

We offered some $10.5 billion of dividends in 2011, which is the largest dividend in our sector.

And about 12% of all dividends paid in the 4100.

Our spending in 2012 will be $30 billion net to support the growth program for the medium term, with over 60 new products under construction and in design.

And this investment is underpinned by new cash flow targets for the next four years, up to $200 billion for the timeframe 2012 to 2015.

So this is an ambitious program and lots to do.

Now let me start with safety and reliable operations.

That is at the heart of everything we do.

Our HSSE key figures are trending in the right direction.

For example, 2011 TRCF and the numbers of spills are broadly similar to 2010.

And our fatalities numbers have declined.

However, we still had fatalities and other incidents last year.

And operational spill volumes increased.

And so we have more to do here.

'm satisfied the way our people actually responded to the incidents.

Like we had the fire in Bukom, the Ghana spill in the North Sea, and also the Bonga spill in Nigeria.

But still there is no doubt we have to make further improvements here.

We look at these incidents and take the learnings across our global portfolio with a continuous improvement mindset here.

Now let me look at the overall development.

Rapid economic element in non-OECD countries is driving sustained and long-term demand growth for all forms of energy.

Demand for oil and gas overall could drive rise by 40% by 2030.

And this growth will be equal or equivalent to 7 North Seas, which will require huge industry investments.

With many traditional basins actually in decline, the challenge is much larger.

Replacing declines on the one side as well as meeting demand growth on the other.

Regulatory and political uncertainties, combined with challenges in the debt markets, are adding to price and cost volatility in this longer-term trend.

And we are seeing local pressure points from things like excess refining capacity in the Atlantic basin and the supply bubble in the North American gas market.

As a result of all of this, we are seeing strong volatility in our underlying quarterly earnings.

Our highest quarterly underlying earnings in the last three years was $7 billion in Q3 2011.

Or more than 2.5 times our lowest quarter in Q3 2009.

These are cyclical effects in a world where volatility has increased and both volatile and macro volatile earnings are now a fact of life.

And we have to deal with that in the industry.

Now in Shell, we are dealing with this by staying focused on the longer-term trends.

Shall activities provide affordable, safe and reliable energy supplies for our customers worldwide.

We use conservative ranges and long-term assumptions for project assessments.

We plan inside a $50 to $90 range for oil and $4 to $6 for US gas.

Upstream we are investing for growth with a strong focus on exploration and continued portfolio built into resource plays like liquids-rich shales.

Downstream, we have taken out a lot of capacity in the last few years.

Now we want to optimize this reshaped portfolio to maximize profitability.

And we will have some very selective growth themes.

From climate change, we see mitigation opportunities in energy efficiency and CO2 capture and storage, as well as investing in things like biofuels which have CO2 advantages.

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

Let me have a look at the performance in 2009.

Our underlying CCS earnings have increased by some 115% since '09.

Cash flow from operations, excluding working capital movements, has increased 80% versus 2009 to $43 billion.

We have been investing for new growth and selling down non-core positions in upstream and downstream.

Underlying oil and gas production has increased as we deliver our growth plans.

And refining capacity has come down by a net 15% due to asset sales.

And for shareholders, our total shareholder return was around 70% over the last three years, a sharp increase over the period and the competitive performance by Shell.

Now as you can see on the next slide, the portfolio has developed tremendously in the last few years.

We will show you how this fits together in a moment.

We started up three really substantial projects last year.

You know them.

It's LNG in Qatar, GTL and oil sands, and we went ahead with biofuels in Brazil.

And we took FID on the floating LNG in Australia.

This is all part of a large sequence of startups and portfolio moves in recent years.

So this is my introduction.

Now for the next 45 minutes, Simon and I will take you through a recap of strategy, what we have delivered over the last few years.

And Simon will do that.

And then I will update you on the Outlook.

And Simon will also make some comments on the financial framework.

And then we will open up for questions and answers with all of you.

With that, over to Simon.

Thanks, Peter.

It is good to be here and seeing you all again today.

I'm just going to update you on delivery against the targets that we set out over the past few years.

Before Peter takes you through the portfolio.

Now we set out three priorities for everyone in Shell back in 2009 when Peter took over.

In the near-term, raising our game on short-term performance.

Delivering our growth projects, particularly targeted at the share.

And working on new growth options for the next wave of investment that will grow the cash flow further into the future.

We've reduced our underlying operating costs with the corporate reorganization 10%, you may recall, against that 2009 baseline.

And we built a continuous improvement mindset inside the Company.

So now cost savings opportunities from multiple smaller-scale initiatives into the future.

Our free cash flow before the dividend payment was $23 billion in 2011, $16 billion after the injection into working capital.

And we declared $31 billion of dividends over the last three years.

Our project delivery in the last two years has gone very well.

And combined with the higher oil prices, that has helped us to rebalance the financial framework to free cash flow last year.

And that underpins the dividend increase that we announced earlier today.

So we have worked hard to generate new options and we have launched new projects for medium-term growth.

A few words of the quarter.

The current cost of supply earnings, CCS earnings, for the quarter including identified items was $6.5 billion.

Excluding the identified items, which were primarily gains on asset sales, the CCS earnings were $4.8 billion.

Earnings per share increase of 16% as compared to the fourth quarter 2010.

On a Q4 to Q4 basis, we saw higher earnings in upstream, but weaker results in the downstream.

The earnings, of course, were impacted by higher oil prices and cyclical pressures in the industry downstream margins.

We also had warmer weather which does reduce gas demand quite significantly for us in Europe.

Our cash flow from operations in the quarter was $6.5 billion.

Just over $7 billion excluding working capital.

And the dividends in the quarter were $2.6 billion, of which around $1 billion was settled with new shares under the scrip dividend program.

We are offering that scrip program again for the full quarter 2011.

Our buybacks for the quarter were $0.3 billion.

And they are all under the program to offset the dilution caused by the scrip.

Now, quarterly results are important but they are really only a snapshot of our performance in what is very much a long-term business.

Since 2009, our upstream underlying earnings have increased by $12 billion.

The upstream cash flow, excluding working capital, has increased by $15 billion.

Of course that is underpinned by a $50 per barrel increase in the oil price.

We have had higher gas realizations as a result, and we have also seen profitable production from the new growth projects.

And the contribution from new projects like Pearl gas-to-liquids continued to grow, or will continue to grow in 2012.

So I feel good about what we have achieved, the underlying performance and the underlying potential in the upstream just for 2012.

In the downstream, 2011 underlying earnings were $2.3 billion above where they were 2009.

And the cash generation next excluding working capital was $2.9 billion higher.

2009 was a low point in the downstream cycle, and we have had the benefits of an upturn since, especially in chemicals.

Refining, however, remains a very difficult segment for the industry.

And if anything, we entered a down cycle across the board in refining again in quarter four.

Now, we have restructured the downstream portfolio quite considerably in the last few years.

We've brought in some selected growth, for example in chemicals and biofuels.

And I think that puts us in a lot more competitive position, a more robust portfolio, in downstream overall than we were a few years ago.

Our return on the capital in service, that which is generating revenue today, was 25% in 2011.

And that is an increase of 10 percentage points since 2009.

It is a satisfactory level of return.

This underlying figure reduces by 9 percentage points to 16% when we take into account the fact that 30% of the balance sheet, on average through the year, is still not yet revenue generating -- under construction or unproven leases.

And that's $60 billion of capital that will move through into revenue over time.

Both the upstream and the downstream segments generated surplus cash after investment over the three-year period, you can see on the right.

This free cash flow position, combined with our capital spending, the dividend, the buyback program, they all resulted in a decline in the balance sheet gearing to 13% at the end of 2011.

And that compares with the recent peak of 19% at the end of the third quarter 2010.

That is only 16 months ago.

So you can see the Company is well-positioned to fund both growth investment and also the payout to shareholders.

Now capital efficiency is an important part of our continuous improvement drive.

We sell down non-core positions, we reallocate the dollars into growth projects.

We sold $17 billion of assets in the last three years alone.

We're going to (inaudible) around 800,000 barrels a day of refining capacity.

On the marketing side we have completed the bulk of our program to get out of markets where we have a small presence and/or a limited growth potential.

So, delivering on our targets to refocus our downstream exposure, and from here we are working to improve the underlying operating performance and to generate much better returns from this overall reshaped portfolio.

In the upstream, we sold 120,000 barrels of oil equivalent per day of upstream positions where we see others can add a lot more value.

At the same time, we have made $15 billion of acquisitions.

And that includes new acreage.

This has mostly been recycling cash from the downstream into the upstream.

Buying into immature resource positions in growth markets where we have either technology, infrastructure synergies or other advantages that can add value for our shareholders.

These deals like the North American resource plays and, for example, Brazil biofuels.

So overall, 17 divestments, 15 acquisitions.

That is the equivalent of a midsized mid cap oil and gas company that we have sold and bought in the last three years.

So good progress on capital efficiency.

We expect asset sales and bolt-on deals to continue as part of our basic business model.

A few words on resources.

We will report our SEC reserves position in detail in the 20-F return, as usual, in the middle of March.

However, we would expect to see the headline reserves replacement ratio all-in on an SE basis to be around 100%.

And the replacement ratio on an organic ratio, just the additions during the year, of around 120% when we take account of the impacts of acquisitions, divestments, and changes in oil price and the allocation of resource in production sharing contracts.

In addition to reserves, of course, we look at resources, a broader definition.

And that is what we used to manage the business.

And we have a substantial oil and gas resource basis in Shell.

This chart shows you just the subset of the total resources position that is in active maturation today.

That is around 32 billion barrels of oil equivalent, or about 27 years of current production.

This is where we put the focus in the upstream.

We look to commercialize these barrels and we turn what was exploration or negotiation or technology success into production and cash flow.

Shell now has some at 12 billion barrels of oil equivalent of resources onstream producing today.

That is an increase of 20% in only 12 months.

It's the big projects coming on.

But it is also 3 billion up and 30% up over the three years, during which time we have produced 3.5 billion barrels.

Today we have a further 20 billion barrels of oil equivalent of resources either under construction or in development design options.

And they, as we mature them, will drive the cash flow further from the middle of this decade onwards.

Looking at our targets for 2012, we made good progress on both the key targets, production and cash generation.

We are on track for an increase in production in 2012.

The precise outcome for the year, of course, will depend on external factors like temperatures, the Nigerian security situation, and the pace of investment in our onshore tight gas activities, particularly in North America.

Over the past two to three years, our project delivery and our cost management have gone well.

We have delivered on all of the strategy milestones and the targets that we set when we first talked to you back in early 2010.

We have been busy with our set sales in attractive market conditions with a strategic imperative to improve the capital efficiency.

And we've also seen changes in the external environment.

For example, we have had headwinds on both production and cash generation from the moratorium in the Gulf of Mexico.

And obviously we are spending at the low end of our potential in tight gas in North America at the moment.

If you put together the divestments, the Gulf of Mexico, and the onshore affect, those impacts together since 2009 equate to around 200,000 barrels of oil equivalent per day of production.

Or, in fact, 100,000 barrels a day since we last spoke to you in March of last year.

So that effectively means that we are substantially ahead of the targets that we set ourselves, both on an economic basis and underlying production basis, although the headline figure may be somewhat lower, as you can see.

We have rebalanced the surplus cash, the key strategic driver behind the 2012 targets.

We had in 2011 $43 billion of cash from ops and a cash surplus after investment and after returns to shareholders.

Now there is more to come on the underlying cash flows.

Those 2011 projects ramp up.

They need to get to full capacity.

150,000 barrels a day still to come during 2012.

At the current macro conditions, and even with the net higher capital investment that we talked about, we would expect to be in cash surplus this year after the dividend payment.

However, of course the macro picture is very different today compared to the environment we envisaged in early 2010.

Oil prices higher, downstream in the US gas price are in the down cycle.

So we are moving on from these 2012 targets, setting a new outlook for the Company longer-term.

And they reflect the new realities.

So with that let me hand back to Peter.

Thanks, Simon.

There is more to come on the CFFO side and also on the production.

A list of projects now in hand to deliver this growth.

We are moving on from these 2012 targets, as Simon just said, and setting a new agenda for the medium-term growth.

So let me update you on the strategic priorities.

And you will see we are keeping the momentum on the strategic drive we have had in the Company over the last few years.

As I said, we have over 60 new projects and options today, dominated clearly by upstream.

As we deliver our new projects, I expect our cash flow to be up to 50% higher in the next four years compared to the last four years.

Or up to $200 billion for the 2012 to 2015 time period.

Capital efficiency is a key part of Shell's strategy.

And we expect some 250,000 BOE per day of asset sales and license expiries over the 2012 to 2017-18 timeframe.

We look at operating matrix such as oil and gas production on a very long-term basis.

And you can see the potential here if these impacts play out.

An increase of 25% from 2011 levels to 4 million barrels per day, absorbing the 250, which I explained beforehand.

So let me give you more details on these themes.

Simon mentioned it.

Continuous improvement is embedded in the day-to-day activities in the Company.

This is all about operating performance, controlling costs, implementing our strategy at a rapid pace.

The opportunity set here runs into the billions of dollars.

Themes like improving our reliability in downstream, reducing our drilling times in tight gas, and getting more from process efficiencies.

Just as one example, our Q4 unit operating costs at our Canadian oil sands have fallen by $5 a barrel compared to the same period in 2010.

With continuous improvement initiatives, as well as our startup of the Expansion 1.

We expect to take out another $3 to $4 per barrel in the oil sands over the next two years.

So let me give you some more details on the portfolio that is driving the next tranche of growth for Shell.

This is all about more energy in Asia-Pacific, more deepwater and tight gas in the Americas, and more investments in traditional and oil and gas plays.

I think if you look at Shell's growth profile in the last few years, the investment profile was really dominated by 3 large projects.

Which was QatarGas-4, Pearl and the oil sands expansion.

There is an important shift in our project flow here now.

These three are onstream.

With the 26 projects under construction, which will open up another wave of production growth.

I think this is one of the most competitive portfolios of projects on the construction in our industry today.

So let me update on some of these new projects.

Shell continues to be the leading IOC for integrated gas.

That is LNG and GTL.

And expects to hold onto the position to at least the middle of the decade.

We have delivered new projects in Qatar, as you know in '11.

And our energy capacity is now 20 million tons per annum.

The next tranche of LNG growth for Shell is coming from Australia.

With 8 million tons per year under construction, which is expected to lift our capacity by 40% by 2017.

Prelude FLNG, which is an industry first, is progressing well.

The Crux field, will provide part of the gas supply for Prelude.

And we are discussing with Nexus to take an 80% stake in Crux and develop an FPSO there to commercialize the liquids content.

The (inaudible) to the Abadi FLNG project in Indonesia and in Lebanon is a 30% stake.

And we have bought Bow Energy which will allow us to increase the train size in Arrow LNG.

Overall, Shell has around 50 million tons per annum of new LNG options under he study.

We have also made progress on LNG sales.

With contracts for 6 million tons per annum of LNG sales signed in '11, linked to oil markets.

And valued at $100 billion at today's prices.

These are portfolio deals.

That means the gas is not linked to any particular supply project.

Now turning to the deepwater Gulf of Mexico.

This is an important region for Shell.

We are one of the largest players in the industry here.

The moratorium announced in 2010 after the spill did bring delays industry-wide.

The moratorium ended in '11 and the new safety standards in the regions are pretty similar to the ones we have at Shell.

The slowdown in the Gulf is still having an impact on our drilling program but we are really regaining momentum here.

The development priorities beyond the projects which are under construction are to launch new hot class developments at Vito an Appo discoveries.

And you can see the timelines we are using there.

We're also getting back to work on exploration in the Gulf of Mexico with at least 5 wells planned for 2012.

Now let me turn to our heartlands.

We have some large projects underway in Shell's traditional heartlands.

These are plays like new oil in the UK Atlantic margin, a new gas investment in Asia-Pacific for Shell's LNG joint ventures there.

Much of this investment is nonoperated.

It is an important part of maintaining Shell's cash flows from these profitable and long-life basins.

So when you put all of this together, we expect to see attractive growth in upstream in the next few years.

I look for financial growth here, not simply chasing the barrels.

You can see the impact this is having on our production mix, with growth in the Americas in resource plays and deepwater.

And growth in Middle East and Asia-Pacific integrated gas.

So those are some comments on growth plans for the next few years.

And you can see we have some exciting projects underway here.

Now before I hand back to Simon, on the financial side let me also update on some of the options which are maturing towards the next generation of project options and long-term investments.

Some 80% of our capital investment is going into upstream.

But we are also investing in very selective growth in downstream, as well.

As you all know, Port Arthur refinery expansion in the Gulf Coast is coming onstream during the first half of 2012.

We're also working on new potential chemicals capacities is North America and in Qatar which will be integrated with the upstream gas for feedstock.

We're investing in selective growth in oil products, for example in China, and continued momentum in Brazil biofuels.

I think overall, we will continue to have a measured approach to downstream manufacturing, relatively small stakes in new manufacturing assets, building just one or two at a time.

And positioning for low-cost advantaged feedstocks and market growth potentials.

So let me now turn to options in upstream.

We had 5 new exploration finds in 2011, including French Guiana and more gas resources in offshore Australia.

We're also working hard to add more acreage to our exploration portfolio.

We look for acreage in established place, in frontier positions, where the subsurface is less well understood but the rewards are potentially very high.

But the nature of exploration is changing.

With onshore resources plays in tight gas and liquids-rich shales, which are driven by land acquisitions and drill-outs, alongside more traditional offshore activities.

We made a series of resource-based deals in 2011, including liquids-rich shales in several countries.

In total, we spent some $6 billion last year on exploration activities and bolt-on deals during 2011, adding over 4 billion BOE of potential resources.

Combining exploration and deals over the last four years, we have added around 13 billion barrels of resources for some $30 billion, or at a cost of some $2 to $3 per BOE.

Now here we have got two examples of exploration of progress in '11.

French Guiana, this discovery tested entirely new oil play.

This oil discovery is a stratigraphic trap.

It means that defining the edges of the reservoirs is complicated and this will need some careful appraisal.

We think that in French Guiana, the well confirms now over 300 million BOEs.

We are planning 2 wells in this block in 2012 which have the potential to increase these estimates as we explore this new exciting play.

As mentioned in Australia, we have continued to find new gas there with 3 successful wells in 2011 which could be part of future expansions of the Gorgon LNG project.

Shell has a long track record in adding new oil and gas resources through exploration.

Exploration has added around 15 billion BOEs in the last 10 years.

Now, exploration is still the lowest-cost entry into new oil and gas.

And Shell has a global exploration program on the way.

We focus on large prospects in proven hydrocarbon plays, high-value near field wells, resource plays like liquids-rich shales and tight gas.

And we make selective moves into frontier acreage positions with a set higher risk/reward trade-offs.

We stepped up our exploration spending in '05, with positive results.

And we are increasing our commitment to exploration again in 2011 to 2012.

So we expect to see a 35% increase in core exploration spending in 2012 to 5 billion as we drill up our new acreage and continue to build new options.

Now this increase includes a step-up in drilling in liquids-rich shales and continued investment in tight gas and CBM.

Now setting aside these resource plays, we expect to drill 20 to 25 key wells in 2012 compared to 18 in 2011.

The drilling plan covers both wild cat activities on the one side and then high-value near-field prospects.

So that is where we are on exploration.

Now let me turn to some of the development potential that we have over the next few years.

We have some 36 projects on the drawing board for medium-term growth.

So let me show you some of these.

We have been working hard to build up Shell's portfolio in tight gas.

And we have moved rapidly into liquids-rich shales.

These are exciting themes for our industry, unlocking large resource positions using advanced drilling technologies.

In liquids-rich shales, which is a relatively new play for us, we're looking into our existing licenses across the world where we can produce oil from what the industry used to see as source rock.

What is increasingly clear is that controlling our supply chain is going to be critical and tight gas and CBM.

The wells joint venture we have formed with CMPC in China is making good progress.

We expect to build nine new rigs together in 2012, and ultimately to deploy about 40 rigs and support services like fracking on a worldwide basis.

For example, in North America and CBM plays in Australia.

This is very much a storey of drilling up and commercializing the portfolio.

Building a longstanding and profitable gas supply business with interesting integration opportunities and building up liquids production.

I expect to see total spending in these plays to be some $6 billion on a worldwide basis in 2012.

Development spending in North America tight gas will be around $3 billion in 2012, which is similar to 2011.

And at the low end of our spending range of $3 billion to $5 billion per year, reflecting obviously the big pricing environment.

We are moving to develop our Eagleford liquids-rich position following successful appraisal there in 2011.

Part of just over $1 billion of development spending on the liquids-rich shales in 2012.

We will also spend some $2 billion on exploration and appraisal and these themes this year, with a focus on maturing our new liquids-rich, portfolio which you have seen an earlier slide.

We have quite some flexibility in how much we spend in developing tight gas and shales.

And spending could be in the range of $5 billion to $6 billion per year on a worldwide basis over the next few years, including exploration of which $3.5 billion to $5 billion would be in North American gas plays.

The precise annual spending levels will depend on near-term pricing and always on our capital allocation choices overall.

Now, some of you may know this.

We have been looking at ways to leverage Shell's strong resource position in North America tight gas into value-added products.

So Shell is assessing at the moment options for LNG exports for GTL, for gas to liquids, and for LNG to transport.

These are value chain projects which will very much play to Shell's strengths as an integrated player.

Let me just stress, these are early days.

We're looking into various value chain opportunities and it is just too soon to say which one, all of them, or none of them will go ahead.

The precise timings and how we balance the opportunity between spot gas exposure and integration will come.

Now the one that we have launched is actually a small scale 0.3 million tons per year LNG to transport project in Canada, which is called the Green Corridor.

We are installing a gas liquefaction plant at our Jumping Pound gas plant and LNG fuel dispensing equipment at the Shell Flying J joint venture truck plazas throughout Western Canada.

We're at the same time maturing similar projects worldwide.

For example, we are looking into LNG for shipping fuel out of Rotterdam and LNG for trucks in China.

Finally, on options let me update you on Iraq.

In Iraq, we are continuing with the development of the giant Majnoon field.

Now, let me be very clear.

Majnoon is a greenfield project.

Basically we started from scratch.

And rather different from the brownfields awarded to some companies in the first round.

We are making good progress.

Although I have to say on the logistics side we had some challenges for the industry in southern Iraq.

We are taking the time to get this right and build it up.

And we are expecting to reach commercial production of 175,000 BOEs per day around somewhere during the 2013.

We signed the final agreements for our gas commercialization joint venture in southern Iraq at the end of last year.

This is a midstream gas deal.

For no production entitlement.

And we plan to supply subsidized domestic gas to local power companies and sell LPG and NGLs at international prices.

The early stages of the JV are all about upgrading and expanding the existing facilities.

In the longer-term we're starting a 4million tons per annum LNG project, likely to be a floating LNG, to avoid congestion on what is a short coastline.

As we mature this portfolio, we should be taking some 15 new FIDs in the next two years.

All part of a strong pipeline of new projects to drive our financial performance into the medium term.

We are maturing these and other options and we will launch new projects according to portfolio fit, profitability of these projects and affordability.

Which, of course, is partly linked to the development of oil prices and downstream margins.

So this is an exciting portfolio, lots to do.

We have it under construction today and we have great choices for the medium term.

So with that, I hand over to Simon for more details on the financial framework.

We have given you the outlook for strategy and portfolio.

So spend a few minutes on the financial outlook that underpins that strategy.

Firstly on CapEx.

Our net investment in 2011 was $24 billion, and that is similar to where we were in 2010.

We have taken a 12 final investment decisions in 2011, and that's 17 over the past two years.

So, spending on these new projects is now building up.

And you can see the trend in the Q4 2011 figures.

This will drive our net CapEx to $30 billion in 2012.

We've also taken on new portfolio options in 2011 and they will have an impact on CapEx too in plays like exploration, the Iraqi gas, liquids-rich shales.

And this will increase our feasibility expenditure costs, for example, in the new LNG and chemicals options.

And you can see the main investment on this chart, and we are putting the priority on a series of large themes, investment themes.

Where we get economies of scale through technology or contracting and procurement.

Overall in the portfolio, we get the right diversity of political and technological risk.

And overall we get the right size of portfolio, the material projects that we need to impact our own bottom-line growth.

Now the returns on these projects are attractive for Shell and they are attractive for shareholders.

About 80% of the investment is upstream.

And of that, 60% is in Australia and North America.

The portfolio of projects that we have underway has an oil price break even on a net present value basis of less than $60 per barrel.

And over time as these projects come onstream, we are expecting that these attractive full cycle returns would translate into a much more competitive return on capital employed for Shell.

Now our cash flow from operations was $136 billion over the past four years, 2008 to 2011.

During which the average oil price was $87.

We are expecting cash flow from operations, measured on the same basis, but $80 to $100 range, to be some 30% to 50% higher than the last four years.

That is in aggregate around $175 billion to $200 billion of the two price extremes.

Today's downstream in US gas markets are clearly in a downturn.

So in these figures we have assumed the return to mid cycle downstream conditions and a $5 Henry Hub in the outer years to give these projections.

But we have got more conservative assumptions in the short-term.

Now this outlook, the four-year outlook is underpinned by the ram-up of the projects that we've already brought onstream in the last few years.

And the new project startups that we have already looked at.

Now, we look at the free cash flow very carefully.

And there is no simple formula for what we choose to do with it.

I expect incremental CapEx, debt management and payout to the shareholders will all play a part.

While I want to be clear that we see share buybacks primarily as a tool to offset the scrip dilution rather than as a primary route to return cash to shareholders.

Also, I would like to be clear that we look at oil and gas production levels as an outcome of the investment decisions that we make on a long wavelength basis over multiple years.

They are not a primary strategic driver for the Company.

Capital efficiency is an important part of the strategy and we are expecting over the coming years around 0.25 million barrels per day of license expiries and asset sales.

If those impacts all play out, then we would still expect to have production to average 4 million barrels of oil equivalent per day 2017 and '18.

That is 25% higher than the 2011 levels.

Now, this chart may be a little complex.

But on the left-hand side we are showing patterns of investment and the growth potential in the upstream business.

The dark bar is last year's cash generation.

The two blue bars, the historic CapEx and future CapEx.

We have been focusing our spending in Qatar and North America in the past few years.

And we are expecting substantial production and cash flow growth from these regions as a result.

Ramp-up of Pearl, Canada, oil sands driving this.

Going forward, we expect to see sustained high spending levels in the Americas.

The (inaudible) now includes the buildup of the deepwater in the Gulf of Mexico, liquids-rich shales.

And that is offsetting a slowdown in investment in the oil sands.

In Asia-Pacific, we will be building up an Australian LNG and continuing to invest in the traditional heartlands such as Malaysia and Brunei.

So the cash flow there should continue to grow more quickly than production.

So over time, over the next several years, I expect our Americas and Asia Pacific upstream cash flows to show significantly the strongest growth.

And that would reflect the highest spending level in both regions.

So let me sum up just to look at the overall financial framework.

Our business strategy requires significant levels of capital investment through cycle.

And it is designed to grow earnings and grow cash flow through the business cycle.

For 2012, we are expecting around $32 billion of organic spending, around $2 billion to $3 billion in asset sales.

We continue to screen the whole portfolio carefully to optimize capital efficiency.

The spending levels that we see this year and into the future, they will be driven by the choices we make and the macro environment.

And oil and gas prices themselves are an important driver of industry costs, as we see.

Of course we can afford more flexibility on our spending levels in the up cycles.

We must keep a conservative balance sheet to underpin through-cycle spending.

And the dividend, as per the policy, is linked to the underlying financial performance.

With that, let me hand you back to Peter.

Yes, thank you.

Let me just sum up a few lines.

And then we can open up for Q&A and Simon will join me here.

So we have delivered the strategic drivers that underpin our 2009 to '12 targets.

The global economy and the energy markets are likely to see continued high volatility.

Shell has the scale and the portfolio choices to manage through these short-term ups and downs.

And the strategy is all about through-cycle investments for sustainable growth.

Our financial position gives us room to announce a measured increase in both our investment levels and cash return to shareholders.

Spending of some $30 billion net in 2012 supports the growth program for the medium term, with over 60 projects and options maturing 20 billion BOEs of new resources.

And all of this is underpinned by new cash flow targets for the next four years.

The sum could be up to $200 billion, as Simon said, for the full year depending on the oil price.

Or 30% to 50%.

I think an ambitious program ahead of us, lots to do.

We want to invest like our shareholders do.

That means for profitable growth.

So we are on this journey now.

And with that, let's go for questions.

Thank you very much.

Teplan from Nomura International Three questions actually.

Firstly, just on the quarterly numbers.

Clearly a difficult quarter in oil products.

But it seems that marketing and trading in particular week.

I was just wondering if there were any one-offs where you expect some sort of improvement into 2012 in terms of marketing and trading.

Secondly, just, Simon, you mentioned major startups, and you've got about 150,000 barrels per day to go in terms from 2011.

Can you give us any indication of what the cash flow from Qatar and the expansion of Athabasca has contributed so far?

And then thirdly, this might be the last question on the financial framework.

I think you've outlined the financial framework.

And in particular it is about the dividend.

You talked about the dividend linked to business results.

You have also indicated cash flow from operations increasing up to 80%.

But you are at the low end of gearing.

You talk about dividend growth in 2012.

I was wondering two questions.

How should one look at the dividend in terms of growth going forward in the context of what you talked about in terms of cash generation?

I appreciate that capital investment is increasing, but surely there is scope to increase the dividend by more.

Okay thanks.

I think I take the first time, you can take the second, and you start with three, and then I may come in on three.

On the O3 results and the Outlook, I think we had the refining side, and we all know the negative impacts of the refining margins across the world.

I think on top of it, clearly at Shell we had three impacts which were a little bit unique.

One was we had $150 million charge coming from the Bukom fire which was in the quarter.

We had roughly Q4, Q4 $100 million FX effects which were in addition to that.

And therefore I think the refinery results are actually, my opinion, pretty much in line with what we have seen in the market.

So the third one, we have no mid continent refineries and therefore the who WTI versus the Brent benefit, which a lot of our peers actually had, we just didn't have.

So I think if you add the three back, I think you look at the refinery portfolio in a very similar way to the industry players.

Now, we had a perfect storm.

After the driving season, the demand just collapsed.

Both in the US but also in Europe.

Weak refining margin, over capacity, demand coming down, trading going clearly from cotango in [back vidation].

So you had the whole chain actually being affected in a very short period.

What is normally our marketing, trading business, thus smooths out the big effects on the refining side, this quarter was just a perfect storm, everything was coming in.

So looking forward, my assumption is clearly we saw some recovery of refinery margins and you have all these numbers already the first few weeks.

So we will see where that goes.

I am pessimistic on refining.

It is overcapacity, new capacity coming onstream.

On the marketing trading side, I am more optimistic the way I see the rest of the year.

But I think we will see how this goes.

But Q4 was a real perfect storm type of example where the integrated chain really was under pressure in all the areas.

You give Qatar, et cetera, for the numbers.

Thanks.

The three big projects.

What we have said on the production potential is total, and this includes the first phase of Athabasca, as well, is 450,000 barrels a day.

In the fourth quarter we were at 300,000 barrels a day.

So there's 150,000 more to come from that activity.

That is about 180,000 in Qatar, 115,000 in Athabasca.

We had some downtime on the first part of Athabasca.

Expansion was running okay.

GTL was about 110,000 barrels a day.

So steady ramp-up.

Still you can see, quite a lot to come.

What we have said on the cash flow side, contribution at $70 a barrel, those three projects would deliver $5 billion of cash in a given year.

Of course the oil price was higher.

But we actually delivered about just under $2.5 billion from those three projects last year.

About $800 million in the fourth quarter.

I'm being kind with you in terms of going out, at the moment.

We are not going to give this information out every quarter as we go forward.

But it is important in terms of the ramp-up and you can see the potential we still have to come.

So on dividend?

Dividend, just how do we think about it?

I think you have to say a dividend is not just for Christmas.

It is something that reflects our long-term strategic priorities and ability to pay the dividend.

I've been here now nearly three years and this is the first time I've been able to announce a dividend.

So I'm very pleased today.

Same for Peter, Chief Executive.

In 2009, you as investors were asking, and quite rightly asking, could we afford the capital investment program we had, and could we afford the dividend we had.

$10.5 billion.

We took decisions to maintain both of those through the last three years.

Remember credit crunch?

How many of competitors, let alone industry at large have cut their dividend or their investment program in that three-year period?

We stuck with both.

Investors are now benefiting both in terms of dividend growth and in terms of the underlying financial performance that we have delivered, and the growth potential ahead of us because we maintained the investment program.

We are still the largest dividend payer in Europe last year.

We may end up second this year but we will still be right at the top, $10.5 billion-plus.

And that is a very significant contribution and commitment from the business.

And we should not forget either that actually reinvesting the cash in the business is the best way to create value.

As long as those are the right projects with competitive returns, we will create more value over a longer period of time by those choices Peter?

Just summarizing the policy at the end, we're looking at the growing dividends.

But as Simon said, if you will take a clear view on the long-term options which we have, on how we can generate, let's say, value for the shareholders, we will therefore take our cash flow and earnings expectations into account.

I think I am pleased where we are now, we have moved back into growing the dividends.

Whilst at the same time offering a lot of options.

And having actually a balance sheet which is fit to face whatever the next six months will bring.

Siegfried, Jefferies.

Peter, you showed the production breakdown by theme earlier of your 4 million barrels a day.

I just wondered, of that, how much is North American dry gas?

And I wonder if you can give us a sensitivity if, for instance, North American gas prices remain at these levels, how much would you cut off that 4 million barrels a day of what you announced there?

And secondly, just coming back on the dividend, you say that dividend is not for Christmas.

But a share buyback can be.

In the sense that you could turn it off and on to reflect the environment.

So I wonder why you're not.

You said earlier that share buybacks are not your preferred methodology, apart from scrip dilution.

I wonder why that is not the case?

Because your peers in North America use that very extensively.

So it seems strange that you have taken that one off the table.

I think on the gas side, as we have said, we have a certain framework between,, let's say, $3 billion to $5 billion on what we could spend going forward.

At the moment we spend at the lower end.

We expect a certain price recovery later in the period, as we said, to Henry Hub 5, in the order of magnitude 15.

These all will drive our investment levels and therefore will drive our production outlook for 2017 and 2018.

I would say today, if the price recovers in the way I have just described, I think you will not see an impact on the 4 million barrels.

I would also say, if you lower actually the tight gas and shale gas investments, we will most probably switch some of that money either into liquids-rich shale where we get more oil exposure, let's say, 60% oil exposure, 40% gas.

And therefore we would add barrels through that.

Or if you have more money being freed up which we don't want to spend in the US, with the options which we have in the funnel, and we have delivered more options than we think we can actually do ourselves, some of them we will have to monetize.

We could actually then develop that.

So I think in the way I look from a macro picture, I think we will manage to those 4 million barrels in whatever shape or form.

The only thing I'm not going to do is exactly ex gas because I don't know how much gas will be.

But we will go for the 4 million barrels.

Thanks.

A couple of words on buybacks.

Just to reiterate.

It is our policy to use buybacks to offset the scrip dividend.

And that means that the current rate the scrip take up around $3 billion per year.

We are not like our American friends in that there are some restrictions on how quickly we can do this.

We can only buy back B shares as a result of the withholding tax restrictions around the A shares.

And we can only buy back 25% of the liquidity on any given day.

We have been running flat out and still only made $1 billion-plus in the second half of last year.

And we are not going to do it when the market is not attractive either.

So there isn't actually a limit on our buybacks this year, other than how quickly we can do them.

We have the cash available, but policy-wise, at the moment we do not see buybacks as a major priority in terms of the return to shareholders.

Jason Kenney from Santander.

So your cash flow forecast, the 30% to 50% increase, depends very much on the downstream, moving back to mid cycle earnings.

And I'm wondering roughly what you would be expecting to earn at mid cycle earnings from the downstream division?

And if you would stay at today's conditions, what that percentage increase would be relative to the 30% lower level?

And then the second question would be the sustainability of the integrated gas resources which was quite special in the fourth quarter.

You have spoken about Qatar already.

But are you willing to go a bit more on integrated gas earnings for the next year or the medium term?

I leave the mid cycle to you, I do the integrated gas.

The downstream, $8 billion of cash generation, excluding working capital last year, the capital employed in the downstream remains around $70 billion, which a lot is actually in the working capital.

Clearly we need to grow that.

Both in chemicals and in the downstream and do better from the refining.

The figures we have just given, the $175 billion to $200 billion, are not particularly dependent on downstream.

Even with 4 times 8, 32, it is still quite the majority is obviously upstream.

So it's not fully dependent on downstream.

It does depend on a pickup two or three years out.

But it is not a significant contributor to the growth that we expect to see compared to the 136 that we have just seen.

What is a reasonable rate of return?

We have previously told that we have to get above cost of capital return on capital.

At the bottom of the cycle.

We are not there today.

Our actual return was around 7% on a FIFO accounting basis.

So we know we need to do better.

Some of the things we've talked about today are what we expect to help us get there.

Thanks.

Jason.

You pretty much know that I will not give you guidance in terms of numbers for the integrated gas.

But I think you can really see the strategy coming to life with clearly bringing the integrated gas projects onstream.

Not just Qatar gas, bringing all the others on stream.

Running the LNG business on a 90% long-term contract basis with roughly 80% oil price linked.

And I think these are parts of our strategy which you now will see obviously the earnings coming in.

And then don't forget GTL is coming into that line, as well.

And therefore you will see growth in that line, assuming oil price stays roughly at the same level.

You will see growth because GTL will just come more into 2012.

But very pleased about the strategic drivers there.

And it is really something which we push, as you have heard from the presentation.

You gave a range of cash flow outcomes on a $80 to $100 price range.

How does your CapEx numbers look going forward on a range of different outcomes?

And could I also ask, in terms of the cash portion, we had a 2% increase in the dividend for 2012, a 20% increase in terms of organic CapEx.

So is that actually your preference in terms of how your cash will be utilized over the next four or five years?

CapEx.

You saw what we have as the next $30 billion for 2012.

Given the 17 FIDs which we have taken, you have already seen in the second half that the CapEx was ramping up.

So we came down in the first half as the new projects came onstream and then we went up.

So the CapEx for 2012 is really what we have, what we give as a guidance.

Going forward, I would just say, as we said, we will structure our priorities also along the affordability lines.

So quite clearly, if you are in an $80 world, most probably you wouldn't expect that costs for CapEx to go up.

If you are in a $100 world, we may bring more options and we therefore could look at more CapEx going forward.

But I think this we will play over time and we will see how it develops.

I think with the cash flow outlook which we have given, we have enough buffer in there to actually deliver the growth.

And we will have now for the first time, and that is what I said, previously we had three big projects driving our spend.

Now we're looking at much more and more flexibility.

So we can react also faster.

Hence typically in the past I said when you go into these big projects, you need 18 months, 24 months kind of timeframe before you actually see lower costs coming in to your capital expenditure.

So that should happen a little bit faster.

And if you are in a lower oil price world, you need to balance that.

So I think, let's look at the '13, '14, '15 later when we are there.

I think we have an ambitious program, but we will optimize the cash flow clearly in such a way that we can deliver value, short, medium and long-term to shareholders.

Just on the dividends.

The 2.5% dividend increase reflects the discussion I said before.

We have reached the point where we can consider an increase again and we are very pleased and proud that we can do that.

Organic CapEx, think of the relative returns.

Typically for every $1 of CapEx we spend, we expect back $1.30 to $2 of net present value.

So that is how we create value.

And it is the quality that ultimately we should be judged against, how we choose to allocate that against the opportunities available to us.

So there is no mechanical calculation.

There will be no mechanical calculation.

There will be a reflection on a quarterly basis with the board, does the underlying strength of the financial position of the Company, both in terms of ongoing financial ratios, cash generation, and the balance sheet itself for affordability at any given time.

And clearly the balance sheet is much stronger than it was.

And can sustain in the current macro environment the level of investment and dividend that we talked about.

[Paul Stetting], HSBC.

You commented earlier about seeing capital efficiency.

But if we take your financial framework, it seems to me that at the high end of oil prices you are probably going to be in a net cash position towards the end of your planning period.

With cash earning probably 0.5% maximum, low-risk bonds earnings maybe 1% or 2%.

That doesn't seem to be a particularly good return to a shareholder.

The area that you do seem to have some flex on CapEx appears to be American dry gas, which at current prices is probably also a zero return business.

And it is also a very short lead time business.

You commented that the buyback is prohibitive, or find it difficult because of the restrictions of your share structure.

In the past, when your share structure has caused you problems, you've done something about it.

Is there anything you can do to your share structure to at least give you a buyback as a weapon?

Because of at moment it seems to me as though you're trapped by it.

Yes, I would like to give you all the assurance that we are talking to the respective inland revenues and governments to deal with the withholding tax.

It is not a particularly easy time to talk about taxes.

Nevertheless, we are trying.

And I'm not going to promise anything.

I would just say that we are working on it.

If it comes, you will see us go very fast into a one share structure which then will actually give us all the flexibility which we need.

So we are working on it.

It is known.

It is more a Dutch issue than it is a British issue.

And we are really working on it.

But tax and budgets at the moment are not an easy game.

But working on it.

Everything you say is true Paul.

Absolutely.

Alejandro Demichelis, BofA Merrill Lynch.

Just to follow up on the CapEx question.

Should we be thinking that the $30 billion is the minimum that will allow you to grow?

And then if you get to that $200 billion of operating cash flow we should be thinking about a much higher level of CapEx?

I think we have outlined to you how we want to run the cash flow and how to grow.

I just don't want to be dragged in on how starting to predict '13, '14 and '15.

I think it is too early.

We have given you a framework which will allow us to grow in such a way.

And I think if you look at and compare it to our competitors, if you take Chevron and Exxon, they're actually quite higher on that side.

Started much earlier.

They could really harvest for a while, clearly, our big spending.

So I think we will deal with this year and come back.

But I'm pretty convinced that with what we have outlined to you today, we can achieve these growth aspirations.

Can we do more?

Most probably yes.

Will the world change and costs will go up over the next three or four years?

If we are constantly in a $100, $110 oil price, could also happen.

But I think there now, cash inflow will also change.

So I think this is a dynamic framework which I just don't want to go into giving you a long-term projections at this stage.

On the CapEx side.

Do you want to add anything?

No not really.

Other than the oil price does determine the unit CapEx cost through the cycle.

So oil price stays at $110, then you may have to spend a bit more to get the same outcome.

Robert Kessler.

I have three questions really about the 2012 budget.

Firstly, how much have you budgeted for Alaska exploration?

Is there a chance you might under-spend that budget for 2012?

Second question is, of the $5 billion exploration budget, can you split that onshore versus offshore?

I understand, of course, liquids directed and the community exploitation and delineation of gas acreage drives the growth there in your exploration budget.

But just curious, just the offshore piece of exploration, what that looks like year-on-year.

And then the third question would be, of the $6 billion 2012 downstream budget, how much of that is associated with the completion of the Port Arthur project?

Did I understand, the last one is how much of the CapEx in downstream is allocated to the completion of Port Arthur?

Yes that is the question.

Thank you.

I take one.

Can you take two and three?

On Alaska, and I think if some of you have more questions, Marvin, as he is coming in Washington on a regular basis, I think he will have a lot to say about that.

We are pleased with the progress so far.

I think we're getting the permits, we're doing a lot of work together with the regulators and these authorities to prepare the drilling campaign.

So I'm cautiously optimistic that we will start to drill in July and August and September.

We have 10-well program for the next two years, and we are preparing ourselves for that.

We have stepped up to go into that.

Now although we have given to you today, for the long-term outlook, but also the short-term outlook, does not include Alaska.

So if we're successful there, if we drill and we develop and we get volumes, that would all be on top of it.

Now I can tell you already you will not get Alaska production before 2017 or '18.

It is going to be most probably later.

But this is not part of what you have seen here.

So also not exploration-wise what we would spend the next two years.

That is not in it at this stage.

The $5 billion of exploration.

At the moment about $2 billion will go into onshore unconventional activity.

Not all of that is North America.

At least $0.5 billion will be outside North America, in China, plus some of the plays that we showed on the charts earlier.

So I imagine Turkey, Oman, elsewhere.

And of the $6 billion in downstream, how much is Port Arthur.

The answer is none really.

It's an equity associate.

It's already financed for the construction of Port Arthur.

Which is beginning.

Some of the units are already in warm standby.

And we are seeing the units by the middle of the year.

They should be on full production.

So no further capital injections to Motiva required.

Thanks for that.

And of the $2 billion, how much would that have been for 2011 for the encore spend?

It was quite a bit higher because there was a lot of acreage acquisition.

If you just said of actual activity, it was probably about the same.

So it was 400 or so in China, the rest in North America.

But with a significant shift of what the activity is from gas to liquids-rich.

And in last year in particular, quite some significant spend acquiring the acreage that Peter has referred to.

Jason Gammel, Macquarie.

Given the prominence of tight oil in the capital spend program moving forward in the Eagleford in particular, I was hoping you could let us know what the existing production was in the play and how much acreage you have in the Eagleford.

If possible broken down between black oil, condensate-rich gas and dry gas?

And if that is too much detail, I'll just get more afterwards.

And second of all, on the (inaudible) expansion, we know what the incremental distillation capacity is.

Should be able to share what the hydro-cracking and coking capacity that is being added at Motivo are.

Okay, take the first one.

I think second one I need to check.

We'll get the number to you.

You want to take the first one?

Eagleford, overall, most of our liquids activity today is on Eagleford.

There's a little bit elsewhere, [Utacurran] and Canada.

But most of its Eagleford, about 13 rigs, 250,000 acres 250,000.

About 60% of it is condensate-rich.

That is where we are focusing the activity this year.

Is that right, Marvin?

Sorry, I can't give you the hydro cracking.

John Rigby, UBS.

Two questions, one on exploration and one again on the buyback.

On exploration, it seems to me over the whole cycle, since the issues the early part of last decade, one of the things you needed to fix was exploration.

That was one of the problems you ran into, it seems to me.

And $5 billion is a big number.

And one of the issues with exploration is you do not want to be turning it off and turning it back on again because you want the people deployed and you want the expertise and so on.

So as you look at it going forward, do you have the pipeline of opportunity to keep level loading that exploration through the next five or six years at the same rate as you are doing in 2012?

That is the first question.

And then if I look at, I think you quoted some costs of resource adds, which I think was a mix, actually, of acquisition and exploration.

But if you do a quick bit of mathematics, it would suggest that you could probably self-support yourself at $5 billion on resource adds organically.

Is that true or is that an aspiration internally to do that?

And then the second point is on the buyback.

You said you'd try and do everything you could to give yourself the opportunity to do a buyback, if that were possible.

But surely the one thing you could do is stop doing the scrip dividend which would give you the opportunity to buy back stock.

Either not buy back stock at all and therefore you would be flat, or then start to use that cash to actually reduce your shares in issue.

Has that been something you have thought about?

You take the second one, I'll try the first one.

Yes, indeed, it was to make sure between acquisitions and explorations.

We have always said where we can, and we want to some niche acquisitions were part of the game.

I would not rule that out going forward.

The pipeline and having the right people, having actually the structure, we reviewed this extensively in 2011.

In order to make sure that if we step up the spending, like we have done a few years ago in 2005, there you have the people but we also have to match the people to mature the barrels through the hydrocarbon maturation funnel.

And that is exactly what we have now tested and checked.

And I think from that point, we could go on and do this.

The other thing which I said earlier on, which is I think important to understand, not everything needs to be developed in Shell.

We have done this in the past.

We are good in finding and de-risking.

But then comes a decision if you do it or if you monetize it at that stage.

We have done that in the past, and I would not rule out that.

But I want the options which we can generate in order to grow longer-term with our organic growth-plus strategy through exploration.

And that is what we are really driving here.

So even if we find things we de-risk it.

We can farm down, we can completely monetize it.

We have done both

Also, you need to think through this also from a change in the whole industry.

A lot of stuff is driven today with global partnerships.

Where you need to have international assets to get access to resources in a certain country.

Or you do like we do with CMPC.

And having actually things on a 100% on your basis on the exploration side, you de-risk it Gives you actually quite a bit of trading chips.

Which are quite useful and things you need in order to diversify your portfolio going forward, as well.

So actually, the exploration guys, they normally get a gross target minus.

So they have to prove to the two of us every year that they can monetize.

Because that is the only way you can actually keep them pushing to spend the money in the right way.

And Marvin can sing a song about that because that is how he gets his budget approved.

So he always has to come back and show how he can monetize this stuff.

And just one other thing on exploration.

Everyone seems to think we're being vague very deliberately.

It is actually quite difficult to be specific with you now, as the nature of the business has changed.

We used to drill wells and add resources.

We now have this big resource business, onshore business.

This year we will drill 28 to 25 key wells.

Maybe another 25 or so traditional type exploration wells.

And 250 or so onshore.

So it is an order of magnitude bigger in terms of activity.

So to give you a number of wells with traditional metrics is quite difficult.

It's been a difficult conversation with Marvin about, comparing what really are apples and pears opportunities.

So we're trying to help by saying, actually sometimes you acquire a company, sometimes you acquire acreage, then you need size and they can drill it.

But all cost together the last four years, $30 billion, 13 billion barrels.

And that includes these resources and [Duggan A] acquisitions.

So that is the best overall view we can give you of what its costs to bring barrels in.

Sorry, but it is an important point.

I don't want you to think that we are dodging and weaving.

Buying back the stock.

Clearly, the answer is yes, but again the scrip dividend is part of a long-term policy towards shareholders.

Some of our shareholders like it clearly.

30% or so have been taking it up.

We don't want to switch it on, switch it off for short-term reasons.

If we start with no debt and cash piling up, then I think we would have that discussion.

But as of today we are not.

So it is not something that we are looking at at the moment.

Martijn Rats, Morgan Stanley.

Two questions.

One related to production.

You targeted 4 million barrels a day.

So we see it very encouraging.

But at the same time, the industry has a history of missing that.

And therefore, I'm sure you must have considered that when you set that target.

Therefore, I wanted to ask, is this a very significantly downward risked target and there is actually some upside potential in this still?

I was wondering if you had any thoughts about that?

The short answer is I don't want to burn my fingers, so that gives you the answer.

Okay, fair enough.

The second question relates to the comment just made that every dollar in CapEx creates $1.30 to $2.30 in value.

That's an interesting one, because at the same time, Shell, like many other large oil companies, has now traded well below net asset value for many years.

And I think if you go among most of us, the discount could easily be something like 40%.

If you apply that 40% discount to that $1.30 to $2.30 figure, you roughly get back to $1 again.

And therefore you could say $1 in CapEx in stock market value creates about $1 and therefore there is no net positive in that on value, at least from a stock market perspective.

Now, you can say, maybe the stock market might not be efficient.

That's not our problem.

At the same time, I was just wondering whether this is something you would be considering when you are setting these CapEx plan and whether you truly have the right trade-off between the dividend growth and the CapEx plan.

I can't explain it.

I can just tell you these discussions are quarterly discussions, not just among the two of us but also with the board.

So this goes around our head.

The value gap which we see I have actually brought it to my top 200 leaders back in November.

And took them through the logic of the value gap which we still see in our stock.

And it is about time now to go after these things.

And we have gone out.

We have an outline of various processes which we go through, and projects.

Not just growth but also underlying assets to prove that our assets can do more.

So this is very much also how we drive our performance inside the Company.

Not just when we think about our dividend structures and CapEx structures, et cetera.

I said $1.30 to $2.00 that we would expect to get.

But $2.30 I'd be very pleased, of course.

And the key thing is, indeed, embedding that thinking in the organization.

There are three people in the audience, actually.

Marvin, who spends most of the money.

Martin [Betelar] who actually looks after Malcolm's money.

And Ruth Cairnie who is head of strategy who actually helps me decide who gets the money in the first place.

So on all of them, the individuals, their targets, they are expected to know what they need to do to close the gap that you refer to.

We say it, there are one or two big explanations.

One of them is your ability to deliver value from the current assets.

Continuous improvement, operational excellence, and just do that better than anybody else.

The return on capital.

We know where the gaps are, we are working on them, and all of our asset managers are with us on this.

What work do they need to do.

The second thing is, the capital that we invest, we need to convince you, amongst others, that it really is going to deliver that much value.

And unfortunately 10 years ago we lived in a trust-me world.

I could stand here and you might believe me.

We now live in a show-me and verify and prove-it quarter-after-quarter world.

So we know, and we've been saying for some time, you need to judge us quarter by quarter as the current projects come on.

Show the quality of the current projects.

And believe that the new projects, the Gorgon, the Prelude, the onshore gas, the deepwater, are going to be as good as the current wave.

And then you have got to believe that we can replicate it and grow over time with the new opportunities.

That is what the strategy is built around.

That is how we play in internally.

And that we fully accept, we have to prove it.

We have to show it quarter by quarter.

Which is why, if fourth quarter is a kick into the system, we know what the impact is both on external perception and what we need to do internally.

Irene Himona, Societe Generale Coming back to the dividend, if I may.

So, two questions.

First of all, you have a new dividend policy, or you introduced a new policy back in 2010.

And today we are seeing the first increase since '09.

Prior to you coming in, the pattern used to be an increase in the Q4 dividend, leaving the subsequent three quarters flat.

Is there anything to read in the fact that you are now increasing the first quarter's dividend for next year?

Related to that is, the word you used in relation to the dividend, which is affordability.

Clearly there's no issue of affordability today.

You have a 13% gearing.

And there would be no issue of affordability in your mid cycle scenario when you're net of cash.

What is the stress case that the board is concerned about over the next 6 to 9 months that might indeed create an issue of affordability?

As our CFO during that time, I think I take the first one.

As far as I remember, but I'm happy to check, we always announced -- and maybe JJ knows that.

We always announced in Q4 for Q1.

So we have not changed at this time.

But I will check back.

But I think that is the policy, at least I have used.

Maybe earlier it was different.

But I think that is what we have used over the last few years.

Is that right?

But I will still check.

So if I have one year where I did not follow that pattern.

So don't read too much into the timing.

But it is a quarterly discussion.

We don't only discuss it at the end of January.

What is the stress case?

What are we worried about?

We've been pretty resilient against anything down to $70 or $80 for a period of time.

How long that period might be would determine how stressed we might get.

But that is not really the point.

What we are looking at is, once you increase the dividend, we don't want to keep -- are we going to pull it back again?

So we have to be that much more careful about going up in the first place.

We still think it represents a pretty attractive payout for the shareholder, and it's still 40% of our earnings last year.

So it is not an easily covered dividend in the event that the price comes off and we need.

The balance sheet is in a better place but the rating agencies are also a little bit tougher than they once were.

And that AA rating means a lot to us.

So it's all of those things we balance.

And I would not want to give an oil price case, but we look at $50 to $90 on the range.

I'm not sure we see it stay right at the bottom of that one over the next 12 months, but we could certainly see it in the middle of that range.

Oswald Clint, Sanford C.

Bernstein.

Just want to focus back again on the liquids-rich shales.

And there's lots of comments that you made about them.

You have got 15 liquids-rich shales globally.

Just wondering, are those the top of 15 that you find within a screening process?

And if they're in the exploration bucket, do you think that these, like exploration prospects, where one in four, one in five of these will be successful?

So how should we think about that?

And then, secondly, related to the 4 million barrels per day in 2017, maybe if you could talk about the decline rates in the production that is embedded with that.

And maybe put that in context of today's decline rate, what it will be in 2017, and maybe actually what it was five years ago.

Thank you.

On the second question, we always used 4% to 6% and have been in that range for a long time.

And we are not going to give you 2017 number.

But that is the range which we have used in that sense.

On screening and adding, it is clearly something which we are pursuing on a worldwide basis.

And we have given you some insights.

The screening or the prioritization has not finished.

We are working further on potential opportunities.

And I think we have given you today what the potential is in all of these plays over the longer term.

And I think I will leave it at that at this stage before we go deep per basin, per basin or prospect by prospect.

But the screening exercise and the adding exercise is still ongoing and we will be forthcoming during 2012 and '13 when we actually add more acreage.

But I can just go as far as saying that in our existing acreage across the world, and licenses and permits, we have got quite a high number of potential possibilities.

And we're looking at them.

Some countries are further advanced than some others.

I think we are very much advanced in North America.

And in Latin America.

We went into Argentina.

We are looking at Columbia.

We're looking at other areas.

US and Canada.

I think in the rest of the world, the pace has been somewhat slower.

But it is now picking up.

I just have a comment on decline rates if it helps.

This is another area that gets less easy to translate in a single headline number.

Again, because of the unconventional.

They either have no decline if you keep drilling.

Or they have enormous decline if you don't.

So take that piece of the portfolio out.

That depends on how much we spend.

The rest of the portfolio, still in the 4 to 6 range, but it's got closer to 4 than 6 than it used to be.

So it is better than it was because of the amount of long-lived assets in the portfolio.

So the shape of the portfolio is changing over time.

Today's unconventional production is less than 10%.

It could grow towards 20%, and then what I just said starts to make a much bigger impact on decline overall.

Alex Murray.

First question is on Iraq.

Could you elaborate a little bit on the economics for the Basra gas project?

And in particular, would it be possible only thanks to the LNG part of the project?

Or domestic gas part will be profitable, as well?

And second question, coming back to prior comments on buyback and share structure, would you consider simplifying the share structure by, for example, merging the two classes of shares or keeping only one of them?

Thank you.

Thank you, Alex, for the question.

And the second one, the answer is yes.

If the withholding tax is solved then we will in turn go sooner than later into one share structure.

But we need to sort out the tax issue there.

That is something which we tried to do back in 2004 when we brought the two companies together.

But we have not been able to do it so far.

On the Iraq side, I think we look at this project in two stages.

And therefore we look also at two profitabilities and both parts are profitable.

So the first one is what we are doing now which is the domestic gas.

It is the expert of LPG, et cetera.

And then the second one, there could be longer-term an LNG play.

But the longer-term is quite a few years down the road.

And from that point, we have been clearly focusing on the first part.

And that first part had to go and pass that our profitability hurdles which we have in internally in the Company.

So we're not looking at one big project whereby one part is really an option for the very longer-term.

And thank you for the question.

Iain Armstrong, Brewin Dolphin.

Do you have an implicit assumption that there's going to be a well-established export market for LNG in the US, given that you are putting so much more money into shale gas?

This strikes me that everyone is trying to do this.

You're putting money into a market which is already in surplus, with the assumption that the gas price is going to get higher.

Are you making some assumption that US GDP is going to suddenly accelerate over the next few years?

No, I do agree there is too much gas around at the moment.

And I think that is why we say we look at possibility to change the (inaudible) expose into liquids exposure.

And I gave you a few examples.

I think I would also distinguish between the US and Canada.

So if I look at Canada, I would see the export of LNG through the Western Canadian side as something which will happen.

And we are working on that with our partners CMPC, Mitsubishi and CoGas.

S I think that is an option.

I think we will also see some exports coming out of LNG of the US.

But I still believe that this is going to be limited, given the fact that there is potential to generate, actually, more out of that gas locally.

So gas to liquids, gas to chemicals.

Which will actually use the gas and produce the energy inside the Americas.

Less dependent on imports, more generating capabilities.

And I think whilst I can see that some energy plans will go ahead, I wouldn't think that these exports will be at such a magnitude that, A, they will have an impact on the global market.

Point one.

And point two, I think it will be limited in capacity, because I think the more value chain integration will actually happen in the US.

So bringing petrochemicals back into the US is certainly a theme.

Every politician, every businessman in that part of the industry is thinking about and his interest to point out.

Thanks for the question.

Neill Morton at Berenberg.

In terms of maturing your growth options.

You spoke about recycling downstream disposals into upstream acquisitions.

Given the fact that your disposal target is slow and coming down, is it fair to assume you're happy with the portfolio?

Or where do you still see gaps?

And then just secondly, related to that, can I just confirm that the 4.25 million barrels in 2018, ex disposals, is all from the existing portfolio?

It does not assume any further acquisitions?

Thank you.

Okay.

You can take the second and I take the first.

I think your question was about the downstream portfolio.

Overall the whole Company?

The overall portfolio.

I think you have a common end on the portfolio management and optimization.

You will always have assets which you will push out.

And that is why we say on the average $2 billion to $3 billion is just something we will always do.

And therefore, I distinguish between major portfolio rationalization exercises and the ongoing business.

We have just gone through a major rationalization on the refining and marketing assets in downstream.

And I think we have concluded that.

At the same time we are improving operational performance, et cetera.

So we're moving down that.

Will there be no refinery or no marketing assets being sold?

There will be.

Some of the edges we will do.

Some markets we cannot actually grow in the economy of scale in the market and most probably will go out.

The same will be true also in the upstream side.

We have monetization options like I described on the exploration side.

But you will also have assets, late mature assets, which we may not be the best operator and we just will sell them.

So you will see a turnover there.

Second question?

Second question is really on the 4 million barrels.

We did 3.2 million barrels last year.

We expect 250,000 of further divestments and license expires.

So your starting point is 295,000.

You have to look at the 60 projects, the 26 under construction and the other 30-plus that are in design.

And that is what drives the 4 million barrels.

So of the26 projects, the peak production, which won't all happen at the same time, is over 900,000 barrels.

And it is close to 2 million barrels within those under design.

We have listed the projects, you can see the potential scale.

Therefore, we need to develop and mature those projects.

We don't actually need to buy anything more.

That doesn't mean we want.

It doesn't mean we won't develop exploration either.

Because in that timeframe, it is possible to bring certainly near-field onstream.

But the target is not heavily dependent on either exploration success or additional acquisitions.

What it's really dependent on is level of CapEx in the environment we actually see, and good project execution.

Mark Gilman, The Benchmark Company

Just three specific questions, if I could.

You recently put into place an exploratory joint venture with [Tulo] with very little detail associated with it.

Could you put some color on exactly what type of prospect that is going to pursue and whether it includes any of Tulo's existing licenses?

Secondly, you recently indicated and announced, and I believe this project probably made a major contribution to your 2011 reserve adds, a sizeable Malaysian EOR project.

Given the fact that the fiscal terms there have traditionally not been terribly favorable, was there a modification in those terms associated with the agreement on that EOR project?

My third question relates to the substantial commitment that you made, at least over a number of years, to exploration off Nova Scotia.

Is there a particular new play type that you want to be focusing on that was reflected by your decision to make this commitment?

Thanks very much.

I take two and three, you can take one.

That Tulo hook up is really targeted at joint prospects where we both see potential and we look at bidding together.

It is not really based around farming either way, them to us or us to them.

Which is still possible but it is not really the nature of the venture.

It is likely to be in areas where one or other of us has some IP advantage, knowledge of the basin or otherwise.

So expect to see it more in the areas that Tulo clearly has that expertise.

Elsewhere we have many other partners around the world.

This is not uncommon in the oil and gas industry that you have partners for exploration in particular basin areas.

Mike, on the Malaysia EOR one, which could potentially be the first EOR offshore project by using chemicals as well.

We are very excited about it.

30 years extension of the license.

Together with Petronas.

And I can only say as much as the terms which we have received for these extensions are attractive for the technology and the innovation we bring into the project from our side.

But also attached to it, it is actually an R&D, joint R&D going to happen between the two parties for the longer-term to develop more.

So very attractive terms there.

On the recent Canadian exploration tender, this is a new area, it's not much explored.

But we see obviously some value in it.

It is a new leap for us to play there.

And therefore, we have gone in for acquisition or the work program of the four plays.

So this is not like in other countries where you do upfront payments like you are used to in the United States.

This is actually a promise to work program and we will go through those in the years to come.

I think, Marvin, it is really most probably 2013?

'14.

Seismic beforehand and then drilling.

So I think we go into some uncharted territories and waters.

But obviously we have got some expectations there.

Colin Smith from BTB capital.

Your chart implies, I think, that you are looking for about 1.5 million barrels per day of production out of Americas come 2017, 2018.

And that looks like it is up about 1 million from where we are today.

If you go through the major projects, I add up 300,000, 350,000 barrels per day which leaves a pretty big gap.

And there is quite a lot on the projects under construction, but it does feel like an awful lot of that is going to have to come from shale or unconventionals of one sort or another.

And I wonder if you could just comment if that's roughly right, particularly in the context of the question that Martin asked which is you didn't really have to set a 4 million barrel a day target.

With the other things you talked about.

And in the past this has been a bit of a graveyard for forecasts for many large cap companies.

And that obviously does include yourself -- not when you are CEO of course.

So I'm just curious as to why you felt it was important to put that out there?

Thank you.

I take the second one.

I think the way I want to be measured, and therefore also the way the Company wants to be measured, is actually on the two elements, which is cash flow and long-term growth.

And production is obviously a function for that.

I think also what we have experienced inside the Company with the target which we have for 2012, it does focus the minds.

And the cash flow does it as well, by the way.

And I know we are brilliant industry and doing all the right stuff.

But we have never been great at forecasting production growth and volumes.

But nevertheless, I think if you ask the shareholder to spend $30 billion net and you promise to the shareholder '13 gross rates of cash flow, part of that is also long-term outlook of production.

I think that is what I really wanted to have as a framework for discussions with the shareholders but also internally as key drivers.

Now, as I said earlier, I always like challenging targets.

On this one, I was particularly sensitive because of the past record.

So I was reviewing this inside out.

And I can tell you there were hesitations inside the Company as well, to go out with that.

Because we all know things can change five, six years down the road.

But I just don't think you can spend $30 billion net every year without actually telling the world what you get for it.

So it is a very simple thing.

And I'm happy to be measured against that.

And I will drive it.

And I think we have driven it the last three years.

Projects are onstream.

It is coming soon.

Yes, we didn't forecast that Q4 2011 was warm and the whole production came down.

That's fine.

That is one quarter.

We look a little bit long-term, frankly, and we will drive it.

So like I said before, you will not get a gas number in North America because that one will change.

But I have enough in the portfolio to get to the 4 million barrels.

Including the 250,000 which we take out through the sales and the licenses.

So I'm happy to take the challenge.

Marvin says I don't want to tie into the math too much.

But I do think Americas is where the growth potential is.

There's still another 100,000 to come in the oil sands.

We have already said that.

250,000 we talked about liquids-rich shales.

That's from zip.

And we have set up to 3 BCF gas before.

Obviously the balance of those two will need to be considered.

And we just said there's another 150,000-pllus to come in the Gulf of Mexico.

So there is some real projects driving real growth.

There is potentially more to come in the Arctic.

So he's got the assets, he just has to deliver it.

Sorry, Margin.

Lucas Herrmann, Deutsche Bank Peter, just coming back on your last point, I agree with you entirely in the context of balancing production with CapEx.

That you were indicating.

As a shareholder though, I'm asking myself if the CapEx is this and the production growth is that, then what I end up with at the end of the day is a stock with a 5% dividend yield, which is going to grow at 2%.

And we can all debate what cost of capital is.

But ballpark consensus is probably going to be 9 or 10.

I'm going to struggle to justify the valuation.

I'm going to struggle to justify owning your stock, for one.

But the key question with that, therefore, is, how did the board determine that 2% is an appropriate level when the growth you are looking at it seems near and underlying 3% to 4%, up to 4 million barrels.

That is in terms of production.

The growth in terms of cash flow, even using 2011 as a base, it seems nearer 3%, 4% of an equivalent oil price.

Why is 2% the appropriate number?

Or 2.3% an appropriate number for dividend growth at this stage?

What confidence is that giving me in the statements you are making on growth, on return, et cetera?

What confidence does it show that the board has in the statements the Company is making on cash flow growth or production growth, et cetera?

I'm a great admirer of what you have achieved over the last three years.

But I'm obviously slightly surprised at the reticence to multiply the dividend by slightly more at this point.

I can repeat all of what we already said how we look at it.

Lucas, we have, I think, delivered the last three years.

We are about to now embark on the delivery of the next few years.

As usual, we had long discussions at the board level on the right dividend levels.

We have not talked to much about the payout ratios compared to the competitors.

We are miles above most of the others.

There's only one, probably Total, which is coming close.

I still remember 2009 discussions with all of you, where in all the meetings I had the one question, is can you afford to give a dividend, are you going to cut the dividend.

So growing the dividend is key in our discussions.

And I think the board is behind that statement.

But we also want to grow the resilience of the Company.

We have delivered that now and we will deliver the next step, as well, in order to actually increase the flexibility to go forward and actually deliver our dividend policy, which is a growing dividend policy.

Attached to our cash and earnings projections.

So I think, as I said, being the biggest, having maintained it, I think we delivered actually on what we said we will deliver.

And we are going forward.

So I do think actually shareholders should take a certain, let's say, credibility out of what we are delivering.

And having a measured approach to dividends, whilst at the same time, I have to say also, a measured approach to CapEx increases.

Because you all think it has gone up quite a bit.

But I do refer you to all the competitors.

Look at the others.

They have actually gone up miles more.

One is actually also quite smaller than we are.

And the payout on dividend is actually quite small.

So I think we are trying to deliver on all the fronts and all the pieces.

I think that with that, there is a growth dividend policy there.

And that is what we are delivering.

And I have said this I think personally many times.

It is always fascinating, you have this discussion here.

If you are in the States, normally dividend is not a discussion.

Because you either do buyback or you better invest in CapEx and you go, in order to deliver growth.

So we are trying also to balance the various needs of our shareholders.

And I think we are here to deliver growth.

And I think we have a fantastic story.

Because we used to time bringing the projects onstream, but we used that time to build, actually, the pipeline to go forward.

I think the cash flow growth you're seeing, again, I would like to see anybody matching those growth rates over the next few years.

They are there and the dividend policy will follow.

But it will be a measured application of the dividend policy.

I cannot invite you for a discussion to the board but I think it will be a good one to have.

One more on the phone and then I close.

Thank you.

The question comes from [Jean-Pierre de Metien].

I have three questions.

My first question is regarding the DD&A in charge.

I noticed that that is a significant decrease from 2011.

From 15.6 in 2010, to 13.2 in 2011.

Obviously this figure in 2012.

My second question is regarding the license is expected to expire in 2017.

Can you give us a time table for those licenses expected to expire and their contribution in terms of proven results in 2011?

And my last question is regarding the mix between oil and gas in 2017 and what may be this mix compared with the joint oil and gas mix.

Thank you.

It was not too easy to hear all the questions.

But I will try.

The DD&A in a charge went down in 2011.

Largely because impairments were in 2010.

The underlying depreciation charge is just under $12 billion per year.

It is almost exactly 75% upstream, 25% downstream.

And we expect no real change substantially into 2012.

So that is the underlying DD&A.

Anything else on top is either impairments or the effect of asset divestment.

I did not quite catch the second question.

I think it was about proven reserve contribution.

But basically there were three main areas of contribution in 2011.

They were in the Grand Birch activity in Western Canada, in the oil sands expansion, and in Prelude in Australia.

Those were the three main additions.

But they added up to less than half of the additions.

The rest were spread right across the portfolio.

Overall, quite a significant contribution coming through now from the unconventional activity.

Oil and gas mix in 2017.

2011 was 52% oil, 48% gas.

We have said for some time, 2012 is the inflection you.

We will produce more gas than oil this year.

Whatever the circumstances, I think.

And we expect the share of gas to grow.

How quickly it grows will depend on the growth in the onshore gas.

By the middle of the decade, and certainly contributing to '17, '18, we will have more big LNG coming onstream.

So probably even Gorgon will make a difference.

We hope of course that we will have various other gas developments.

But offset by liquids-rich shales, deepwater, maybe the Arctic.

So while it will probably increase from low 50s, it will not go to 60 and beyond in terms of the gas oil.

And worth saying, of the gas production today, about 75% of it is actually priced against oil exposure.

So our total exposure in terms of the price exposure is very much oil linked, not gas.

I think that was everything.

Thank you Simon.

I think we close with that.

Thank you very much for coming.

As we have said, the plate is full to deliver over the next few years.

We will go after that.

And thanks for your support.

I would like to invite you, if you have time, some drinks outside and some little snacks.

Is that still in the budget, JJ?

So we will be happy to engage further outside there.

And Martin, Ruth and Marvin are there, as well.

And obviously all the IR people.

So thank you very much for coming.

Thank you.