Equinor ASA (EQNR) 2013 Q4 法說會逐字稿

Thank you, Hilde, and good morning to all of you. Really appreciate that all of you took the time to come here today. The last few years, I think Statoil has made good industrial and strategic progress, and I believe we are in a strong position to compete. We have a very sound financial position. We have discovered more oil and gas, conventional oil and gas, than any other oil and gas company in 2013. We have a strong resource base, and I think we have more optionality than ever.

On that basis, I really appreciate the opportunity to present our plan to you today, and I look even more forward to executing on the plan. The three key priorities or themes of our presentation today is high-value growth; by that, I mean grow, but at higher return to shareholders. Secondly, improve efficiency; and by that, I mean that we intensify even more our focus on cost and capital efficiency. And three, to prioritize capital distribution to shareholders.

So let me introduce you to some of the key numbers behind what we are saying. We will continue to grow our business. We expect around 3% CAGR in the period between 2013 and 2016, and we have good growth prospects towards 2020 and beyond, backed by a very strong resource position. But we will grow with less spend. Over the next three years, we will reduce our capital spend by $5 billion. That is [8%] compared to our previous plan. And with our current plan, we expect free organic cash flow to cover dividend from 2016, at $100 oil price. Also, we will deliver stable returns on capital deployed under the same conditions.

Later today, we will provide you with the details of our program to enhance our efficiency. We have, as you have seen, already implemented a number of improvement measures, and we have identified now further areas for improvement. And today we launch a comprehensive program to deal with efficiency, and we expect savings of around $1.3 billion annually from 2016 and onwards.

Finally, we will further enhance our competitive capital distribution policy. We will continue to increase our dividend payout. We will introduce quarterly dividends from 2014; and giving, therefore, our shareholders an extra payout in 2014. And we intend to use share buybacks more actively.

Before I continue outlining our future prospects, let's take a brief look back. It has certainly been a decade of transformation for Statoil. The merger enabled us to compete more effectively. We have focused more on the upstream, and we have built a highly competitive resource base. And we have, throughout this period, been able to deliver returns to our shareholders above the average of our peer group. And three years have passed since we presented you with a strategic framework in New York, and I think you have seen our teams making progress. Our exploration team has truly delivered world-class performance with high impact discoveries -- 11 in Norway, in Brazil, in Tanzania, as well as in Canada.

And a few years back, many of you raised many concerns about the situation at the Norwegian continental shelf. The outlook was questioned. In the last three, four years we have seen a development better than even we anticipated at that time. And today, the NCS is truly revitalized with a longer perspective.

Also, our project execution teams have delivered well on our project portfolio -- on-time and at-budget, creating more stability in our performance. And on top of that, we have seen profound changes in the European gas market. We decided to move quickly to adjust and to modernize our gas contract portfolio. At the outset, this was not without risk, but it has worked. And I think it turned out to be the right move.

In summary, I think we can say that the strategy has worked and our teams have delivered. The details of the 2013 numbers and performance will be outlined by Torgrim later on today. I will limit myself to give a few overall perspectives. And looking at our performance operationally, I think we were more stable, with continued safety improvements and production, as expected.

I already talked about our exploration performance. And we had the highest RRR, at 147%, since we started reporting on SSE reserves back in 1999; confirming, I think, the long-term outlook of Statoil. And, remember, the recent high-impact discoveries has not yet moved into the RRR ratio. And on the financials, I think we still delivers competitive returns on capital employed.

But, of course, there are also areas where we need to improve, and let me start with safety. We are improving, and it's a clear sign of improving quality of our operations. But we still have incidents, incidents that should not happen, so we need to continue to work hard to strengthen our performance.

On security, following the In Amenas terror attack, we have addressed security more forcefully. We need to improve, and we are on the way with a comprehensive improvement program, and this will have an impact.

Third, being the world's largest offshore operator, and with 40 years of operating experience, unplanned losses are still too high, so we need to intensify our efforts to deal with that.

And, finally, this industry has not the best track record, in my opinion, when it comes to cost and capital discipline. And in today's operating environment, we need to step up.

So, let's look at our strategy. As I see it, the hallmark of our industrial progress has been our strong technology and upstream positions. And we will continue in the direction that we communicated around in 2011. And this is our roadmap. It shows you how we will move forward, and how we intend to prioritize and focus.

On the back of leading exploration results, we will continue to invest at a high level in exploration with the same strategy, because it works. I think we have an encouraging portfolio, that Tim will speak about later today. Further, we will intensify our efforts to improve efficiency and strengthen our competitiveness to deliver value from our operations, onshore as well as offshore.

On the project side, despite delivering major projects on-time and on-budget, I'm not happy. I'm not satisfied, because the cost in the industry is simply too high. We therefore need to redouble our effort in this important area. And attacking this basic industrial challenge gives the opportunity to set new standards, both when it comes to profitability and return.

Then, moving to the midstream, we have a superior European gas position, roughly with 15% market share. As you have seen, and as I already spoke about, we have adjusted to new market realities. The share of direct sales and sales on liquid hubs are on the increase. At the same time, we continue to realize prices at very good levels for European gas, and we will further capitalize on this position.

In the US, we have, in a very short time, strengthened our midstream position, increasing the value of our onshore assets. We've taken positions, as you know, in gas pipelines going to Toronto as well as to Manhattan. And these, our actions, now providing solid value uplift on our gas positions over there.

And, finally, we will continue to be more active when it comes to portfolio management as part of our strategy and toolbox to enhance value. So, while our direction remains unchanged, we are making some important adjustments. By introducing certain changes, we believe we will deliver improved shareholder value and returns, while maintaining the opportunities for our long-term growth.

Why and how can that be? We have had exploration success; therefore, we can now focus on the best assets and prospects. We simply have more choices. Secondly, we respond forcefully to industry challenges related to increasing cost and capital intensity. Here we are stepping up with a very specific plan and a comprehensive set of actions to deal with this industry challenge. And also, in a volatile world and in an industry that is cyclical, we need to make sure that the Company can operate in different pricing environments. The adjustments and the plan that we are presenting today will make us, in our opinion, even better prepared for different price scenarios and outcomes, both in terms of the balance sheet but also in our optionality for the future.

So let me now tell you how we are going to deliver on this. Growth has been a distinct part of Statoil's profile, and will continue to be so. From our position of strength and now more optionality, we will continue to deliver growth. In the period from 2013 to 2016 we expect, as I said, 3% average annual growth from our portfolio. Stricter priorities, combined with a program for capital efficiency, will help us to reduce capital spend with $5 billion in the period. And we'll talk more about that later; and, again, compare it to the plan we had previously. And in a $100 environment, the plan enable us to cover dividends through organic free cash flow in 2016.

In recent months, we have analyzed how to benefit from our flexibility. We have scrutinized every part of our portfolio. We have worked hard to improve the profitability of projects, and we have prioritized opportunities that yielded higher return. And you have also seen some more recent divestments. By focusing on the premium assets and systematically working to optimize concepts and solutions, value will further improve. We will build on our solid project execution record to deliver on-time and on-budget. And the result is improved profitability, taking the internal rate of return from 16% to 24%, if you compare the ongoing projects in execution with non-sanctioned projects.

And Johan Sverdrup is of course a fantastic example in this respect, and we are in the final stage of selecting the concept. And we expect an investment decision in a year's time. And I think this will be the best example of high-value barrels any CEO can talk about these days, coming onstream towards the end of this decade -- delivering value for many decades to come, to Statoil, and also to our partners.

One of the areas I believe Statoil stands out is on our operating experience. We have four decades of technology development, innovation, and operations of complex offshore assets, and this is the real core of this company. In recent years, we have made good progress in improving efficiency and reducing costs. We have introduced a new operating model at Norwegian continental shelf after the merger, driving efficiency and better safety. We have increased industrialization and standardization. Best example was the current portfolio or the fast-track projects. We have taken actions, as you have seen, on the rig side to insure capacity at good prices. And also in our North American onshore business, we are improving by taking over operator ships in terms of drilling.

We have also taken important steps over the last few years to leverage the global supplier community better. And right now we are executing a number of mega-projects in South Korea, offering high quality at lower cost.

In addition to all of these actions, we are addressing also organizational efficiency. In January this year, we decided to outsource certain staff functions. And earlier this week, we announced a streamlining of our strategy unit. And our efforts have yielded results. They are measurable. And on the NCS, the field costs have been stable 12 consecutive quarters.

We have now launched an extensive corporate efficiency improvement program. We have identified a broad set of areas where we can achieve improvements, from offshore drilling to optimizing midstream assets. This is just not another initiative. It's ambitious and it's concrete, specific, and it's measurable. In total, our improvement program gave expected annual savings of $1.3 billion from 2016 and onwards. And Torgrim and Margareth will give you some more details on the program, later in their presentations.

I have discussed prioritization and efficiency and cost. In addition, active portfolio management has been an integrated part of our strategy, and you have seen us taking actions. And there is a pattern there. We continuously maximize returns from existing producing assets and prioritize the most value attractive assets. And we will, all the time, evaluate whether we are the right owner of any particular asset. And in 2013, our strategy provided good opportunities for value-creating divestments in the North Sea and UK and Norway, as well as in Azerbaijan. And these transactions realized significant value and released capital we can now deploy in projects with higher returns.

I started my presentation today presenting our priorities and also our financial commitment to you. And let me expand somewhat on what you should expect from direct returns. In line with the dividend policy, the Board proposes a dividend of NOK7 per share for 2013. That's an increase. And following changes in the Norwegian law in 2013, the Board will also propose introducing quarterly dividend payments, already from this year. And subject to annual general meeting consent, the dividend for the first two quarters for 2014 will also be paid out in 2014, in addition to the 2013 dividend, giving our shareholders a 50% extra payout in 2014. We are committed to the efficient distribution of capital to shareholders also using share buybacks as an integral tool more actively into the future.

So, what about the long-term? And backed by a very strong project portfolio, we remain a growth company. We are entering into a decade of execution and project deliveries that will support the underlying growth in production, revenues, and continued value creation. We have, as you know, a very attractive portfolio at the NCS, with prospects of a prolonged plateau beyond 2020, in both mature but also in more frontier areas. And we maintain strong positions in the most attractive parts of North American onshore and offshore, Brazil, Angola, and Tanzania, to mention some. And, as Tim will show you later on, we have achieved early access into basins with high potential for the decades beyond 2020. And I think you will agree with me that the project portfolio and the opportunities on the slide here is a portfolio that very few oil and gas companies can match today.

So, this is one part of the sustainability, the long-term prospects of the business. There are also other sustainability measures, and first is a prerequisite for sustainable, long-term performance, in my view. It's fundamental for getting access to resources, access to capital; but, not at least, access to the best people. And trust must be earned, first by a credible plan and by delivering results; ensuring quality in operations; and, of course, high safety performance.

Second, a strong values platform, high ethic standards; following rules and regulations. Yes, compete fiercely, but we would like to win the right way.

And third, through openness and transparency, engaging with all our stakeholders to create stability for our operations. These are not nice-to-haves; they are needed to open a competitive space for big companies like Statoil.

And finally, a trusted company needs to be in sync with society and the general public. If you are unable to meet the most pressing issues of our time, like the climate change, that will almost be impossible. On all of these issues, there are growing demands and expectations on big companies; but I believe Statoil is favorably positioned, and we will continue to work these issues very hard because we think they are fundamental business issues.

Let me close, and very, very quickly summarize. We continue to grow our business. We take down the CapEx estimates. We improve our cash flow. And we will continue -- we will do this while continuing to deliver competitive shareholder returns. This is our plan. This is how we will move forward and build an even stronger Statoil.

Thank you for your attention.

And by that, I think I should give the word to Torgrim Reitan, our CFO.

Welcome, Torgrim.

Thank you, Helge, and good afternoon, everyone. Today, I will present the results for the fourth quarter and the full year, and I will lay out the details of our new plan. We are making important changes, entering into a new phase of tougher prioritization and a better balance between returns and growth.

But first, let me take you through the results. 2013 was a year of strong strategic progress and good operations. Our earnings were impacted by divestments; however, we maintained a stable production cost. We produced 1.94 million barrels per day. It would have been 40,000 barrels per day higher if we adjust for the divestments and the re-determinations. And this is in line with our expectations.

Our reserve replacement rate was strong, 147% in organic RRR, and as Helge said, this is the highest since we started to report on [SEC] reserves. It was 128% when we take into account the divestments.

Then we had another very good year within exploration, 1.25 billion barrels from the drill bit. It's leading in the industry last year.

And then, we continued to deliver on transactions, more than $4 billion in proceeds, leading -- realizing $2.7 billion in capital gains.

And finally, we continue to increase the dividend to NOK7 per share this year, and that translates into a direct yield of around 4.7%.

In 2013, we delivered adjusted earnings of NOK163 billion. Compared to last year, this is impacted by divestments and redetermination. In the fourth quarter, adjusted earnings decreased by 12% from 2012. Solid earnings, but international results was impacted by the North American business. And I will come back to this on the segments.

The quarter was also impacted by lower production, and this is as expected. Our reported cost and SG&A were influenced by increased activity. And this is related to activity-based cost as royalties and transportation and one-offs. So adjusting for this, our costs are around the same level as last year.

We have also made adjustments to reflect the underlying performance, as we do every quarter. We adjust for negative impacts of around NOK5 billion in lower fair values of derivatives and NOK1.5 billion in impairments and a positive impact of more than NOK10 billion in capital gains. So all inclusive, we delivered a 14% increase in net income this quarter.

So let me then turn to the segments. We continue to deliver strong results from our Norwegian business. The cost focus is paying off, and despite having more fields into production, we have maintained stable production costs for 12 consecutive quarters. We have also started production of our fast-track project number six, which is Bay du Nord, and it is performing as expected.

From our operations outside Norway, we achieved record production, ramping up production in the US onshore, in Angola, and Brazil. However, you will see that the earnings for these segments are down to NOK3.6 billion in the quarter. And this is mainly due to higher gas share, lower realized prices, and high depreciation in North America. The increase in DD&A is due to a high portion of production coming from US onshore fields with a relatively high DD&A rate.

It is worth mentioning that a significant part of the value creation in the US onshore is supported in the MPR segment.

For the full year, our international earnings increased by 1%. Around one-third of our production now comes from outside Norway. And the cash flow per barrel for our international production is on par with our Norwegian production. So we are growing internationally and it is a profitable growth.

Our business in the marketing, processing, and the newbuilds contributed with around NOK11 billion last year. And for the quarter, we reported very strong earnings of NOK3.7 billion. We see a particularly strong contribution from US this quarter, having significant value on the Marcellus gas by delivering into higher-priced markets in Toronto and, the more recently, into Manhattan.

And in addition, we have created a lot of value through LNG arbitrage. Then it is no secret that many refineries are generating losses across our industry. And our refineries are no different. This is, of course, not sustainable. And we are working hard to take out further costs in that business.

And finally, we see another strong quarter for our natural gas business in Europe, achieving strong sales and realizing prices at a record level.

Equity production was down 4% in the quarter, compared to the same period last year. We continued to start up teams and ramping up production. However, this was more than offset by divestments, re-determinations, lower of gas -- lower gas offtake on the NCS, and expected natural decline. For the year as a whole, production was 1,940,000 barrels per day, and this is in line with our expectations.

We generated cash flow of NOK219 billion from our operating activities last year. This is a reduction from 2012, mainly due to lower volumes and downstream margins. However, it is worth noting that last year, we paid more taxes in 2013 than the reported taxes. And this is due to higher earnings in 2012, with a six-month delay in payments. So adjusting for this, our net cash flow would have increased by NOK8 billion. So the net cash flow would have increased from minus NOK4 billion to plus NOK4 billion for the full year.

So, looking at our gross investments, organic CapEx was $19 billion, and this is in line with what we guided for.

We delivered a record reserve of placement through a strong effort by our organization, adding nine new fields that improve reserves in 2013. And all in all, 900 million barrels have been added.

Shah Deniz is an important contributor. And I need to remind you that the effect of the divestments will impact RRR for 2014. This will impact the reported RRR, but of course, not the organic RRR.

In 2013, we added resources of more than two times production through exploration and increased oil recovery. And this secures a strong resource base of 22 billion barrels and it is a competitive resource base.

So, then let me move to the capital markets updates. Today, I have three messages that you need to remember. First, we are high-grading our portfolio, prioritizing hard and allocating investments into the most value-creating projects. We are reducing our investments by $5 billion in the period 2014 to 2016. We are ensuring an organic free cash flow to cover dividends in 2016. And we are increasing the profitability of the projects.

Secondly, we are increasing efficiency across our business. We had expected annual savings of $1.3 billion from 2016, and making us even more lean and competitive.

And third and finally, we reaffirm our commitment to capital distribution. We are growing our dividend, introducing quarterly payments, giving additional distribution this year, and making more active use of share buybacks. This will give a return on capital deployed on today's level going forward, and 3% annual organic production growth from 2013 to 2016 on a rebased basis. And as Helge said, this is how we will move forward and build an even stronger Statoil.

Value creation is our target. And we have many world-class projects, like Johan Sverdrup, like Johan -- like Bay du Nord, and the pipeline for the next decade is very solid. Our portfolio can deliver more than 2.5 million barrels per day in 2020. But we will be more selective in which projects we pursue in the near term.

Therefore, we have decided to divest certain assets, more than $18 billion in proceeds over the past years and delivering around $10 billion in accounting gains.

We have also demobilized some projects, saving them in the bank for later. Examples here are Eirin and Bressay. Then we optimize other projects through specific improvement programs and looking at the different concepts. Johan Castberg and Snorre 2040 are examples of this.

Through these actions, we significantly improve our value creation. Our future projects with startups before 2020 will give an internal rate of return, on average, 24%, assuming $100 per barrel.

And we increase net present value per dollar spent from 19% to 37%. This means that the next wave of investments will generate even greater profits than the current developments. And the majority of our new volumes have a breakeven below $45 per barrel.

30% of our investments are nonsanctioned, so we control the progress ourselves. You should expect that we will continue to adjust our portfolio and you will recognize the pattern.

I know part of your job is to compare our performance with our peers. And I like to compete. And I am proud of the quality and depth in our project portfolio. We have more than 100 projects to choose from, and you will see that the expected return from our prioritized projects is highly competitive. And in new developments, we lead our peer group in terms of profitability.

So our job is to deliver these projects on schedule and cost. But this will be key, so let me talk about what we are doing within this area. I am pleased that we are competitive at cost, with a low unit of production cost compared to peers. But at the same time, we must continuously improve, and that is why we are addressing the industry challenges head on.

We have put in place an improvement program that will deliver annual savings of $1.3 billion from 2016. This is included in the investment estimates going forward. Please note that the impact will be significantly larger if we deliver on the ambitions stated to the right. Margareth will go further into detail on the CapEx improvements later on, so let me just comment on our operational costs and SG&A.

We will see underlying production growth until 2016. And we aim to keep total production costs at 2013 levels in real terms, even if production is growing. This is an ambitious target, as we already have a competitive unit of production cost.

In addition, we will continue to reduce operational costs at the refineries and processing facilities. And we are reviewing the entire cost base and reducing [many] to increase our organizational efficiency. So these improvements will impact the bottom line and I will report on them annually going forward.

We are already seeing effect on the bottom line. The staffs and services project that we have run has reduced field costs in our Norwegian business by several hundred million krones already. And there is more to come. This is about making the right choices when we can, not waiting until we have to. And every dollar counts.

Today, we reiterate our commitment to capital distribution. You know our dividend policy well and we have proposed an increase to NOK7 per share for 2013. At the annual general meeting, we will propose to change the payout schedule from annual to quarterly dividends starting this year, and this means we will pay out two quarterly dividends in 2014, namely in August and in November, giving a distribution similar to 1.5 annual dividend payments this year.

Given the additional distribution in 2014, we will not initiate this year buyback now. However, we expect to use share buyback more actively going forward. This will depend on our proceeds, on our free cash flow, and the balance sheet.

We come from a position of financial strength. We are generating strong cash flow from our producing assets and we have reduced our net debt from 27% to 15%, while investing significantly. And at the same time, we have grown dividend and we have maintained a very solid credit rating.

In 2014, we will increase our net debt slightly to around 20%. This is impacted by the implementation of quarterly dividends.

Going forward, we will maintain a strong balance sheet and maintain net debt to capital in the area of 15% to 30%. We expect to generate around $22 billion per year, on average, in cash flow from operations, with a gradual ramp up. Then, we have decided to invest our own $20 billion in organic OpEx this year and around $20 billion per year towards 2016. And I want to mention that 40% of this investment program is related to projects starting up after 2016.

Let me point out that these are gross investments, so it does not include proceeds, and we will continue to manage our portfolio actively also going forward. And we are investing into profitable growth. Around 45% of our investments will go to our Norwegian business. 60% will be related to liquids and around 80% will be within OECD, maintaining a portfolio resilient to political risk.

Finally, we expect our organic free cash flow to cover our dividend from 2016, and this will be the case also going forward.

We will continue to grow our production. The prioritized projects will deliver organic production growth of around 2% between 2013 and 2014. And this is from a rebased production in 2013 of 1,001,850,000 barrels per day as we adjust for the impact of divestments and re-determinations.

Several projects are starting up this year. On the NCS, we have Gudrun, Valemon, [villiasouth], and several fast-track projects. Outside Norway, we have CLOV in Angola, Jack and St. Malo in the Gulf of Mexico. And we will also continue to ramp up production at earlier startups, like [PSVM] in Angola, our fast-track portfolio in Norway, and our onshore assets in the US.

Then our growth will accelerate to three percentage points in the period 2013 to 2016. Goliath and Big Foot are the main contributors towards 2016, in addition to the fields already mentioned.

Our current portfolio of producing assets is performing well. Decline is stable at 5%.

As you know, our current portfolio has the potential to produce more than 3.5 million barrels in 2020. But we are prioritizing value over volume, and we have decided to create a better balance, taking on investments and balance cash in with more spending. And with this in mind, we still expect to raise production to 2.5 million barrels, but we now expect this to be three to four years after 2020.

And I think it is important to note that this is not a target. This is the portfolio that is there and has the ambition, and our current plans indicate that. This is a result of the decisions we have made to high-grade growth, including divestments and optimizations.

I am pleased that Statoil is performing well on the ROACE compared to our peers. Our ambition is to remain in the top quartile of the peer group. However, I am not satisfied with the falling ROACE in the industry and in Statoil that we have seen over the last years. The measures that we announced in Statoil today will reverse the trend.

So going forward over the next few years, we expect to maintain ROACE and returns around the same level as in 2013. Assuming an oil price of $100 per barrel, the ROACE in 2013 was 11%, and for the coming years, we expect to see our ROACE at the same level at similar prices.

So let me summarize. We are making changes, prioritizing hard and high-grading the portfolio, increasing the efficiency and prioritizing capital distribution to shareholders. This gives a more balanced growth with higher returns. We have the organization and we have the capabilities to achieve this, and we have the technology and we have the asset base. And we have proven that we will deliver on this strategy, we have proved that we do, so I'm really looking forward to the next chapter.

So thank you very much for your attention, and then I will leave the work to Helge to guide us through the Q&A session. So thank you.

Thank you very much, Torgrim. We will now open up for questions, both to the CEO and to the CFO. And we'll take questions both over the telephone and from the audience. So, first of all, I'll ask the operator to explain the procedure to those who are with us on the audio conference today for posing questions.

(Operator Instructions)

And we'll start with the questions from the audience here in London. And we'll take the first question from Lydia.

It's Lydia Rainforth from Barclays. Thank you very much for the presentation. Two questions, if I could, please. Firstly, on the improved distributions to shareholders. It's obviously always very welcome, but what conditions would you need to actually trigger the share repurchasing? Is it a certain gearing level? Or is it if you get $2 billion in from capital divestments, that's what you would want to return to shareholders? How will that process actually work?

And then, secondly, if I can push a little bit more on the cost side, actually the -- much more of it seems to be on the capital side of it rather than on the operating cost side. And I take the point around growing production. But it does seem that it's only about 2% of your existing cost base that you are planning to save on the OpEx side. So should we see this as a minimum level that you are looking to achieve, and that you can take that a lot further, not necessarily to 2016 but beyond that?

Well, on dividend, we think about our balance sheet that we should be able to, one, invest in good projects; make sure that we have a resilient balance sheet so that we can tolerate different price levels; and finally, to be competitive in the way we return directly to shareholders.

We have the dividend policy that we have delivered on, I think, very precisely over the last few years. We intend to continue to do that. That is the proposal from the Board this year as well. The plan -- give more capital efficiency. And we indicate that we will use share buyback more actively than we have done in the past. And we tie it to the balance sheet strength, the cash flow, as well as proceeds from transactions.

You would also see that we are indicating that we would like to have a single A rating, and we give certain preferences in terms of where we would like to have net debt to capital employed. These are more broad guidelines, not exact numbers. But the intention today is to, again, reinforce our commitment to dividend also directly to shareholders.

On the efficiency program, in a way you are right, but there are many of the costs that eventually go into CapEx -- like, you know, drilling, and how we develop our projects. So if you think about those $1.3 billion in savings from 2013 -- 2016 and onwards, roughly $1 billion is in CapEx and the rest is on the efficiency or on the cost side, which covers operational costs and SG&A. And hopefully, these processes can lead to momentum, so we can capture more; but this is what we are prepared to commit to today.

Then we have Theepan, please?

Theepan from Nomura. A number of questions, please. Firstly, just, I think, in terms of investment going forward, you were around 20% in North America. So I just wanted to perhaps get a little bit more color how you split that between the Deepwater, particularly on conventional and sort of heavy oil, and the onshore? And are you sort of comfortable with the position in North America as it stands?

Secondly, just a point of clarity on CapEx. Just going forward, I mean, do you expect CapEx perhaps to just broadly stay flat in the next couple of years beyond 2014? Or is there a risk CapEx goes up in 2015 before then coming down materially in 2016? And, again, as investors typically there have been -- we've been given three-year plans in the past, and cash flow delivery is largely being backend-loaded. So I just want to clarify sort of the comment around a gradual growth in cash flow from operations.

So, on the North American business, they have several sort of paths. One is Gulf of Mexico, which is existing, producing assets; and then a portfolio of very good projects under execution by our partners in Gulf of Mexico, that will be very important contributors over the next five, six years. For starters, overall, profitability. So there will be significant CapEx going into these projects over the next few years offshore Gulf of Mexico.

On top of that, we have high-graded our exploration program in Gulf of Mexico. Tim will talk about that later today, so you will get more details. Then you have the offshore exploration in East Coast Canada, where, of course, we need to continue to explore in the area around Badinor. So Tim will talk about that as well.

In terms of the oil sands business, we have the Leismer facility. And the next project in the oil sands business you would see on the slide of Torgrim, that these are projects that we need to optimize further. And then, finally, you have the onshore business, the shale business and the tight oil in Bakken, Marcellus, and Eagle Ford. And, of course, there are significant contributors to EBITDA. And then we have to, as we see the market develops, how much CapEx do we put into that business. So those are the overall sort of thinking around the portfolio.

In terms of CapEx, we guide on the average number, $20 billion for the three years' period on average. I wanted to underline also that roughly 40% of that CapEx goes into projects that we start producing beyond 2016, just to underline the importance of building also long-term goals for Statoil. In terms of cash flow from operations, you are right in making the assumptions that we'll be higher at the back end of the period than in the beginning, but we have guided them on [22] on average for that period.

You might want to add -- if there's anything to add, Torgrim?

It will be gradually increasing towards 2016. We have new fields coming into production with lower tax, and especially in the Gulf of Mexico that will have a huge impact on the cash flow from operations.

We have the next question here in the second row, first line.

Edward Lucas from The Economist. Could you talk a bit more about the gas arbitrage that's proving so profitable? What is your business model there? What gives you the advantage? And how sustainable is that? And secondly, I don't think you mentioned the word Russia at all, which is your large eastern neighbor. I just wondered if you could talk a bit about your links with Rosneft and whether you see anything there that could replace the huge enthusiasm you once had about the Shtokman field?

So all the gas arbitrage we have on LNG facilities up in the Bering Sea in Norway called Snow White. So we actually own that contract ourselves, that makes us able to send the gas to the most profitable market. And that is to the beauty with the LNG. And we are pursuing projects in our portfolio that, hopefully, will give us more LNG. Right now we are maturing more resources in East Coast of West Africa and Tanzania, and hopefully, that can be our next LNG project.

Of course, there are wide price differentials between the US, Europe, and Asia. We expect relatively stable prices in Europe. And Europe has to compete for the marginal barrels or cubic meter of gas with Asia. We expect gas prices in the US to increase, as there will be more demand and also on export. And perhaps, over time, when there are more -- even more LNG coming into the market, perhaps you will see a slight reduction in Asia.

In terms of Russia, huge hydrocarbon potential. We are close to Russia in Norway. We have areas where I think Statoil has particular competence. Most notably, I think offshore competence in harsh environment. So we have a joint venture with Rosneft that is covering the Bering Sea. Part of the formula disputed, sold in between Norway and Russia, and then almost 80,000 square kilometers of acreage in the Ausk Sea. So we are now running seismic in these areas and are preparing for drilling over the next five to six years.

Then, interestingly, we have also entered into a joint venture with Rosneft onshore, where we are actually using the capabilities that we have built now for several years in doing shale and tight oil in the Americas. And we think that that is a significant potential in Russia also on that part of the industry. So we have worked closely over the last five, six years with Rosneft.

We pursued also Shtokman for many years, both in Heidrun, and subsequently in Statoil, and subsequently in Statoil Heidrun and then Statoil. But the changes in the gas market and the cost of that project simply did not make it profitable as of now. So, the resource base is huge, but so is the capital intensity. And right now it's not profitable. So we are not any more part of that project. So, either the gas market has to change or you have to make much cheaper concept.

It's Michael Alsford from Citi. Two questions just on the framework. Firstly, could you maybe break down what the split is in terms of the CapEx saving of 5 billion between what's been disposed of, in terms of assets? What is project deferrals out of this for the 2014/2016 plan? And then perhaps what is obviously the sort of capital efficiency point that you make? Is it simply the $1 billion that you mentioned in 2016?

And then, secondly, just on the kind of comment you make about the strength and profitability of your portfolio, when you look at the projects pre-sanctioned that will start up in 2020. When I look at your chart, it's just simply Johan Sverdrup and IOR projects. Is that the case? Or are there other projects within that number?? Thank you.

So, if you want to take the last, Torgrim. On the CapEx and the assets, of course, we have -- we had guided earlier on 2.5 million barrels per day, and the CapEx that we guided earlier, we are associated with that number. Of course, there's source based and we have much more project to that. The project is that Torgrim showed, where he had categorized it in different columns, gives some indications of that, but we are not prepared to go into even deeper details on that. But I can say that we are prioritizing our project portfolio on a global basis to make sure that we have a portfolio that is efficient from a corporate point of view.

In terms of CapEx savings, you're right, that the program that Margaret will talk about later today, $1 billion out of this $1.3 billion in savings are associated with savings anticipated from CapEx, i.e., running future projects and drilling in a better way than we do now.

And that $1 billion is -- you need to compare that to our operated share of our investments. And in 2016, that's around $11 billion, with one out of 11. So you get the size of the land magnitude. On the 24%, and which projects included in that, it is actually 16 projects. Johan Sverdrup is, of course, there. It is a large and a very good contributor to the number, but there are many others. It is a few group of Mexico assets, cross-track projects, IOR projects, and Johan Casper is also included in that portfolio.

All right. Thank you.

Next question, please.

Alejandro Demichelis from Exane BNP Paribas. A couple of questions. On the framework on the CapEx coming back to that, I think now you mentioned in the 2.5 million barrels, that's still achievable within your portfolio maybe three, four years later. And I think that if we go back to the previous CapEx indication, you were saying that what you were investing was in line with the 2.5 million barrels. So the question is whether we are going to see an increase in CapEx after the 2016 period, because you're still going to be chasing the 2.5 million barrels probably three to four years later?

Second question is on M&A. I think we have seen increased speculation about potential deals. Maybe you can tell us where do you see any kind of cap in the portfolio? Or whether you think that you can reinforce your portfolio, if anything?

I'm not following all the speculations about what we're going to do and ought to, but I heard this morning that we were speculating that we will acquire an exploration company. Right now I think I have the best exploration team in the world. I don't need more exploration teams to Statoil at this stage. We have a key focus now actually on maturing, developing our resource base organically.

I think, nevertheless, it's our obligation as a management team, as a Board, to follow opportunities in the market, both in terms of selling assets when that is right and also buying, if that adds value to Statoil altogether. But I would like to send a very clear signal now that the key focus on my management team is really on executing on the plan that we have presented to you today.

In terms of the 2.5 million barrels, sort of ambition that we have, I think when we launched it in 2011, most people sort of questioned it due to the resource base. Not any more. I think all of you see that we can deliver 2.5 million barrels if we want to do it, based on the resource base. It's much stronger when we launched that ambition in 2011. But I think it's our obligation to think when our situation changed, the market changed, we need to change too. And with the cost increases and the capital intensity in this business, I think it's more value-creating by going a bit slower.

And we indicate to you today that we will have net cash flow from our operations to fund CapEx and dividend from 2016. Our intention is to leave it out within our means also moving forward. But I think also what happens in four, five, six years, I think it's too early to say, but we've honestly sent a strong signal again that we are value-driven. And that is sort of the key guiding star for us moving forward. And we just indicate to you that, as we see it now, the current plan gives 2.5 million in 2023. But as Torgrim underlined, this is not an objective for us. The objective is to make money -- period.

Nathan Rozof for Morgan Stanley. Thank you for the presentations. Just two questions, if I may, please. So, firstly, on tax rate guidance, both for this year and perhaps longer-term, if you could just say a few words about that, particularly in the context that CapEx now lower than your previous guidance, does that mean you get less of an uplift from the NCS, and what that could do your tax going forward?

Second question is on CapEx itself and just on the exploration side, what are you assuming beyond 2014? You've given guidance for 2014 exploration spend; but for 2015 and 2016, are you assuming that that tails off or actually moves higher from current levels? Thank you.

So, I think my role in -- on taxes is really to speak with as many governments as possible to make clear sure that the taxes are stable as we move forward. So maybe you want to respond to that on exploration? Roughly one-third of sort of our exploration activity will go into the CapEx number. That is basically as we have done it the same sort of ratio that we have had before.

Yes, on taxes, going forward, you should expect corporate tax rate around 70%. We had 70% to 72% earlier; but as we look at it now, it's more close to 70%. And that goes due to the mix in the portfolio. If you split that further up, I think you should anticipate the Norwegian business, 72% to 74%; internationally, 50% to 55%; and the NPR, 50% to 60%. There are some adjustments to that outlook on tax rates.

Jon, please?

It's Jon Rigby from UBS. I'll preface the question by just saying I very much like the structure of the financial structure that you're describing about the way you're looking at the business right now. But what I wanted to say was, or ask is, it's become evident perhaps over the last 18 months or two years that your thought processes have changed about how you are running the Company. You had a view out to 2020, but clearly, the actions you were taking in terms of disposals and so forth were already jeopardizing that volume number. So, you are clearly already starting to think about balance of growth and returns.

So, two questions come out of that, I think, is -- first is, how are you measuring value and the balance between growth and returns? What is it internally in the Company that you can make the judgment call about whether you're going for the extra 1% or so of volume versus the lower CapEx that you've made that choice today? And following on from that is, can we understand the structure and the outlook that you're now providing as one that's going to be a sustaining one going forward? Because it feels to me that you did start to wander off the sort of vision that you made three or four years ago.

The second question is just a particular one on one of Torgrim's slides. I think you indicated that there was some investment CapEx going into projects with a sub-10% IRR. And I just wondered why you were doing those projects? Thanks.. Thanks.

So, in my view, this strategy or this Company has not changed, in the sense that I would like to think about Statoil as a technology-focused upstream company. I think we have steered the Company in that direction very firmly over the last 5 to 10 years. We have sold shipping, we have sold petrochemical. We have sold retail -- the retail franchise. We have sold pipelines -- simply to put capital into the area where we think we can compete the most effectively, and that is really where we have our basic skills.

So that is one part. The second part that we would like to continue to grow our Company, and there is no change to that today. But we are taking down -- we are taking the foot off the accelerator a bit and go with a little slower pace, because we think that makes more sense in the current industry and environment. The way we think about profitability and how we measure it, I can, unfortunately, not give you one number that we look at. But how we think about it is that we run every project through a very rigorous mechanical project where we test IRR, net present value. We test it -- the solidity of the project, and so on and so forth.

And based on that, there is a ranking. And then, of course, we, as a management team, we have to assess all the factors as well -- i.e., do we have to attempt to a project now because the license is going out? Do we have to do it even though it's a third quartile project? Because otherwise you lose the resources on the ground. And there could be other reasons as well. But based on that, we try to find the right balance.

What we are trying today is actually to be quite specific not only saying that we give priority or trying to find a better balance, but also trying to provide some evidence that actually the actions we have taken in our best measurement will give higher returns. Maybe you want to take that, Torgrim?

Thank you, Jon. We don't decide everything ourselves. So I think that's sort of my first question. I can give you an example -- chart in this Phase II is more to the right in that chart to the left. We are not operator. And we choose to reduce or own the ship share in that fleet.

Peter is next now. Peter?

Peter Hutton from RBC. Thanks, and particularly thanks for the targets and guidance that you're giving, which is sort of nicely rounded -- nicely joined up. And distinctively, has [ROCE] in there, which I think some of the other people are missing. One question following up from that, though, is I think you said during your presentation that 40% of your CapEx over the next three years was going on projects that would not be delivering by 2016. So that suggests that you're spending 60 billion; 40% is not going to be producing 25 billion capital not employed. Is that included in your keeping your ROCE target at 11.8? Or are there some adjustments that we might expect to have to make?

No adjustments; only price. So there's, in 2016, there will be quite a bit of capital unemployed. So if you adjust to that, it will, of course, be a much higher return on capital employed.

Matthew?

It's Matt Yates from Bank of America. A couple of questions, if I may. First one to Torgrim around the balance sheet strategy. Having now, I think, in the past, you've said you wanted to keep a fairly conservative balance sheet in order to fund future investments. With you scaling back the CapEx slightly, does that give you more flexibility on the balance sheet side to maybe take advantage of lower rates and boost group returns that way?

And then second question is around the results we had in Q4 in the international business. Can you talk about some of the issues you highlighted are arguably more structural in nature, in terms of realizations? Does that in any way come into your strategy about future CapEx or future acquisition appetite on onshore US?

So, on the international business, we try to be very specific to -- the international business apart from the onshore business and the North American business, but that had some fields out of stream in the quarter made absolutely fine and according to our plans. The way I look at it is that, technically, the resources that we have entered into are some of the most competitive US onshore Eagle Ford, Bakken, as well as Marcellus. I think we have now shown actually that we can operate it technically, and we can use the scales that we have generated from many years of oil and gas activities. And then, of course, the price pattern is quite significantly different than we saw already a few years back. And, of course, that has to impact also the way we allocate the capital and how we think about it.

If you see, on the other hand, we cannot only think about the next one to two, three years, we need to also think about the longer-term, the way I think about Marcellus, for instance. Most likely will be a very important legacy asset for Statoil for many, many decades, with very efficient cost base. And hopefully, with more demand on the gas side, could give, for us, a very, very profitable, long-term assets moving forward. But the short answer is, yes, of course, market circumstances must also impact the way we allocate the capital.

On the balance sheet, it's very important and it's very strategic for us to run with a solid balance sheet and significant liquidity. What we say, that the strength of the balance sheet should be an A rating on an unsupported basis. In the credit rating we have some support in the rating in there. So that is the strength of the balance sheet.

Liquidity, we run with the cash and cash equivalents we're some DKK125 billion by the end of the year. So it's a significant amount. And actually, as we have actually used the bond markets quite actively in 2013, we picked up more than $10 billion. That was used to adapt the rates were very good and very attractive.

So the balance sheet is very solid and it will remain so. And that is due to the uncertainty that we see in the macro environments. We need to be robust. And I remember, Helge, when you hired me you told me, never put me in a situation where I am run by the balance sheets. And that is important for me to --

I have been there before.

-- to deliver on.

Maybe a few comments on the quarter results in DPNA as an internal pricing within the segments. So that DPNA organization we get the local Marcellus price. And we know that that is floated with gas and it's a low price.

MPR gets the Toronto price, Manhattan price and that margin. So I think it is important when you look at that business that you take into account the value chain. And I think it just demonstrates the importance of taking care of your hydrocarbons in the US. And I think we have done that pretty okay so far.

Oswald Clint at Sanford Bernstein. Maybe going back to returns, you talked about Statoil's returns and industry returns being terrible and how you would like to aggressively tackle costs.

I would like to just ask you about what sort of response are you seeing from your service suppliers as you embark on this strategy? What sort of response are you seeing from them already or what sort of response do you think you will? And is there enough of this happening in the broader IOC world that you can really start to see some cost reductions from your suppliers?

And then secondly, I think most of the companies maybe over the last five years probably spend a bit more on [Minton's] CapEx than they expected to do because of, obviously, natural decline rates. I wonder -- maybe you haven't seen that. But if you have, is that something you have factored into the next three years' CapEx numbers? Thank you.

In my view this is not individual oil company challenge on the cost on capital intensity. I think it has to a large extent to do with how this industry is working. And I'm not sure that this is the oil and gas companies against the service industry. I think that this is a challenge that we need to work on together.

And I think there are other industries that have been more effective in dealing systematically and over time with their cost base. I think the pattern -- and I've been in this industry, in several sectors, now for 15 years. And I think they are quite effective to work costs one or two years ended the prices changes and then they move on.

So I think this time we tried to attack it more structurally. And Margaret will talk about how deep we go into some of these areas. I think, for instance, there are quite significant quality costs in this industry. I think there are costs associated that we are not planning well enough.

I think this is an industry that loves to develop new things, so I think we can standardize much more. And I think also, including Statoil, the oil companies have developed extremely specific technical requirements that drive costs and make it very challenging for some of the suppliers to really deliver efficiently. So we have specific projects in Statoil but also with suppliers to see how can we deal with this issue.

Also there are examples like how many concepts did we work on before we decide and for how long time. And I think there is also an opportunity there to use our experience and to go faster towards the right concept instead of using all the engineering houses in the world to work on these different concepts. So it's a logic that I think this is something that we have to do together. And the more people that engage in this from the industry, I think, the higher chances that we will have an impact.

And the advantage I think we have in Norway is that we are relatively big, so that we can also look at opportunities across fields where we are operator. And, for instance, the way we have attacked the fast-track projects, the way we have dealt with the rig intake to take down the cost on certain fields where we have to drill for many, many, many years. Instead of paying down the rig three times, we own it ourselves and run the drilling program. I think this will have been very, very difficult unless we had operator position on several fields.

When it comes to bio-ore, if I understood the question right, we have factored the CapEx that goes into that work also into the guiding for 2014, 2015 and 2016. I hope I understood the question right.

It's Mark Bloomfield from Deutsche Bank. Your guidance on operating cash flow of $22 billion seems to imply around a 30% uplift relative to what you generated in 2013 on a 10% lower oil price. I guess a 3% compound growth rate in volume goes some way to explaining that.

But perhaps you could be a little bit more specific in helping us understand the contribution from the other significant moving parts here. And I'm thinking margin and whether you are making any specific assumptions around working capital or cash tax movements in there. Thanks.

That will be a very good CFO question.

Thank you. I think the starting point it's important to get right. There's a drag on taxes, so there's a lot of taxes paid in this year compared to last year. But on a comparable level, around [19] (inaudible) in this year.

So [it is a growth] from cash flow from operations and it comes from the production mix. The current mix has a lot of natural gas in the US and there will be more liquids over the next years and there will also be more liquids in lower tax regime. And then it's built up by production and all of that.

It is -- growth is rather stable growth in that direction. Then efficiency in the working capital is also very important and this is something that we work very diligently on. And it's important because the big size of the marketing and processing business.

Irene Himona, Societe Generale. You highlighted the importance of being resilient to different price scenarios and the importance of the credit rating. The targets are given on an oil price of [$100 real].

Are you prepared to give us a sense of what your return on capital would look like? And is there any flexibility to the CapEx plan, should oil turn out to be $90, for a period? And there is concern in the market right now, obviously, with discussions on Iran and indeed the increase in US supplies.

Well, there is, of course, flexibility in our plan. I think actually this is one of the most important commitments that we can give our shareholders, that we need to find a way where we balance or are able to steer the Company without very deep costs through different cycles. And I think you have seen us operating this quite effectively since the financial crisis back in 2008 and 2009 -- actually, as Torgrim said earlier today, with a stronger balance sheet now than we had at that time.

Of course, the balance for us is that we, and what I tried to say in my introduction today is that we both need to be prepared to handle significantly lower oil prices for a period of time, but also that we do not give away optionality for the future if you see a significant tick up in the prices. And hopefully, we have found that balance.

In terms of the oil market, normally we are very careful in predicting on that. But if I should give a few comments around that, it seems to me, at least, that the market outlook is a little bit better than it was maybe a year or two back, but still with uncertainty.

And if you look at the oil market, it would seem that it will be next year or this year, saw more growth in the non-OPEC side of things. So maybe that is indicating perhaps some softening. But I've said before that I think a monkey can predict oil price better than I can. So it is hard. But I think these are the factors that we need to follow.

If I may, Helge, I think we used $100 per barrel as a sort of a reference price in the calculations. We use a different price, a lower price than that, in our planning and our decisions.

And when it comes to our planning, we use various scenarios. We call them the good, the bad and the ugly. So it is about testing out that we are resilient in all these scenarios and have sufficient tools in place to deal with it.

Neill Morton, Investec. Two questions, please. You have been asked in the past about the government stake, Helge, and you have quite correctly said that it wasn't your place to comment. But there have been studies recently linking the possible dilution of the government stake with perhaps a corporate move by Stata well. Can you confirm or deny those kinds of conversations have taken place?

And then secondly, late last year you gave an interview in a trade magazine where you were quoted as saying that you saw or you foresaw a major restructuring of the oil and gas industry over the next five years. Can you clarify what you meant? Thank you.

For some reason I always get that question. As far as I understand it, the new government have said that they will issue a new white paper on the Norwegian states' ownership positions in different companies in Norway.

And this is not a white paper on Statoil, as far as I understand it. It's a white paper on a strategy on the Norwegian governor's ownership positions. And we, of course, also await the signals from that.

I will never, ever comment on individual situations or speculate on individual rumors. But I can say as a general direction now, the key focus we have in our management team now is actually to deliver on the plan that we have presented to you today.

And I saw also there were some comments on, you know, are you going to buy an exploration company, and so on and so forth. It's not very meaningful for us right now, actually, when we have to select from very good internal projects.

Having said that, and repeating what I said before, I don't think you would like us either not to think about asset divestments or acquisitions, if that is value creating. But I think what we need to do is to be very clear on if we do a deal on an asset, buying instead of developing ourselves, it has to make strategic sense. And you should understand why we do it.

On the restructuring of the industry, I think you can always have those speculations. And I think they could be reasons like addressing the cost side or you want to establish yourself in a specific geographic region. You would like to build a specific line of business. Or it can be simply two parties that have a different view on oil and gas prices moving forward, so that there is an area to transact.

But again, this is not something we spent much time on these days. We spend time on the plan, and we spend time all the time on looking at our portfolio to make sure that that is optimized as best as possible. I think we sold for $18 billion over the last few years and with a quite good return as well.

Was there another question in the back of the room, or did I -- no? Okay, then one more question over here and then we will turn to the audio audience.

[Nick Colon from August]; just a very quick follow-up on pricing and flexibility. The Troll field, the gas market is quite interested to know, given the recent fall in gas prices, will you pump to the cap in production of 30 billion cubic meters a year, or would you scale back that output?

Well, as you know, we have the two fields where we have flexibility on Troll and Oseberg. And we have a commitment to you as shareholders and also through the marketing instruction that we have with the Norwegian government, where we are also selling their gas on our behalf, to not maximize volume but to maximize value. And that is what I am prepared to say about that.

And of course, Troll and Oseberg, very important fields for Statoil. That was a political answer, but I think you understand I cannot say much more.

All right, then we will take a few questions over the phone. And I will ask you to please limit yourself to one question each, as we have around eight minutes until the lunch break. So the first one to go is Anne Gjoen and please go ahead, Anne.

I have a question in relation to return on capital employed in 2016 under free cash flow. Could you tell about the amount on capital employed in 2016? Because the point is that you are talking about organic free cash flow in $100 per barrel in 2016, and I know that is very far from analysts' expectations, although consensus has been too high with their estimates for a rather long time. So how much capital employed? And it's some worry here that it's very different assumptions, probably it's on natural gas price.

Okay. So I'm not prepared to give you the number for capital employed in 2016. But I think a good starting point is the accounts for this year and the investments and DD&A as an estimate. The capital employed is expected to increase towards 2016. So, return on capital employed, around today's level and on similar prices.

Next on the phone is Teodor Nilsen from Swedbank.

Congratulations, it was a very good reserve replacement ratio. I just wonder from which fields did the increase come from. And should we increase that (inaudible) to stay on levels closer than [150%] over the next few years, given that you have several more projects to be sanctioned over the next years?

So we have had a quite active year in terms of sanctioning new projects, but also to increase provisions or increase resources from our existing projects. Some of the projects that we have approved, of course, is [Oste on stand and also Shaktanis]. You will see results from the IOR activities and also some from the onshore business, but smaller amounts from there.

We have said -- what we said in New York in 2011 that we would see roughly an [RoR] replacement ratio about 1 for the decade, the next decade. And I think we are well on the way to do that, on average. And we will not guide and be more specific on that. But of course, we have some major fields coming up like the [Hans Sverdrup]. We are indicating that we will make sanctioning on that project in 2015, for example.

So we are confident that we can deliver more than 1 on average over this period. But of course, it will vary from year to year. Actually, I think this is one important development at Statoil, because for almost a decade we had reserve replacement ratios above or below, significantly above 1. And we have turned it now and we have reached portfolios, as we have discussed, that give more confidence about the longevity of our business, which is good for you, I think, and is good for the Company and for our people.

So you didn't book anything, any resource from [Optelis] or oil sand in 2013?

Yes, some. But we are not providing numbers. But it's not a major part, it's a small part.

Thank you.

John Olaisen from ABG.

A question on the return on capital deployed over the next quarters, or between here and 2016, I guess 11.8 will be the yardstick that we will have to measure on. Should we expect the return on capital employed to be flat in 2014, 2015 and 2016? Or should we expect it to go down and then up again in 2016? Tell me a little bit about that so we are prepared when we are looking at the quarterly numbers going forward.

So it will naturally fluctuate from quarter to quarter. But it is a pretty stable return on capital employed over the next three years, so there's no profiling of that. It seems to -- the decline in return on capital deployed has turned. So then it's approximately on the same level.

Okay, thank you.

Guy Baber from Simmons.

You guys mentioned your commitment to portfolio optimization and divestments a number of times during the presentation. But you have no divestiture targets, though. So I was just hoping you could once again share with us the framework as to what drives the divestment decisions. Do you believe you need to further optimize geographically or are you by segment exposure?

And then also do your return on capital employed targets make it less likely for some of your non-core assets to be divested if those sales would be ROCE dilutive? Just trying to get a better sense of how material divestments could be and what specific criteria you guys use to screen them.

I think my starting point is that we don't have to make divestments. You have seen the balance sheet. And so we do it if we feel it's value-creating for Statoil. And as we discussed earlier in the call, we are not prepared to give divestment targets for individual years or for periods. In my opinion and in my experience that drive you towards having to make a transaction before that, in that time. And I don't think that's value-creating.

So we tried to assess the strategic profile of our portfolio, the investment levels, the profitability, the CapEx profile. And of course also the buyer universe and whether we feel that we can get the right value for the asset. And of course, I think when it goes to productization of projects, not necessarily related to your question, but on a general basis it is clear that the framework that we have put out to you today -- there are projects that will not qualify and has not qualified.

And then we have to think about do we delay it, do we rework the concept so it's more profitable? Or is it better or more value-creating to sell it? I think you understand that there is not an exact science into this, but we have to assess all of these factors.

Mehdi Ennebati from Societe Generale.

I will ask one question. You had a lot of success regarding explorations in [2010]. Now I wanted to know if you are thinking about taking the opportunity to farm out some of your recent discoveries and use the cash to invest or enter into promising areas with potentially high-return projects where you are currently not, such as, for example, onshore East Africa, Uganda, Kenya or any other area.

Or do you think that -- do you stick to the fact that you have enough to do by selecting your own discoveries to develop? And are you interested in doing that?

And if I can ask just a very, very quick second question regarding [in Amanas] in Algeria, it seems production started to ramp up in Q4 versus the last three quarters. And the Algerian Minister of Oil announced to the press that production will come back together relatively quickly in the weeks to come. Just would like to know if you already took this into account in your 2% production growth guidance for 2014.

If I understood the question right, the way we think about it in Statoil, that if you have discovered a resource you can think about that as a resource you have. And you have to put that through the same sort of methodology that we just spoke about, that we have to make sure that -- are we the right company to develop this resource or should we divest it or farm out?

Tim will speak, talk more about this later, and Tim and management team has a very, very active view on their portfolio and do farm-in and farm-outs all the time to optimize value and activity plans. And I think you will see him be active also moving forward, perhaps more on the farming out than farming in, given the portfolio we have.

But there is also a time perspective here, and you have seen that the expiration team has been in Statoil have been quite active in building acreage position also for the longer-term. We have taken positions as you have seen in Brazil, in Norway, in Australia, to name a few, and New Zealand -- which has a much longer term perspective but falls very well in line with the strategic framework that Tim and his team has developed with early access, higher risks and bigger positions. In order to discover something big, Tim tells me that you have to drill on a prospect that is big.

Oh, sorry, on Nigeria we have repatriated our people to Herzegovina and part of (inaudible) probably the rest over the next few weeks. It will take some more time in Amanas. We cannot disclose any date today on that. There is not full production in Amanas and we have factored that into our guiding moving forward.

All right, thank you very much.

Thank you. And that will conclude the Q&A session for now. And we will break for lunch. Lunch will be served right outside of this room and we will start the next session again at 1:45 PM. And we will try to start precisely on time due to -- in consideration for our webcast audience. Have a nice lunch.

Thank you much, Hilde. Good afternoon, everyone. Good to see you all. Already a lot has been said about exploration, so I will do my very best over the next 20 minutes to keep you awake after lunch. I'd like to share with you Statoil's exploration success story; and then, of course, to talk more about how we continue to deliver world-class exploration performance going forward.

So, let me start with our 2013 exploration results. This slide speaks for itself. In 2013, we were the leading explorer. We found more conventional oil and gas than any other company, and we also made the single-largest oil discovery in the Bay du Nord in the East Coast of Canada. In total, we found 1.25 billion barrels; 1.15 billion barrels according to IHS, and this IHS statistic on the screen here. And that's almost 10% of what the entire industry found in 2013.

2013 was, without any doubt, great exploration year, and I would say -- hasten to add, another great exploration year. We've now discovered more than 1 billion barrels of oil equivalents each of the last three years, and added 3.9 billion barrels of new resources in total, and made 11 high-impact discoveries. That is, discoveries more than 250 million barrels on a 100% basis, or 100 million barrels net to Statoil. And I think you'll agree that is consistent, world-class performance.

We've also opened up six new plays in four different basins, and you should all know what that means: significant follow-up potential. So all of this has been achieved for less than $3 a barrel. In the same period, we have replenished the folio with attractive acreage in Norway, Gulf of Mexico, Angola, Canada, Brazil, Russia, New Zealand, and Australia, to mention the most important. In sum, we have an opportunity-rich, geographically diversified, and oily portfolio.

In my judgment, our exploration portfolio has never been stronger. We've created optionality for the Company and we have significant follow-up potential in Norway, Tanzania, Brazil, and Canada. And we have a portfolio -- I know most of our competitors envy us. But let me now show you that our exploration success delivers value, too.

Big volumes are usually better from a value perspective. And as you can see from this slide, our high-impact discoveries have even lower CapEx per barrel and higher rate of return than our sanctioned portfolio; which, of course, is a robust and attractive portfolio in itself, as both Helge and Torgrim have shown. This proves that our strategy of accessing and drilling more high-impact opportunities creates significant value. That's confirmed by WoodMac -- if you look at the chart on the right-hand side, where they rank value creation from exploration for the period 2010 to 2012.

That value creation stems from a mix of the high-impact discoveries I've already mentioned, and high-value barrels from near field discoveries, especially in Norway. Note that the 2013 discoveries are not included there yet. But, of course, I expect that the positive trend will continue, with the likes of the Bay du Nord high-impact discovery. So, my main point, looking back, is that we have successfully delivered on both volume and value dimensions the last 3 to 4 years.

So now I'll share with you how we intend to sustain such leading exploration performance. I believe the recipe for continued success is threefold: high-grading, prioritization, and capital discipline. First, the high-grading. We've gone from 2 to 6 core exploration areas in three years. And we'll continue to deepen with more quality acreage, and following up on our successes to take out the full potential in those areas. We have, and will continue, a selective access strategy to replenish the portfolio.

We will focus on large-scale, quality acreage positions with the potential to become the new core area. An example is our entry into Russia, where we are now progressing well with the onshore and offshore joint ventures with Rosneft. Prioritization -- true, global prioritization is probably the most important ingredient. We prioritize basins; we prioritize prospects; we prioritize wells; we prioritize rigs; and we prioritize seismic.

As an example -- one of many -- we've redeployed the Discoverer Americas drillship from Gulf of Mexico, first to Mozambique and then to Tanzania, to follow up on our success there.

Then I'd like to tell you a story about acceleration, about accelerating one of our best opportunities. In March last year, when I was visiting with our exploration team in Calgary, they told me that they had a better prospect to drill than what was planned. In the space of two weeks, we had changed our plans and secured partner and authority approval to drill Bay du Nord. This was definitely one of the best decisions I've ever made, and it demonstrates our ability to act swiftly and decisively when we see a good opportunity. And now we're looking at the possibility of accelerating the development of this high-impact discovery.

We also will continue to churn the portfolio so only the best opportunities stay. We've recently withdrawn from the Beaufort Sea, and dropped the Blocks at 47 in Surinam. We strive to mitigate our risk and cost exposure in high-risk and cost opportunities, and that's why we farmed down twice in Mozambique before drilling. Another good call.

I'm not going to spend a lot of time on improved efficiency. Margareth will revert on that in more detail. Needless to say, our well efficiency is extremely important, as around 60% of our exploration spend is on wells. Exploration is, and will be, measured on how much value we create for every barrel we find; and, as such, we will prioritize the projects with the best value proposition when selecting both drilling candidates and new access.

So, now I've given you what I believe the recipe for further success is. Let me turn to our exploration strategy, which you should all be familiar with. As Helge has already said, our strategy stays firm. It has brought us consistent success and three main pillars stand firm, as I said. Three years ago, we really only had two core exploration areas, or portfolios, if you like: Norway and the Gulf of Mexico. Now we've added additional, high-quality portfolios in Angola, Tanzania, Brazil, and East Coast Canada, giving us six in total. And as I say, we will continue to deepen our position in these core areas in order to exploit the full potential, just like we've done in Norway for many years.

The second pillar is about high-impact wells. And this may sound pretty simple and maybe even stupid, but I think it was as simple and stupid as this -- once we started thinking bigger, we were on the right road to success. If you don't think big, you don't access big, you don't drill big, and you don't find big. Drilling enough high-impact wells has been the key contributor to our volume success. And in 2013 alone, high-impact wells contributed 80% of the volumes discovered. In 2014, we'll be drilling high-impact wells in six different basins, six different countries.

Early access at scale is about replenishing the portfolio. And we intend to do this by selecting opportunities that represent timely, low-cost options for the future. Our sound regional and geological understanding of this core is, of course, the basis for our selective access approach. I have a fantastic and highly competent exploration team who has screened the globe for the best opportunities for many years. Now we are reaping the rewards of all their persistent efforts.

So let's now take a closer look at the potential in our plans for the six core areas. And I'll start in Norway. I'm going to start in the far north in the Barents Sea. Statoil is breaking new ground in the Barents. We participated in two play openers -- the Skrugard discovery in the Johan Castberg area in 2011, and the Wisting discovery in the Hoop area in 2013. In the Hoop area, we will drill Apollo and Atlantis this year. These structures are in the same geological setting as the Wisting play opener, and this obviously increases the likelihood of success.

In the Johan Castberg area, we are currently drilling a prospect called Kramsno, and we will follow up with a new prospect called Drivis. We are also preparing for the 23rd concession round, and a group comprised of 17 oil and gas companies has established a project, operated by Statoil, for joint seismic acquisition in the southeastern Barents Sea this summer. And that joint effort should be extremely cost-efficient.

So, staying in Norway, but moving further south to the prolific Norwegian Sea and North Sea, let me draw your attention to our near field exploration efforts. Over the last three years, we have proven approximately 250 million barrels of timely, highly valuable resources, and made 15 near field discoveries with a success rate of 81%. And in the Norwegian Sea alone, Statoil has made three high-value, near field discoveries close to Asgard, Norne, and Njord fields last fall.

We will maximize the value of these discoveries, either by direct tie-ins to the platforms and to the host installations, or by fast-tracking them. We have extended the reach for fast-track, which means that an increased number of discoveries can now become fast-track candidates. And Margareth will tell you more about this in her presentation. We will keep a similar near field exploration drilling activity level during the next three years, due to the attractive value proposition and the high chance of success.

So now I want to take you across the Atlantic Ocean to the Gulf of Mexico, another highly prolific basin, that one where we as operator are still striving to make our first operated oil discovery. The [GoM] continues to deliver high-value barrels, as demonstrated by the recent discoveries made by BP and Chevron. Over the last year, we have worked extremely hard to further high-grade our portfolio in this prolific oil basin. And right now, our top three prospects in the Gulf of Mexico are Martin, Perseus, and Monument; and all of these ranked very highly in our global prospect portfolio.

In 2014, we will drill Martin, which is one of our top prospects in terms of volume and value. Martin is right in the heart of the Mississippi Canyon, a very prolific area of the Gulf of Mexico, as you can see from the slide behind me. Perseus will be drilled after Martin, assuming all the required approvals and permits are in order. The value proposition for significant oil discoveries in the GoM remains attractive, and it is one of the main drivers for continued exploration in GoM. But we will only drill the very best prospects; but, personally, I believe we have the competence needed to succeed here as we have elsewhere.

So let's continue the journey, this time eastwards to the Indian Ocean; more specifically, to Tanzania, where we had our breakthrough gas discovery, Zafarani, in 2012. Since then, we've had 100% success in Tanzania, and the area has been elevated to an exploration core area in a very short period of time.

Following the Zafarani success, it was all hands on deck to quickly mature and drill new prospects and to acquire 3D over the entire license. Less than two years later, we've drilled an additional five wells, and we are currently production-testing the Zafarani 2 appraisal well. That was made possible, as I said earlier, by redeploying the Discoverer Americas drillship from Gulf of Mexico to East Africa. The latest discovery, made in the fourth quarter, the Mronge, brings our in-place gas proven guess volumes in Block 2 to somewhere between 17 Tcf and 20 Tcf in place. And that provides the foundation for the major gas development.

In addition, and as you should be able to see from the chart in the middle of the slide here, or the image on the middle of the slide here, we have identified significant upside potential. In the central area of the block, where we've made all the discovery so far, we have mapped five low- to medium-risk prospects which we believe hold significant potential, somewhere in the range of an additional 5 Tcf to 15 Tcf. Following the ongoing drill stem tests, we will drill a new appraisal well on Zafarani before continuing our exploration program on the Piri prospect.

The same year, 2012, as we made the Zafarani discovery, we also participated in the Pao pre-salt discovery in the outer Campos Basin in Brazil. So let's now see how we are progressing there in Brazil, one of the true exploration hotspots the last decade. Together with Petrobras and the operator, Repsol, we have recently embarked on an extensive appraisal program of Pao. Today, however, I'd like to focus on the Espirito Santo Basin to the north, another emerging oil play in Brazil.

We are now well positioned in this basin, where we acquired six new blocks in the 11th concession round last year. We believe that a successful oil play is proven and extends from the multiple discoveries with [are made] into our new blocks. We are already part of the Indra discovery in the block BMES 32. That discovery has been appraised by Petrobras in the license to the north, and a 200-meter oil column was announced. A second oil discovery, Sao Bernardo, has been made just to the north of Indra.

We are very positive about our new acreage in Espirito Santo. We're operators in four blocks, partner in two others. We will operate a very large 3D seismic data covering all of these blocks, and that will commence shortly. Our plan is to mature the prospect in three and to start drilling in 2016. And we have a commitment across the six blocks to drill 10 wells, of which -- stat four -- Statoil will be operating.

The last few years, Brazil has been mostly -- not only, but mostly -- about pre-salt. We now know that a similar play has been proven on the other side of the Atlantic. So let's now move to Angola, where we will shortly be in testing a very large Kwanza pre-salt portfolio. Statoil operates blocks 38 and 39, and we are partner on three other pre-salt blocks -- 40, 25, and 22. The latter is adjacent to Block 21, where Cobalt has made several pre-salt discoveries recently. The pre-salt play is now proven in Angola, and we believe this will extend into one or more of our blocks.

Dilolo is the first high-impact prospect to be drilled by Statoil, and you can expect a start up there in the end of second quarter this year. As you hopefully can see from the image, this is a mega four-way closure. It could be in excess of 1000 square kilometers, and it's one of the largest closures I've seen in my career. By comparison, Libra, in Brazil, was mapped as a 730 square kilometer closure before drilling, according to AMP.

However, multiple wells will be needed to fully test the Dilolo closure, and one well will not provide all the answers. You can expect news from Dilolo late 2014 or early in 2015.

Over the next 2 to 3 years, we will participate in eight commitment wells across the five blocks in which we participate. And while uncertainty remains, the potential for making one or more very large oil discoveries is certainly there. Expectations are high, and all eyes will be on Kwanza in 2014.

That was not the case with East Coast Canada, where we made groundbreaking discoveries in 2013. So, let me tell you more about that. As already said and others, at the year-end, Bay du Nord was the world's largest oil discovery in 2013. Statoil has consistently worked the Flemish Pass -- which is the name of the basin where the Bay du Nord was found -- for a number of years. We have built, as you can see, a very substantial acreage position with significant follow-up potential, and we are the dominant operator. We are, in fact, the only operator in the Flemish Pass.

We have identified several structures similar in size to the Bay du Nord discovery, some with impact potential. Our efforts now will be focused on proving up that potential at the same time as we plan to start advancing Bay du Nord towards a development decision.

We're planning to start a new drilling program in the fall of 2014. I'm very happy about that. And we have earmarked a rig from Norway to move to Canada. And we've also agreed with our partner, Husky, on the first two well targets. We plan to acquire 1900 square kilometers of 3D seismic in the Bay du Nord area, starting in late spring.

This discovery, and the neighboring discoveries and surrounding prospectivity, represent an opportunity for high-value barrels. Bay du Nord is located in moderate water depths. Reservoir and oil quality are good, and development of production technologies are already largely proven. Statoil has already formed a multidisciplinary task force to assess the feasibility of an accelerated development of the Bay du Nord discovery. I have to say, I'm very excited by the recent of elements in the Flemish Pass. I'm also very confident that there is more, potentially much more, to come.

So, let me sum up. Throughout my presentation, I've highlighted Statoil's successful exploration efforts, and that we will continue to follow our successful exploration strategy. Exploration will be the primary growth engine for Statoil, and 2014 has the potential to be yet another good exploration year.

I'd like to leave you with three messages. One, exploration has delivered consistent, world-class performance three years in a row. We have a deep, rich, and balanced portfolio centered around six core exploration areas. And we have a solid foundation for strong deliveries in 2014 to 2016.

When it comes to 2014, we will continue to high-grade the portfolio and to have strong capital discipline. We will maintain our exploration spend at around $3.5 billion, and we will spend almost exactly the same amount on seismic and wells as we did in 2013.

We expect to complete 50 wells. And out of these, we will drill high-impact wells in six different basins. Our P90/P10 resource estimate for 2014 is 400 million or 1500 million -- or 1.5 billion barrels of oil equivalents. I'm confident that Statoil will deliver leading exploration results in 2014, and that we will create even more optionality; and, thereby, value for our shareholders.

Thank you very much for your attention today.

I'd now like to give the word to Margareth -- Margareth Ovrum, Executive Vice President for Technology, Projects, and Drilling. Thank you.

Our core messages on why and how we are adjusting records. This is about high-value growth, improved efficiency and capital distribution. And Tim has just explained how we are doing to source this growth.

And now, as usual, I have to do the work. Eh?

I have three messages for you. First, we're performing well on project and well execution and we will continue to do. Secondly, we are a technology-driven upstream company but we increasingly apply manufacturing-based execution to reduce costs and improve margins. Thirdly, we commit to CapEx savings and CapEx reducing efforts delivering an aggregated CapEx savings of $1.7 billion net to Statoil between 2014 and 2016 of which $1 billion is for 2016.

These measures are part of an extensive improvement program where we are addressing CapEx, OpEx, and production efficiency. And as Torgrim explained, the $1.7 billion is part of the $5 billion in reduced CapEx from 2014 to 2016.

So, let's start with our project performance and I am proud to present the progress we have made. We have a strong improvement on the [HSC] (see slide presentation) result which enables us really to focus on what is important -- operational excellence. Of a project organization on facility delivered a serious incident frequency of 0.3 in 2013. And this is the best in the Company. And I lead the way and prove it is possible to continue the extraordinary trend.

Moving to costs, the total cost of the project portfolio, both the facilities side as well as the drilling side versus sanctioned estimates has shown a strong improvement since 2009. And over the last three years, we have delivered on cost or below. And we intend to deliver the best level of predictability for 2014 and onwards.

And we're delivering on schedule. Actually, we are delivering one month ahead of plan. Equally, drilling and well show strong results despite high pressure in the market. This is highly important, due to the agency exposure but also the significant part of our CapEx spend.

On the HSC, drilling and well delivered a serious incident frequency of 0.7 and it improved from 1.8 the year before but with no serious well control incidents in almost four years. We managed this despite drilling a record number of wells. In 2013, we delivered 120 offshore wells, an increase of more than 60% from year before. And actually, we delivered in addition 29 drainage points to our multilateral wells where we are world-leading in applying that technology and these add significant high-value barrels.

Moving forward, we will consider the right number of wells to create capital affectability through optimal reutilization and capacity.

In parallel and in spite of accelerating market costs, we have reduced costs per offshore well on the Norwegian Continental shelf. We work systematically to continue the downward trend on costs and I will come back to this in more detail.

In June I met a lot of you and you asked for benchmarking. And I'm happy you did. You know, I love to compete but not as much as I hate to lose. I look at this. In November 2013, results from the independent project analysis demonstrates strong project performance for Statoil. We are on or above industry average on all except one benchmark. And we also observed a very positive trend.

In 2010, four of the nine benchmarks were on or above industry average. Today, the number is eight. And a level of maturity reflected in the front-end loading benchmark is solid for all these -- reservoir, well, and facility.

And that is, of course, a prerequisite for a robust operation and a robust execution. But this doesn't mean that we have one and that I am satisfied.

We still have too many changes and that is clearly an area for improvement in Statoil. Until now, we have compensated by very good execution. Through systematic work we deliver our projects with high predictability and competitive development solutions. Currently we are moving in a very positive direction the opposite of the industry. But for sure, our peers will improve and so must we.

In short, we have delivered, as promised, competitively and without major project failures.

Moving forward, three elements are key for me. First of all is to continue to extract learnings from historical, ongoing projects. Then no exceptions to changes in the design. And thirdly, an increased degree of standardization.

So, how do we work with execution to systematically support predictability, competitiveness, and reduce costs? The overall status on time, cost, and quality in our large and more complex project portfolio is good.

Gudrun will start production in Q1 according to the plan, with a facility cost significantly below sanctioned estimates. And right now we are completing the first well and we are just about to perforate. My real plan, and that was my plan, was to deliver two months ahead. Continuous storms wrecked and it obviously annoys me. Annoys me.

Valemon is on track to deliver. So is my precious Oseberg subsea compression project, the enormous subsea structure, which is already installed on the sea floor. And the compressor is now being tested in a very large pit at [Corster].

Second, on the portfolio level, we obtained very attractive prices with our Asian project like the Gina Krog, the Mariner, and (inaudible). The common denominator for the industry's underperformance on time, costs, and quality is largely related to [immature] engineering. To avoid knock-on effects to procurement construction and hook-up, we will continue to ensure one early experience transferred from peers and our own projects; and two, early mitigation of emerging challenges and hands-on interfaces with our suppliers. This is hard work every, every single day.

These measures have been applied for Valemon and Gudrun and will be applied for both Mariner, Aasta Hansteen, and Gina Krog. And they are approaching construction in 2014, according to plan.

Then to our drive for cost and efficiency improvements in our early phase projects, the bar for treating projects on a tailor-made basis has been raised. Johan Castberg and Johan Sverdrup are both high-impact projects approaching concept selection. And having said -- and we pursue for these projects, we pursue standardized and cost-effective solutions.

Having said that, technology will also be focal to realize significant value upside for these projects.

And you know the average recovery rate on the Norwegian Continental Shelf for Statoil field is 50%. We have an ambition to reach to 60% and we have increased it by 20% on average since the [TDO] -- the projects.

The world average is as low as 35%. And on Johan Sverdrup we believe we, with our extensive tool technology toolbox, can realize the best recovery rates on the NCS up to 70% over the field lifetime.

And now, now we are talking.

On Castberg, we work hard to increase our business including evaluating costs, reducing technologies such as moving from horizontal X-mas tree to vertical Christmas tree. And that may also exemplify how we in Tanzania and, in the East Coast Canada, aggressively pursue cost and time-efficient solutions and the use of our technology. For the Tanzania development, we work with our partners to evaluate a subsea to shore solution. And the 2,600 meters water depth we think we can apply standard subsea deepwater solution as well as extensively and highly advanced we use our subsea technology and [comfort us] we develop further the (inaudible) field and the [Snohvit] field.

Similarly, we are now assessing a successful development in the frontier of the Bay du Nord discovery, focusing on a solution that will bring us to oil faster than previous projects of that side in the offshore Newfoundland.

And following our increasingly more efficient development operation on MCE and NCS, we will reallocate, as Tim said, a rig from NCS to accelerate the appraisal of that discovery. And this is exciting. And even I am being labeled, in Norway, I am being labeled a technology babe. Maybe you don't understand it, but I must face the beauty of our emerging manufacturing-based solutions.

And the Norwegian (inaudible) projects has demonstrated Statoil's ability to adapt and rapidly expand standardized solutions. The results on the simplified execution although for the near-field development and discoveries are substantial. And as you can see on this slide, six projects already onstream with six more to come peaking close to 100,000 barrels per day in late 2014.

The portfolio is very robust with low breakevens and high returns. The execution risk is low with lead times down to 32 months.

Continued success of teams near field exploration and also development of technology to further extend the reach for these fast-track projects will ensure fast-track activity going forward. So I am highly dependent on you, team, but you always deliver. So, we will succeed on that.

Our ambition is certainly to expand our offshore manufacturing segment.

Now to another segment we really take pride in, the onshore US. The total well CapEx may comprise up to 90% of the total US onshore development. So any improvement will strongly impact the value and the margins. Statoil US onshore drilling performance is illustrated by the time and the cost per well in our three assets.

The overall trend is strong, backed by 30% to 50% reduced drilling time and 25% to 50% reduced cost per well from early 2012 to end of 2013, in line with or better than our peers.

The main reason for these savings is what we refer to as our perfect well approach, which is a systematic deconstruction of best practices within all segments of the well construction and subsequent drive towards improvements in simplification on each segment. We expect to continue these improvements and we aim for another 15% reduction on the total well costs by 2015. And there may be some further upside from new technology development.

The perfect well approach is already under implementation on the Norwegian Continental shelf and for our offshore drilling teams. And we're taking learnings from onshore.

This picture and the fast-track success provides me with confidence in Statoil's ability to deliver highly competitive results. And we have that faster than I think you and even I would have anticipated a few years back.

On execution, let me summarize. Our project and well performance is strong and competitive. We trust our ability to sustain this performance. By manufacturing we will pave the way for a step change in cost efficiency.

We need more on the cost reduction. You heard my boss. He is really demanding and so am I. And I will now provide you with more insight into cost reduction and efficiency in [HFUs].

As referred to by Helge, Statoil has launched an extensive efficiency improvement program. The purpose is, of course, to improve the free cash flow by addressing CapEx, OpEx and production efficiency. And I would like to detail out the CapEx efficiency commitments and measures which will deliver an aggregated savings of $1.7 billion between 2014 and 2016 of which $1 billion in 2016 and a sustained level going forward.

Note that we see upsides to these numbers.

For CapEx reducing measures, the FX will be primarily be extracted within well delivery, field development, and modifications. So how to my commitment? This is a toolbox of [unrisked] efficiency improvements, opportunities, some delivered and some which we work on. Some of these succeed and some might fail; still in total, they are sufficient to realize our commitment.

I will revert to our standardization efforts in more detail on the next slide. Within field development of modification, we expect to deliver Gudrun with the facility costs 12% below our sanctioned estimate mainly due to the reduced scope. We have simplified technical requirements and, not at least, we have optimized our procurement processes.

Moving forward, we have a firm ambition to reduce engineering hours per ton by 10% to 20%; by further simplifying our technical requirements; to increase standardization; increase quality and precision; and do it right the first time. We will also reduce our NCS modification CapEx by 20% saving equity CapEx more than $100 million each year. And we will actively pursue leaner concept for our field development projects.

On the offshore well delivery, we have leverage learning from repetitive deliveries to increase efficiency. For instance, on the Troll Field. And you know, on the Troll Field we have the most sophisticated and technology-advanced multilateral wells in all of our Norwegian Continental shelf. Still we have made them as standard as well so we do it again and again and again, and we really get very good efficiency out of that. So we have reduced construction time for the Troll multilaterals with 15% over the last years.

Going forward, we have an ambition to reduce average offshore well construction time by 25% and realize cost savings of 10% to 20% per well by applying the perfect well approach, learning from onshore US, and standardized concepts. In addition, more efficient well deliveries create flexibility and as I mentioned, we will reallocate one rig now from NCS to Bay du Nord for appraisal, really.

As demonstrated, our US onshore team has a strong operational track record of competitive well delivery. We see the potential for additional 15% in total well CapEx savings toward 2016 applying the perfect well and also more deployment of technology.

Now to standardization. And this is my stairway to heaven.

Statoil pursues step by step, a systematic approach to mature technology, mature new technology as solid skill for [ours]. We are now embarking on a similar systematic standardization journey. Standardization is as you know, it's not new for Statoil. We had the [construct] project; we have the multilateral well for the Troll; we have the old category D and day rigs representing standardization in our rig portfolio; and standardized floating storage units for Mariner and for [hybrid] as good examples.

We see more upside going forward. Note though, as these are examples and they are not additive. We will apply the standardization approach on our large upcoming developments; use of standard modules and [accusements] for Johan Sverdrup and Johan Castberg could hold a CapEx savings of a potential $150 million to $300 million for the licenses. Concept standardization could deliver 8% to 10% in savings on facility costs by reduced engineering paid and this is in fact, some proof we have of a copy from Mariner to [Brekke].

Standardized vertical X-mas trees for Johan Sverdrup and Johan Castberg have the potential to save $0.8 billion to $1 billion over the field lifetime -- both CapEx and OpEx.

Standardized production wells contribute to realize well cost reduction of 10% to 20%. And a recent contract on NCS, based on standardized components, shows a potential reduction of 20% on costs.

We have more developments now in the shallow water and I asked my people to develop a lean concept to compete with subsea. And this is a new low-cost wellhead platform that I call the subsea on slim legs. We have completed a feasibility study and are now evaluating implementation in various fields.

For example, in near field discoveries at the (inaudible) and Oseberg area. Potential savings from this amount concept range between 20% to 30% depends on the size of the field and that is compared to a subsea solution.

To sum up, we will develop our standardization capabilities like we have successfully managed our technology developments in the past. To me, the examples and opportunities in this slide and the previous one provide comfort in committing to these CapEx savings.

And let me end where I started. We deliver on our promises and we will continue to do. We adapt our execution model to reduce costs and improve margins. We commit to an extensive improvement program delivering an aggregated $1.7 billion in reduced CapEx.

Now you see what I meant by doing all the work. Thank you.

Thank you very much Margareth. We'll now open up for questions to both Margareth and Tim. And I'll ask Tim to join Margareth up here on the stage. We'll again start with questions from the audience.

And I see one over there. Please, if you could pass the microphone left?

Thank you. It's Brendan Moore from Bank of Montreal. Just a couple of questions, more for Tim, and congratulations. Just firstly, in Tanzania, if you can give us any insights into any drilling or expectations for the outboard part of your block that you didn't discuss?

And just secondly, just in terms of drilling that we're going to be following in Kwanza Basin, if you can just make any comments around the potential -- or the risk, I should say, for gas on your exposure?

And then just lastly, obviously you've been very successful -- more, also, for what you haven't drilled. And if you can just talk through your dropping of your exposure to Surinam and being out of the transform margin?

Okay. Very briefly on Tanzania, the prospectivity in the outboard part of the Block 2 in Tanzania doesn't look that great, so we don't have any firm drilling plans there. When it comes to Kwanza, I think one of the uncertainties there is, of course, what kind of -- is obviously whether we find hydrocarbons, but also what size of hydrocarbons we'll find.

We've seen that so far what's been proven by cobalt seems to be quite similar to the highly volatile system which we have in the Pao discovery in the outer Campos. So we'll just have to see, I guess, on that one. There is both oil and gas, obviously, in the basin there.

When it comes to Surinam, it's a pretty conscious decision by ourselves to move away from the conjugate merger. We were also quickly in Ghana. We drilled one high-impact prospect. It was the only one that was there. It was dry. We moved out again.

We've done the same with Surinam. We probably confused you all by going into another license in Surinam that we had basically committed before we pulled out from the other one.

John first. Yes, please, go ahead.

Two questions. The first one: I'm conscious you're going to be somewhat critical of my mathematics or my understanding of statistics. But if I take the sort of midpoint of your P15, P10, and P90 numbers that you are drilling for, you're clearly going to, A, if you come in somewhere close to that, you're going to be adding resources well ahead of the production of the Company.

And I guess that raises the question at some point: rather than the strategy I think you have taken so far, which is de-risking and taking partners on in the spending bit of it, whether you start to look to monetize actual resources that you have discovered in the same way as I think other very big exploration-oriented companies kind of fit into the strategy. I just wonder whether you could talk a little about that?

And then the second is just to go onto US onshore. You talked about efficiencies in drilling, but as I understand it -- understood it from a couple of questions I think I have asked in the past is, you have a very different strategy as well in terms of the wells you are trying to drill, I think particularly in the Bakken, where I think you are trying to get better recovery rates or URs, as I understand it. So the efficiency of the drilling or what you drill is better than your competition and not just the cost of drilling that well. Is it possible you could talk about that if that's true? Thanks.

Just to start on the resources, your observation is correct. Another statistic for you to like is that over the last three years, we've delivered considerably more than our P50 estimates. That doesn't necessarily mean it's going to continue.

But in terms of monetizing these -- I think as Helga mentioned earlier on -- sort of if it fits, and we can realize good value for parts, although I could see also in some of our discoveries that something we might consider. Traditionally we farm down that predrill if we think it's too risky and too costly. But as I say, we have an open mind to doing that also post discovery.

Okay, what I showed was the drilling and drilling operation -- the efficiency on the cost side and on the time side. And, of course, we also have an ambition to reduce the total CapEx further. And as you probably know that the recovery rate in these areas in the shale oil area is normally much lower than we are used to.

And I think that we -- as a company we work very hard to improve the recovery rate, also, in Bakken. And I think we have a very comprehensive toolbox, which we will also utilize in -- on unconventional in the US.

And then Michael is next.

Thanks. It's Michael Alsford from Citi again. Two questions, if I could, on two specific projects. Firstly, on Johan Castberg, one of the reasons for, perhaps, the delay to that project other than the tax was around resources. Given the recent well results that you have drilled in the area, could you maybe give an update as to whether that is still one of the key challenges? Or do you think you have sufficient resources now to push ahead with that project?

And then just secondly on Johan Sverdrup, while you might not be happy to give a CapEx number or production profile today, could you maybe talk a bit more broadly about what are the key decisions that you're thinking about right now? What are the key issues, perhaps, before we get to the projects of scoping? And when might that be? Thanks.

Maybe I'll start on Johan Castberg, and then Margareth can continue. On the resource estimates -- when it comes to the two main discoveries, then our resource estimates sort of remain the same.

As I say, the results of the -- is two or three? -- three prospects which we drilled up until now being a bit mixed. We did make one oil discovery on the Skavl. We are currently drilling prospects on Kramsno, and then we will drill Drivis. And I think until we have drilled those two prospects, then I think the jury is a little bit out in terms of the total resource picture, and then whether what we have is enough already, Margareth is probably better suited to answer than me.

On the Johan Castberg, we are -- as it was mentioned, we work on both the resource side as well as on the cost side. And of course we need some solutions on the tax side, in addition.

On the cost side, I would say we are trying -- we have a base case, which is the transportation to shore. We tried to reduce the CapEx, and we are working on that in a good manner. But of course, we also evaluate the different concepts, which could be even less costly; but of course it depends on how much flexibility you build into the concept. I can't give you any figures on that, of course, as you probably know.

Then on Johan Sverdrup, there will be, as Helga said earlier today, we will have -- early in 2014 we will have a concept selection. But of course everyone knows that we will have a field center, we will have four platforms, and we will have power from shore.

The key decisions: early this year, concept selection; in next year, beginning on next year, the sanction. And we hope the Parliament will assess it during the --

Spring session.

-- spring session in 2015. But also, we are working on the unitization, because we need to unitize it before the PDO. So we work on it -- will be a very good solution. And we will score high on the benchmark.

She always delivers, too.

Yes, Christine.

Sverdrup, it's very good oil. You can work with it. And we can utilize the whole technology portfolio we have to increase the recovery. So that will be very, very interesting to work with going forward.

It's Lydia Rainforth from Barclays again. Two questions, if I could. Firstly, could you just talk through a little bit in terms of more detail the reducing modification CapEx by 20%, and just how that actually happens, and over what sort of time frame?

And then, secondly, a lot of time was spent on the capital side. I'm just wondering if you could take us through more on the OpEx side -- how much you can try and take out of there, and where the main areas are you are looking at?

First of all, on the modifications side, we are prioritizing modifications; we are optimizing the concept; and we are making it leaner -- the work processes leaner than it is today. So that is what we are doing on the modifications side. We are -- also, Helga alluded to earlier today over technical requirements. We make them more simple. Then it was on the --.

It was on the OpEx part, wasn't it?

The OpEx part. I haven't said very much about the OpEx part today, but Torgrim mentioned in 2016, out of the 1.3, 0.3 is SG&A and OpEx. And OpEx is part of the efficiency program which I'm heading up, which cover both CapEx and OpEx as well as production efficiency.

And I'm not sure I will reveal anything at the time being, but we work on, maybe, our modification concept on our more maintenance concept. Can we do it in a more efficient way going forward?

You know, we are -- in all of our projects we have sensors to measure everything. Why can't we use that in another way, to -- based on condition-based monitoring and also maintenance? So I think one of the things we are really assessing is our maintenance concept, as an example. And to subsea aftermarket, I think we can get more out of that, just as a few examples.

I think we have a question on the list, or -- yes? If you could pass the microphone.

Christine Tiscareno from S&P. I just wanted to find out if you could give us, Margareth, an idea of -- that staircase on Page 12, on the Slide 12, that you have designed in which you show all the different standardization potentials that you hope to achieve. Is there -- could you give us, like, a time frame when you think it will be delivered?

And then you mentioned about your expenditures. Could you tell us what percent all these standardization and technology improvements -- what percentage of your expenditure is it? Is it 10%? 20%? We know that all of these are going to provide a lot of cost savings, but how much is it costing to provide that?

And then, lastly, I just wanted to know if all the sort of previous operational hiccups that you had were hiccups, or whether -- is that going to be business as usual because of all these things that you're carrying out? Trying to standardize production and putting in more subsea production, taking unmanned platforms. All these changes -- are they going to be creating problems as you adjust?

First of all, I hope you see that we have improved every single year now in some years. So we have had changes already, and we will continue to do so. And the industry -- all of you have a problem. It's too costly. We need to increase the margin.

So I think the whole organization -- we understand we need to do something. And it's the same with the suppliers. They also understand it also. So we need to work very hard together with the suppliers. And I think we are in a very good way to work with them now. I'm not afraid that will create some hiccups, because this is the way you need to work everyday. You need to improve from one day to the other.

But what is very important, and this was something I started with -- you need to do it right. You need to have your safety record in the right way. Because if you are, then you can work on improvements. If you have a lot of problems, it's impossible to work on the improvements, so safety is prioritized as number one.

But then, if you have that correct, then you can work on the improvement. And I think -- you know, some years ago -- I've been in this industry for many years. And from years ago, the fast-track projects, nobody believed that we would -- that that would be so successful. But we have done it, and I don't think we have had any big issues in that context.

Timewise -- you asked for the time on the standardization, and I haven't put up any figures on the timescale there, because -- first of all, as you know, we have some very big projects now. So if we should manage to standardize, we need to do it now. Because we can do it with Johan Castberg; we can do it with Johan Sverdrup. So we need -- some of these we need to do now. And our standardization on wells, for instance, we have already started. And all of the contracts going out now is based on standardization.

I said we had one contract on completion that was awarded a few months back. And we asked for standardized solutions, and then we managed to reduce the cost by almost 20%. So you need to use it on all the contracts. You need to use it and discuss with the suppliers. And you need to work on it on a daily basis. But Sverdrup and Castberg is our means to do it.

And we have Peter.

Hello. Peter Hutton from RBC. Two quick questions, both for Tim, if I could. On the Gulf of Mexico, you mentioned there were three prospects which rank highly in your global portfolio. You talk about Martin -- can you give us a little bit of flavor about Perseus and Monument and how they come in?

And then the second question on Angola: you have mentioned you're involved in eight wells, two of which you'll be operating. You're on two blocks. Your partner is on three blocks. You are operating on average one -- you're doing one well per block, others are doing twice as many. Might we expect a lot more drilling to come from yourselves?

I definitely hope so. And let me just explain that. And the commitments are fairly openly communicated, I think. On each of Block 38 and 39, we managed to negotiate down to one well commitment on each.

But as already mentioned, I think, on Angola: irrespective of the outcome of the first well, we almost certainly have to drill a second and third. And it has to do with the size of the structure and the potential variation in reservoir development across the structure, assuming we find reservoir, of course.

In the three other blocks, there are two well commitments on each. So the other block's operated by Total, Repsol, and BP. As I say, we probably won't manage to complete more than one well this year ourselves on Block 39. We will step across the 38 after that, or at least that's the plan.

And I think we probably, even if we had a discovery on Dilolo, we probably need a few months to sort of revisit that and have robust plans for moving forward. So eight commitment wells. I think our partners -- some of our partners are due to start up sort of about the same time as us, some a little bit later.

And when it comes to GoM, some variation on those prospects. I think the characteristics in terms of volume and value, and not least, chance of success are very similar. I don't really dare to say it, but at least they are, as I look at it, and the way we risk prospects, medium-risk prospects.

I probably shouldn't have said that, but that's just how they are. And I have to be open and honest about that. They are impact prospects. They're somewhat different. The stratigraphy is somewhat different on these. The Martin is a big four-way as we map that. and that's usually good in the Mississippi Canyon.

Could I add one thing on standardization? Is that okay?

Yes.

Because just for you to understand how important it is with standardization -- because you can reduce engineering, you can reduce the documents -- all the documents. You can reduce the risk. You can achieve economies of scale, because you can order many more equipment or modules or whatever. You can also have much more lean work processes.

But maybe the most important for me, it is really to -- it's all about changing the culture and how to adapt to our new DNA, which is really in margin, margin, margins. So I think standardization in itself is very, very important for all of us.

Oswald, please.

Thank you. Oswald Clint at Sanford Bernstein. Tim, maybe a question on the Barents Sea, which seems to have been a lot stronger last year. I think Lundin hit some pay in the Permian -- the deeper Permian.

Are you seeing any of that potential in any of your blocks in terms of the Barents? And then, Margareth, you said -- you talked a lot about standardization; and then you said, but technology adds the upside. So what's the risk that we go through the standardization, and then suddenly you get excited and want to throw science at these things, and costs get inflated once again?

Thanks, Oswald. Let me start on the Barents Sea. Our focus, our priorities are the Johan Castberg area and the Hoop Area. We've tried over the years unsuccessfully to do what Lundin have done, and that's make an oil discovery in the Permian -- in the classified Permian. So good luck to them on that.

As I say, it's a challenging play, but there are a lot of challenging plays in the Barents Sea, as you know, some of them related to uplift and burial; others related to -- it's extremely shallow, particularly in the Hoop area. I think suffice to say a lot of what's missing in the Barents Sea, some significant breakthroughs in terms of finding ore discoveries; but still, some way to go in terms of finding sort of robust, profitable development solutions for many of these discoveries.

I think that's something we will need to bear in mind. It's a rather special setting. It's not particularly difficult from a water depth point of view, from a pressure or temperature point of view. But the geology continues to play some tricks, sometimes, in all of these areas, actually. Margareth?

On technology and standardization, first of all, I think it's not contradictory. I had an example with lateral wells on the trough -- they are the most advanced. It's a lot of technology into it. But when you can standardize and utilize, or reuse, and reuse, and reuse other technology, then it will be very, very cost effective.

And for me, technology -- it will be still very, very important going forward, but I think we can push more on developing more cost-effective solutions and more focus on improving margins with our technology muscle. But it's not contradictory. I think it's -- develop technology, and you're able to use it.

Brandon, please.

Thank you. Brendan Moore from Bank of Montreal again. Just in terms of what we've heard this afternoon around capital efficiency, your focus on internal rates of return -- as much as you had great successes in Tanzania with the gas discoveries, where would the projects sit within the portfolio going forward? And if it will stay within the portfolio, would you be happy handing over operatorship, or do you believe LNG is a core competency of Statoil?

Maybe I'll start, and then Margareth can follow up. I think as we've alluded to here, the fundamental thing here is that we have to find enough gas first. We have to have sort of a robust resource base in order to be able to move forward with any project.

Should we move forward, as you know, it will be a huge investment. That's the characteristic of these kind of projects. The nice thing about them is that they tend to -- once they start producing, they tend to produce for many decades and generate a lot of cash.

I think we're in a pretty good place now. As I said, 17 Tcf to 20 Tcf in place are produced. We're currently testing the Lavani-2 well. We haven't released any results, but I'm allowed to say that the tests are very encouraging.

So I think there's no problem with the -- no problem whatsoever with the well deliveries, at least based on that test. We have a lot of upside potential, much more than we thought. It's a fabulous story, because going back, we almost didn't drill Lavani, and it's only because we applied very specialist seismic techniques that we convinced ourselves that we should drill it. And then, only then, did we recognize Lavani.

And only when we had success on Lavani did we see all the other stuff. And it can sound a bit sort of -- well, you know, so you -- it doesn't sound like we knew we were doing. But there's a huge concentration of gas here. And as I say, hopefully we can prove up somewhere between another 5 and 15. And we have a very solid basis in Block 2. And notwithstanding sort of together with BG and Ophir, who operate blocks 1, 2, and 4. And then when it comes to other challenges on Tanzania, maybe I leave it with you once more.

We have, of course, a very strong complementary partnership. And we are now in the process of working out the right joint venture consolidation. But meanwhile, we are the operator on the offshore part, which I alluded to or I elaborated a bit on. We prepared for a subsea-to-shore solution from very, very deep water to shore. So yes.

And then you asked a question about potential divestment. I think that was what you said. It wasn't exactly your words, I think.

We have a 65% equity in block 2. So I think the answer, as Helga answered earlier today, and as I answered previously about potentially farming down after discoveries: we have the optionality to do that. But at the same time, it's important to have materiality in these kind of projects going forward. But that needs to be balanced out with the risk and, obviously, the capital exposure, because it will be very costly to develop.

Okay, we'll take two questions from the telephone audience. And again, I'll have to ask you to please limit yourself to one question each.

First question comes from Teodor Nilsen from Swedbank. Please go ahead, Teodor.

Thank you and good afternoon. I think Tim saw (inaudible) on his Slide 5 -- that chart which showed CapEx for high-impact discoveries and CapEx for sanctioned discoveries. My question is if you remove Sverdrup for the high-impact discoveries, how would that chart have looked like?

The simple answer is that I don't know, but there are 10 of 11 high-impact discoveries. There's only Paleogene north-south which is not included in that chart. So otherwise, [Badenwood] is there. So that's really a very important contributor on that one. Pao is there, the Castberg is there. And then, actually, Tanzania is also there. So that in a way, you can say that would probably weigh up at this point in time this one for Johan Sverdrup.

So that's about as much detail as I can give you there. But I actually don't know the answer what it would look like if we took out Johan Sverdrup.

Last question before we wrap up comes from Oyvind Hagen from ABG Sundal Collier. Please go ahead, Oyvind.

Yes, thank you. On Johan Sverdrup, you are now mentioning that you're hoping to reach a recovery factor of close to 70%. Is that something that's already baked into your resource guidance that you have provided, or is that upside from the figures that you have published?

I haven't disclosed the figure for what we are putting into there, the concept selection -- and it's obviously not 70%. I just said from our experience from increasing the recovery rate from 32.50% on average, we -- and I know that if we work with that, this is very, very good oil. And the reservoir is good. And I believe that we can -- if we work with that over the lifetime, we can manage to get almost a 70% recovery rate.

Thank you.

Thank you very much. And we'll have to wrap up for today. And I will -- before we all leave, I will leave the floor to our CEO, Helge Lund, again to wrap it all up. Please, Helge.

Thank you, Hilda. And first of all thank you to all of you for being patient and being here for so many hours. We really appreciate this opportunity to talk about what we are trying to achieve in Statoil.

I will not go into detail in a detailed summary, but I think the message that we're trying to get across is, one, that we will pursue within the same strategic framework as we have done before. We will grow. We'll focus on upstream, and we'll use technology as an important part of leveraging value moving forward.

Secondly, we have been quite specific in the framework that we will deliver on over the next three years to provide you with more granularity and certainty around targets and objectives that we are working towards. And the key objective for us has been to identify a better balance, given the industry environment of providing growth, and at the same time deliver value -- both in our operations, but also in terms of servicing the shareholders directly.

We have not today paid a lot of attention to talking about the long-term. I think you see that we have a very strong resource base. We have very strong projects. We have told you that 40% of the CapEx actually from now into 2016 is actually for projects following after 2016. So my best assessment and judgment is that we have an approach and a resource base that will give the opportunity for growth and development much beyond the term over the next decade. And then we have to look at what speed do we develop these resources as the market and industry is developing.

Then our team, of course, will engage with you extensively over the next few weeks, and whenever you have questions or issues that you want to address, because there are many things that we cannot address in a short session like this. But I will not be available next week, because people make strategy happen. It's not made by a presentation, by executives.

So this morning, I sent a letter to 2,000 leaders in Statoil outlining what we intend to do over the next few years. I also had I think a 10 minutes webcast to all our employees in Statoil this morning to set out the new framework.

Next week, I will spend most of my time meeting with my people in town hall meetings in Oslo, in Stavanger, in Bergen. And I will meet with 600 leaders within Margareth's unit, because they are essential in order to deliver on the improvements that we have talked about today.

And the day after, I'll meet with Tim's team as well, to make sure that everyone understands, and we can discuss extensively in a broader way than we have been able to do so far, due to all the restrictions for a publicly-listed company, to make sure that we have full force behind the execution of the plan.

So I leave it with that. And again, thank you for your patience. Thank you for coming. And look forward to engage with you as we move forward. Thank you.