Equinor ASA (EQNR) 2016 Q4 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to Statoil's capital markets update on what I know is a very busy day for you all.

I'm very pleased that we will be able to run you through a series of presentations to look through our outlook over the next four years and also comment on the quarter results that you've seen presented this morning.

We'll be starting with presentations from Eldar Saetre, our CFO; Hans Jakob Hegge -- our CEO, sorry; Hans Jakob Hegge, our CFO; Margareth Ovrum, EVP for Technology, Projects and Development; and Torgrim Reitan, EVP for DP USA.

And I'm delighted that we have many members of the executive committee here, who will also be able to answer questions, both in the session itself and after the session more informally in the gathering area outside.

Safety is central to everything that we do in Statoil and with that in mind, I'd like to just read a very short announcement about safety, specifically for today.

(Conference Instructions)

So with that, I'd like to move directly into the capital markets update itself and I'd ask Eldar to join us on stage.

Thank you very much.

Thank you, Peter and good morning, everyone.

It's great to see you all.

This is the third time that I have the pleasure of welcoming you to our capital markets update here in London, but it is the first time I do so without looking back at yet another year of falling oil prices.

So let's make that a new tradition.

2016 was a challenging year for the industry, a fact also reflected in the fourth-quarter and full-year results for Statoil, which Hans Jakob, will get back to soon.

But there is also a saying that you should never waste a good crisis and I am proud to say that Statoil is emerging from this downturn as a stronger and much more competitive company.

We have reset our cost base, we have transformed our opportunity set and sharpened our strategy to be even more value-driven in everything that we do.

In short, we are now well positioned to capitalize on the opportunities of a world-class portfolio.

Last year we achieved a lot, but we also experienced the worst thinkable.

We had one contractor fatality during construction work in South Korea and on April 29, we lost 13 of our colleagues when a helicopter crashed on its way to Bergen.

For the year as a whole, our serious incident frequency came in as 0.8, which is an increase from the two previous years.

I'm not satisfied with this development.

Over many years, we have improved our safety results and now we have to get back on a positive front and we are fully committed to doing so.

We have already taken several steps to reinforce safety measures throughout our Company and it starts with me and all our leaders being crystal clear that safety of our people and the integrity of our assets and operations is and remains our top priority.

I take pride in the fact that we have a track record for delivering.

We promised $2.5 billion in yearly efficiency gains by the end of 2016.

We delivered $3.2 billion.

Since 2013 we have taken down operating costs and SG&A by 30%.

The breakeven price for what I like to call our next generation portfolio is now at $27 per barrel.

CapEx for 2016 came in at around $10 billion, well below the initially guided $13 billion, mainly due to increased efficiency, strict prioritization and also a very disciplined project management, project execution.

We sanctioned five new upstream projects last year and one in offshore wind and added a billion barrels of resources to this portfolio.

Looking then at the energy markets, we see still both the traditional commodities typicality, as well as longer-term structural changes.

The oil price is clearly showing signs of recovery on the back of expectations of a tighter market balance and also the recent OPEC agreement.

We expect oil prices to rise towards the level of $75 by 2020, but we also see significant uncertainty and continued volatility.

In addition to OPEC policies and their discipline, how much and how quickly the US onshore responds is one of the key questions obviously in this equation.

When it comes to natural gas, short-term prices are under some pressure.

Medium to longer term, however, we see a stronger gas market emerging.

Declining European production, indigenous production market gradually absorbing new LNG capacity and clearer policies, reflecting the need for natural gas to replace coal in power generation.

All these components afford this view and Jens will give you more detail, a more detailed outlook at our gas seminar in London in four weeks' time.

Looking then towards 2040, we see an energy system in transition.

New renewable energy is rapidly becoming more competitive and will continue to be the fastest-growing source for new power generation.

Technology and innovation are driving this development and we do not expect this to slow down, despite some uncertainties on international cooperation and of the global climate policy.

Still, in 2040, significant new capacity will be needed to meet demand for both oil and gas, regardless of which energy scenario you tend to believe in.

And the winners will be the producers that can produce and deliver at low cost and with low carbon emissions.

High value, low carbon is also the core of our sharpened strategy.

We will shape our portfolio, guided by a set of strategic, call it, principles.

The first one is about cash generation at all times.

To me, this downturn has truly demonstrated the value of resilient cash flows from our operations.

Efficient cash generating capacity also in a low-price environment is critical to secure a financially robust future.

You can call it the low-cost strategy for high value.

The last few years I've also underscored the importance of the Norwegian continental shelf to us in this respect.

As a large operator, we have been able to effectively implement significant cost improvements across the entire NCS portfolio, bringing operating costs down to an impressive 10-year low and increasing production efficiency consistently by 6 to 7, 6.5 percentage points, adding around 75,000 barrels per day almost for free.

Now, CapEx flexibility is the second guiding principle for us.

Thanks to the efficiency program, a high share of operated assets and also our position in the US onshore, Statoil was able to reduce organic CapEx by 50% over two years, while also increasing our production capacity.

The flexibility to adjust spending when you want to do it and not when you have to do it is highly valuable, supporting our financial management and increasing our capacity to create value through the cycle.

Torgrim will give you a more detailed update on our progress in the US later today.

Thirdly, we remain a cyclical industry and this offers opportunities to create value for companies with the capacity to act countercyclically and I will revert to this point soon in my presentation.

And finally, as we move towards a low carbon future, carbon intensity and efficiency will increasingly be a competitive advantage.

Our emissions per barrel is around half of the global average and carbon efficiency will also be a factor for us when shaping our future portfolio.

Statoil will develop our business, supporting the ambitions of the Paris Climate Agreement and we are proud to be ranked number 1 in our industry on carbon resilience by the Carbon Disclosure Project.

Then, as I will get back to, we are also building a profitable business within renewable energy.

Let me then turn to our improvement efforts.

Our target for cost improvements by 2016 was annual efficiency gain of $2.5 billion, measured against 2013.

We delivered $3.2 billion.

This is a total reset of our cost base.

But we are not done improving, in fact we are already chasing the next billion.

So on top of the $3.2 billion, we will get further impacts from already initiated improvements and market effects and that is in particular related to projects development.

And then, the next phase for us is to go from an improvement program or project mode, to a culture where we continuously improve and we are well on our way.

We are learning from other industries and using the full toolkit from the LEAN methodology and stabilization in technology, innovation and digitalization.

So in sum, this adds up to an additional ambition for 2017 of $1 billion.

A question that we often get is how sticky these cost improvements will be when markets recover and the heat of this industry, we've seen it before, is turned back on.

So my response is that we will make them stick and we also believe there is a significant potential from implication, based on that standardization and based on that also industrialization related to our industry and our company.

80% to 90% of the improvements that we have achieved are related to efficiency, doing things differently, not market effects, nor deferring activity.

As an example, we cannot control global rig rates, but we can control how long it takes to drill our wells and now we get almost 70% more meters per day compared to 2013, 70%.

These are real achievements, doing things differently, which will actually be even more worth in a potential future market with higher rates.

Then, ladies and gentlemen, here we see our next generation portfolio.

These are projects that were sanctioned in 2015 and plus non-sanctioned projects, all to be in production by 2022.

The portfolio will enable breakeven price of $27 per barrel.

It is truly a radical transformation and in fact during my 36 years now in Statoil, this is the most profitable opportunity that I've ever seen.

And while investments and breakeven are down, resources are up.

We are looking at 3.2 billion barrels of oil equivalent in recoverable resources and 65% of this is oil.

So by reworking solutions all the way from the reservoirs to the market, we are getting more for less.

In 2019 we will see first oil from the Norwegian Johan Sverdrup, where the breakeven price for phase 1 has been further reduced to below $20 per barrel.

This has always been a world-class project and now we have made it even better.

An impressive achievement we are proud of and Margareth just can't wait to give you more details on this specific project, but she can also give you other examples of how we have improved in relation to other projects.

For our post-2022 projects, we also see significant improvement and we continue bring down breakevens for this part of our portfolio as well.

In a cyclical industry, timing matters.

Between 2012 and 2014 we completed divestments of around $13 billion.

This helped us in building a robust balance sheet, supporting our capacity to act countercyclically also during the downturn.

As one example, we have awarded $30 billion in contract since 2015, capturing market effects, enhancing performance-based contract structures and also offering obviously much needed work to hungry supplier industry.

On the exploration side, we added close to 25,000 square kilometers of acreage last year.

We deepened our position in prolific basins like Norway, the UK, Brazil, East Coast Canada and added frontier options in countries like New Zealand, Mexico and the Republic of Ireland.

In 2017, this year, we start to drill around 30 wells, including several high impact opportunities.

That is seven more wells than we drilled last year, while keeping spending at the same level of around $1.5 billion.

So let's then look in somewhat more detail on how we are developing our new energy business.

As an energy company, Statoil considers renewable energy as a fully integrated part of our business, of our strategy.

Industrially, this is an opportunity to leverage our core competencies, create value in new areas.

The Dudgeon offshore project is a good example in the UK, with 67 turbines being installed as we speak.

It is really a challenge that plays to our strengths in project execution, in logistics and marine operations and other areas.

Financially, renewables offers an attractive risk/reward proposition.

So far in our projects we see a real return in the range of 9% to 11%.

With costs coming down quickly, renewables are set to be cost competitive, especially in power generation and with subsidies gradually being phased out, developers increasingly need to take on market exposure, market risk.

And this will also have an impact on return expectation and the competitive landscape in this industry.

Strategically, renewables diversify our portfolio, adding longevity and also cash flow resilience.

And to illustrate the long-term potential, in new energy solutions we are indicating a range of 15% to 20% of our CapEx in 2030 to this area.

The growth profile will be back-loaded, starting from a yearly level of around $500 million last year and growing, assuming that we are able to access and mature sufficiently attractive and profitable opportunities.

Looking at the broader portfolio, Statoil is pursuing a distinct and value-driven strategy.

On the Norwegian continental shelf, we have a unique position and we will leverage this position further to maximize value.

As a major contributor to our next generation portfolio and with further exploration potential, the NCS remains the backbone of Statoil.

In our international business, we will focus, we will deepen and we will continue to explore.

Brazil is already a core area for us, having accessed the Carcara discovery last year, on top of Peregrino phase 1, phase 2, and Pao and also building on our strategic partnership with Petrobras.

In the US, we will continue to improve, to operate and to add acreage to our highly flexible US onshore position.

In addition, our ambition is to add and to develop one to two core areas, both offshore and onshore, with the same long-term potential from further capitalizing on our legacy positions and through active exploration and business development.

For midstream and marketing, the job is still to secure closures by accessing premium markets and also to increase value, increase value creation by strengthening our asset-backed trading based on a capital-light approach.

So allow me then to summarize what you've heard this morning.

We have reset our cost base.

We have transformed our opportunity set for the future and continue to chase improvement, continuous improvement.

We are ready to invest in our next generation portfolio, currently at $27 per barrel and we have the financial capacity to execute on this set of opportunities.

With planned CapEx this year at around $11 billion, we will be cash flow positive at the $50 oil price.

We remain committed to shareholder value creation and capital distribution.

The Board will propose to the AGM to maintain the dividend at $0.2201 per share in the fourth quarter, offering a scrip option through third quarter 2017 and maintaining keeping share buybacks as a part of our toolbox.

And you should expect the dividend to be maintained at the same level for the first three quarters of 2017.

Finally, we are sharpening our strategy as an energy company towards 2030, being even more value driven in everything we do.

That's the core of who we are and how we are positioning Statoil to capitalize on high value opportunities.

So thank you very much for your attention and now I leave the word and the floor to Hans Jakob Hegge, our CFO.

Thank you, Eldar and ladies and gentlemen, good morning.

It's good to see you all.

2016 has been a tough year for the industry and for us.

The low prices have impacted our results, but we have delivered solid operational performance, taken down costs, delivered $3.2 billion in annual efficiencies and radically transformed our portfolio projects.

At the same time, we have maintained financial flexibility and our firm commitment to capital distribution.

We are in a strong position to capitalize on our high value opportunity set.

Let me start with our 2016 numbers.

Impacted by the lower prices, we delivered adjusted earnings of $4.1 billion, down from $9.6 billion in 2015.

Our net operating income was $80 million for the full year, compared to $1.4 billion in 2015, heavily impacted by net impairments of $2.3 billion.

This is mainly due to the changes in our long-term price assumption.

Still we delivered a solid cash flow, which I will come back to.

We delivered strong operational performance, high production efficiency and increased our well capacity.

Our production was above guiding, despite the high turnaround activity.

We delivered annual efficiency effects well above our ambition.

OpEx SG&A is reduced by 13% in 2016 and 30% in -- from 2013.

We have demonstrated strict financial discipline, improved the breakeven of our next generation portfolio and reduced organic CapEx for the year.

In short, we are getting more for less and we have increased the production.

Adjusted earnings for the Group were $1.7 billion, down $100 million compared to the same quarter in 2015.

Achieved liquids prices increased by 14%, gas prices were up in the US and decreased by 14% in Europe.

Our cash flow from operations was strong, up $1 billion compared to the same quarter last year.

Losses in countries with limited tax shield gave an effective tax rate of 102%.

Development and production Norway delivered strong adjusted earnings, of around $2 billion, on par with the fourth quarter last year.

Strong deliveries on production, operational performance and cost contributed positively.

OpEx SG&A is down 15% in underlying currency and the regularity is at a record high level, well above 90%.

Development and production international delivered an adjusted pre-tax loss of $681 million.

The negative result is impacted by expense, previously capitalized exploration, higher turnaround activity in Angola and Nigeria and some quarter-specific elements.

In the quarter, the cash flow from our international operations was around $17 per barrel after tax.

This is the same level as from the Norwegian continental shelf.

US offshore production continues to grow.

These are high-value barrels, generating significant cash flow with low cash costs and no tax.

Our mid and downstream business delivered solid results, driven by strong marketing and trading.

Adjusted earnings were $514 million, up 22% from the same quarter last year.

End of quarter, we had more volumes in transit to capture higher margins.

During the quarter, we produced close to 2.1 million barrels per day, an increase of 2%.

We are delivering a strong production for the full year, even with high turnaround activity and we have increased both our total well capacity and the production efficiency.

Through the year, we have utilized the flexibility in our Norwegian gas machine and moved volumes out to periods with higher prices.

In a year with limited contributions from exploration, we maintained our resource base above 20 billion barrels.

Increased recovery rates contributed to our reserves and the three-year average organic RRR was 90%.

In 2017, this year has started well.

Last week we announced our second discovery and two years after Valemon came on stream, we made a new discovery containing 20 million to 50 million barrels, which can be put on stream immediately, adding considerable value.

Our financial position remains robust, with a strong positive cash flow of $900 million in the quarter, after two tax payments, dividends and organic investments.

The free cash flow for the full year was negative $3.1 billion, after net acquisitions of $1.1 billion.

At just above $50 per barrel, we would have been cash flow neutral.

Strict capital prioritization and efficiency improvements have reduced organic CapEx with $3 billion in 2016.

The Carcara payment, impairments, currency and the increase in working capital gives a net debt ratio of 35.6%.

And the scrip program has reduced the dividend paid in 2016 by $900 million and the take-up rate for the shares issued in the quarter was 46%.

We have delivered $3.2 billion in annual improvements.

This is well above the increased ambition we outlined last year of $2.5 billion and we have captured effects all across the dimensions we have been tracking since the start of the program.

80% to 90% of the $3.2 billion is the result of efficiency gains and will have lasting effects.

Let me explain the key elements behind these results.

Close to a third, $1 billion, this is in our unit production, where we already were a top-quartile performer compared to our peers.

Costs are down and production efficiency is up.

So let me give you one example from Oseberg Field Centre, one of the largest installations on the Norwegian shelf.

From 2014, we have reduced costs by more than 30%, as we have prioritized strictly, simplified processes and do more work ourselves.

And the production efficiency is up from 85% to 95%.

And we have similar improvements across the portfolio with even tougher targets set for 2017.

$900 million is the result of increased drilling efficiency.

Since 2013 we have brought down the cost by $27 million per well, a reduction of 35%.

Modifications and brownfield cost is reduced by 45% and in addition, we have reduced our SG&A by 30%, optimizing our [staffs] and services and more efficient business follow-up.

This is a continuous hunt for further efficiencies, while maintaining a high focus on strengthening safety.

The position demonstrated by our organization is truly inspiring.

Now let me shift to the outlook for the next year.

As you've heard, Eldar has already presented our sharpened strategy for high value and low carbon and in my presentation, I will elaborate on why we believe our next generation portfolio is highly competitive and a strong investment proposition.

So before doing that, let me show you how we will continue to improve our business, capturing lasting effects.

This year we raised the bar with an additional $1 billion in cost savings, realizing the forward impact of improvements already made and continuously improving all parts of our business, further strengthening our cash generation.

We are working hard to lock in these improvements from the efficiency program and capture further market effects.

We will continue to drive performance every day, learning from the best and together with our partners and suppliers, implement best practices to increase value and reduce costs.

Reducing the drilling costs even further will be important going forward and Margareth will tell you more about this later.

Simplifying and standardizing processes of US onshore will be equally important and you will hear more about that from Torgrim in his presentation.

OpEx SG&A has been significantly reduced and we see further potential to simplify our processes and become an even leaner and more agile company.

Let there be no doubt that we are on a journey of continuous improvement, making that a core part for of our DNA.

This is cultural change in motion.

We have radically reshaped and improved our portfolio, getting more for less.

Our average breakeven is now at $27 per barrel.

At $50 per barrel, the internal rate of return is 20% and the portfolio payback is quick, by 2023 again at only $50.

This underlines the resilience of our portfolio at lower prices.

The portfolio contains $3.2 billion high value barrels, with an average production of 360,000 barrels per day from 2020 to 2022.

As the CFO, I am pleased to say that we are challenging also the best projects to become even better and the organization delivers.

Let me give you two examples to highlight what we have done.

Peregrino Phase 2 in Brazil now has a breakeven below $45, a reduction of more than 30%.

It started with spending the necessary time optimizing and simplifying the concept.

We also captured market effects in the contract awards and now we are realizing the effects of the increased drilling efficiency and strong project execution.

We aim for a production start-up in 2020.

CapEx is reduced by close to $1.5 billion and production is increased, extending the life of the field towards 2040.

Trestakk is another example, this one from the Norwegian continental shelf.

Here we have reduced the breakeven on this subsea buyback from $58 to below $20 per barrel.

And these are not unique examples, we clearly see that there is a powerful learning effect when you leverage it across the entire portfolio.

So the improvements we have made will also have an impact on the project with start-up well into the 2020s, such as the Carcara oil field, a deal we made in a low price environment, capturing value from cyclicality.

And value remains the priority and our improvements have increased our production.

The strong growth in 2017 is related to increased efficiency and start-up and ramp-up of fields such as Gina Krog, [Ivarosen] and Hebron, as well as increased activity US onshore and lower turnaround activity.

From 2018 to 2020 we have several major start-ups, capturing significant value in the upturn.

The list includes Mariner, Stampede, Aasta Hansteen and Johan Sverdrup.

This contributes to our cash generation, which I will now address.

Last year we said that we could continue with our investment program and be cash flow neutral at $60 in 2017 and $50 in 2018, with a debt ratio in the mid-$30s.

Today we are cash flow neutral at $50, after cash dividend with a stable debt ratio.

The improvements have made this possible and the CapEx reduction in the outlook period is substantial, around $10 billion without reducing the flexibility in our portfolio.

And the balance sheet remains strong, with a capacity to maneuver and we have a single-A rating on a standalone basis with a stable outlook.

We continue to be comfortable with a debt ratio in the 30s.

With the current assumptions, we will be back within our long-term ambition of 15% to 30% towards the end of the outlook period.

Now let me give you just a bit more detail on how we manage our financial framework to capture high value opportunities.

Our commitment to create attractive, sustainable shareholder value is at the core of our strategy.

We have positioned ourselves with a great set of opportunities and we are investing in world-class projects, such as Johan Sverdrup.

These are projects with strong returns and radically improved breakevens.

We see a double-digit return on average capital employed at $70 by 2020.

For the next generation portfolio, the ROACE is well above 20% when the projects are producing.

We are growing our cash flow from the existing operations and sanctioned projects, improving cash margin and we will continue to demonstrate financial discipline, managing short-term challenges, while continuing to high grade our portfolio.

We will still have a long-term perspective on investment and return.

And our dividend policy remains firm and the Board will propose for the AGM to maintain our dividend and continue our scrip option and share buyback remains a part of our toolbox.

Moving onto guidance, we plan for around $11 billion in CapEx for 2017 and exploration spend of around $1.5 billion.

Value is our priority when increasing our production and you can expect a growth of 4% to 5% from 2016 to 2017 and around 3% annual growth from 2016 to 2020.

We continue our efficiency improvements, raising the bar to deliver $1 billion in additional savings this year.

Let me sum up in three points.

First, our track record is strong.

We have taken down costs faster and deeper and radically improved our projects.

Second, we have maintained financial flexibility, with a firm commitment to capital distribution.

And finally, we are in the strong position to capitalize on our high value opportunity set.

Thank you for the attention and now I give the word to Margareth.

Thank you, Hans Jakob, and good afternoon, everyone.

Look at this, this is the world's biggest spar, it's Aasta Hansteen.

You know, this is 200 meters long and 50 meters in diameter.

If you look at the person in the white circle, that is Eldar.

So our job is to develop and to deliver the competitive solutions which will shape our company's future.

This responsibility includes the development and execution of all Statoil operated projects, it is drilling and well procurement, as well as research and technology globally.

No small task, but you know, I have the best job in the world.

Eldar and Hans Jakob, they already presented some excellent figures from projects.

I will explain how we have achieved these figures.

In 2016 has been the most energizing year in my career, not only because my boss is pleased with our figures, but because I've seen what we are capable of.

And as Eldar said, he has been in this Company for 36 years.

I'm more a youngster; I've been there for 35 years.

We keep on delivering on all our targets and I believe it is because of who we are.

I've never witnessed a more creative and result-driven force.

First of all, we have our world class project portfolio, we make even the most complex challenges profitable also with low oil prices.

We continue to reduce breakevens and increase the value of our projects significantly.

This gives us the opportunity to act countercyclical and we sanction projects.

Secondly, we seek the real game changers through innovation and technology.

In the following, I would like to support my statements through facts, numbers and examples.

After all, I am an engineer, so I like more figures than words.

So our mantra is every single dollar saved today is a dollar we can use to create value tomorrow.

It applies to the quality in project execution, just as much to the maturing of future projects.

To the left side, you see the cost development in our sanctioned projects.

In 2016, we reduced the expected forecast to 90%, compared to the sanction estimate.

Some is captured market effects, but more important, we delivered below cost because of our execution performance.

And let me give you a few examples.

Gullfaks (inaudible) we delivered more than $125,000 million, below estimate, four months ahead of schedule, due to efficient drilling, efficient (inaudible) campaign and the quality in execution.

And currently, we are more than $250 million below the estimate on the Dudgeon wind farm in UK due to highly efficient marine campaign and also the use of industry standards, $250 million below.

Obviously, I will revert to you on Sverdrup soon.

As you can see, we managed to save costs and reduce our estimates.

This means that we can sanction new profitable projects, award contracts in a favorable market and create value for the Company.

Last year we sanctioned four Statoil-operated projects, Peregrino 2 in Brazil, Utgard, Byrding and Trestakk on the Norwegian continental shelf.

Below the sanctioned projects, you see some of the exciting opportunities ahead, both short and more longer term.

The first seven projects are planned for sanctioning within the next two years.

Currently, these are the ones we have matured the most and have the lowest breakevens, but I can assure you we work hard to make all of them as profitable as possible.

On this date last year, I promised you a non-sanctioned portfolio with a breakeven below $40 per barrel.

I just wanted to remind you of this because we have over-delivered.

The graph on the left-hand side shows the exact same selection of projects we showed you last year.

The dark grey area marks the improvement in breakevens since then and the magenta color shows where we currently are.

And we have not only reduced the breakeven, we have introduced stricter CO2 intensity targets and increased the value of these projects.

The CapEx has been reduced by 43%, the resources at the same time have been increased with 12% and the NPV is increased with 12%, even with a reduced oil price assumption of 20% to 30%.

Actually, if you had kept the prices fixed, the NPV would have been increased with between 70% and 80%.

I also wanted to comment Lars Christian, Arne Sigve and Torgrim, what they have achieved on production efficiency and reduced operating costs in particular.

This learning also improves our projects.

Some of this is a result of competitive pricing and we are on track with regards to expected market effects.

However, the main contributions are improvements, which will sustain even if the market changes.

We chase every element and challenge how can we simplify the concept; how can we standardize on previous projects; how can we utilize existing infrastructure more wisely.

How can we use new contract types or models that increase performance, how can we use technology, and so on.

I believe in setting the impossible target, targets which require radical changes.

In 2015, very few people believed it was possible to reach a breakeven target of $50 per barrel, but one year later the portfolio was $41 per barrel.

And today, the breakeven in the next generation portfolio, as you have heard from Eldar, is $27.

This demonstrates we can make the impossible possible and we will work just as hard in execution phase to beat these figures.

We see this positive development in all types of projects globally, but regardless of how good these project numbers or the portfolio number gets, we will not sanction a single project until we have made it as profitable as possible.

And let me be very clear, the prerequisite is a strong safety culture.

Improvements that do not support our safety work have no place on our improvement agenda.

I promised facts, so let me go into more detail on two of our giants, Johan Sverdrup and Johan Castberg.

Johan Castberg is the largest oil discovery in the Barents Sea.

With thea selected FPSO concept, we reduced the breakeven from $80 to below $45 per barrel last year.

Since then, the scope has been matured further and the current breakeven price is below $35.

Such improved numbers do not just appear on their own.

This is a result of a project team willing to challenge conventional way of thinking and collaborate closely with their suppliers.

And since the CMU last year, we have optimized the field layout, we have reduced the number of wells, but still we have increased the recoverable resources and we have further reduced the seabed intervention cost.

We have challenged the supplier industry to find new subsea system solutions and they have responded.

Together we have simplified requirements which will result in less wait, lower complexity, less documentation and lower cost.

We have now a standard package specification which we can implement across the whole portfolio.

The estimated cost reduction is approximately NOK40 million per well.

Johan Sverdrup is an extraordinary project in size, in CO2 intensity, as well as in the achievement.

The project team's commitment is a testament to our mantra, every single dollar counts and it really proves we are on the journey from improvement programs to a continuous improvement culture.

Sverdrup has always been a very profitable project, still they keep up the intensity and continue to hunt for ways to reduce cost and increase value.

Sverdrup is a phased development and we have now completed 40% of Phase 1. Twenty-four million work hours are completed and most importantly, without any serious actual incident.

In August, we communicated a CapEx reduction of NOK24 billion, compared to the PDO estimate.

Since then, we have reduced it with an additional NOK2 billion and this is a result of the best-ever drilling campaign, quality in execution, limited scope changes and the chase for every single dollar such as optimizing the use of floor material, giving us NOK30 million in savings.

In Phase 2, the CapEx is reduced with NOK30 million to NOK45 million since the PDO of phase 1. By setting tough targets, efficient collaboration across disciplines and the use of experience from Phase 1, the project has reduced the number of process trains from two to one, reduced the number of wells from 42 to 28 and copied 40% of equipment from Phase 1. Copy, paste is good for us.

Even with the radical cost improvements, the resource range has been further improved.

Now it is ranging from 2 billion to 3 billion barrels in resources for the full field.

And we have increased the production capacity for both phases to 660,000 barrels a day.

So as you can see, the updated breakevens are below $20 for Phase 1, below $30 per barrel for Phase 2 and for the full field below $25.

I'm not sure anyone can beat these figures.

Reduced drilling cost is also significant contribution to the improved project breakeven figures.

In some cases, drilling amounts to half of the project price.

We continue to deliver groundbreaking improvements within drilling and wells and compared to 2013, we have increased the meters per day by 69%, we have reduced the days per well by 42%, which gives a cost reduction of 35%.

And as you can see, on external benchmark, it's a Rushmore benchmark on the bottom left, we are significantly lower on cost per meter drill than our peers.

So, in short, we deliver more wells to a much lower cost.

This is a result of a continued focus on simplified well design.

It's a focus on standardized wells, operational efficiency and what we call the perfect well approach, which means setting targets based on the best section drilled ever and driving towards these targets.

It embeds the continuous improvement culture we pursue in terms of both safety as well as performance.

It is a methodology we have successfully stolen from Torgrim and the US onshore operations.

It is also adopted by our projects, where the driver now is common cost targets with our suppliers.

Within all areas, not just within drilling and well, we have to work closely with our suppliers to succeed.

We do not fill the shopping cart with goods and argue the price when we are at the cashier.

We collaborate to bring the price down before we get to the cashier.

Together we work to simplify, to reduce the interfaces and find new contract models that will promote a win-win situation.

One example is the integrated drilling and well contracts on Sverdrup and Mariner and [Kettiyay], or have we bundled the marine operation together with the subsea on Trestakk.

I believe we have more to gain, for instance, by introducing LEAN, optimizing logistics, working with suppliers to reduce the non-productive time.

And, as I stated, we hunt the real game changer that can take our competitive edge to a new level.

We seek high-value, low-carbon solutions.

One example is our roadmap towards a remotely operated factory and unmanned field development.

It is the specific example of what we can achieve by utilizing the digitalization and it will radically reduce our carbon footprint.

So, picture the big platform, the standard platform, big, heavy and complex.

And then imagine the benefits of having several smaller standardized building blocks, as you can combine, allowing for better field utilization and optimization.

I simply call it the mix-and-match solution.

And everything is operated from shore.

We combine subsea with unmanned topside technology to find an optimal solution for each project.

It will improve the robustness of our project portfolio by making even the smaller field developments profitable.

An early assessment on one of our projects shows a potential CapEx reduction of $1 billion.

We see this as a future development solution for several of our fields.

It may seem like science fiction, but you know we are getting close.

Believe me, many thought the Asgard subsea compressor was unrealistic, but it has been running for one and a half years now with 100% uptime.

At the CMU in 2014 we presented the unmanned wellhead platform, or, as I like to call it, the subsea on slim legs, as our future long target.

It is already under construction and it will be installed this summer, three years later on Oseberg Vestflanken.

Currently, we are developing the unmanned production platform and the next step will be the unmanned and remotely-operated factory, aimed for frontier areas and deeper waters, for instance, like the Barents Sea.

World records for size belongs to history.

We still think big, but we build small.

This fits perfectly into the new strategy.

It requires less cash, increased CapEx flexibility and enables us to act countercyclical, and has a significant lower carbon footprint.

And based on our technology track record, I am sure we will succeed.

To summarize, we will continue to mature and develop a competitive and carbon-efficient project portfolio.

We will maximize the value creation through continuous and sustainable improvements and we will use our innovative capabilities and technology to fuel radical changes, even beyond what we have achieved so far.

I believe in the future of this industry and I know we have both the competence and the determination to shape competitive solutions for the future.

And then I would like to give the word to my very good colleague, the flexible cash generator, Torgrim Reitan.

Thank you.

So, thank you very much, Margareth.

It's a fantastic colleague I have, haven't I?

So, good afternoon, everyone, and it's good to see you and it's good to be here in London to give you an update.

Last year we discussed our plan to transform the US business.

It is a portfolio of high-quality assets and it provides a strong fit with the sharpened strategy.

The US portfolio is flexible, it can respond to lower prices and it will capture value in an upturn.

But, like many others, we invested significantly in the US in a high-price environment and, as a consequence of the falling prices, we have made impairments and we have negative earnings currently.

With that said, we have a first-class portfolio and organization and I have confidence that we have the ability to make this business work at low prices.

And as some of you may remember, or will remember, this plan has three pillars.

First, we're going to make money at lower prices.

That is measured by net operating income, our 90 to 50 ambition.

So in 2014 we needed $90 per barrel to have positive earnings.

In 2018 we'll make money at $50.

Second, we are going to improve our operations by 20% to 25%.

And lastly, and maybe my favorite, we are going to double the cash margin in a $50 environment.

So today I'll give you an update on all of this and show you that our plan is working.

So let me first update you on our portfolio.

Onshore we have an attractive portfolio in three core areas.

Last year we increased our share in Eagle Ford and we took over operatorship from Repsol.

We divested non-core Marcellus acreage.

And offshore we have had a significant production growth of high-value barrels.

And in December we won two blocks in Mexico's first deepwater bid round.

The US and the broader of the Gulf of Mexico is an important part of Statoil and a significant part of our Company and it is our task to make it work.

And hard work is what it takes for us to contribute to the targets that is laid out by Eldar and Hans Jakob.

So how are we doing?

We will bring our earning breakeven from $90 to $50.

In 2016 we ended about $66, so we are well under way.

And you know, $90 to $50, that is based on our earnings.

And the impairments we took two years drove most of the improvements from 2014 to 2015.

Since last Capital Markets Day we have taken both the impairments and we have also made reversals and the net effect of those is very minor.

So let's instead talk about the real improvements.

Unit production cost, that came down by 34% in 2016 and, along this, drove $4 on this chart.

Our onshore recovery rate is at 41% over the last year and offshore production grew by 45%.

And this was driven by new wells and also improving regularity of 94%, nine-four percent.

These new offshore barrels, they are of high quality with a strong cash flow, but they come with a high DD&A rate.

So, as an example, Julia has a DD&A rate of $60 per barrel, six zero.

That means that it contributes positively to cash margin, but, actually, it contributes negatively to the $90 to $50.

These are lasting improvements, but to get to $50 we must improve our recovery rates even further.

Stampede needs to come -- needs to start up safely and on time and production from existing fields need to ramp up as planned.

We need to continue cost reductions and our efficiency gains and we need to improve our regularity onshore.

With this progress, and what we plan to do, we can get to $50.

So let me discuss our operational targets.

Last year gave me confidence in our ability to transform what we do.

In fact, we have already surpassed two out of our 2018 targets, onshore development cost and operational cost per barrel.

And we are close on the third one, the administration costs.

So let me give you some concrete examples of what we have achieved.

In the Eagle Ford, unit of production cost is reduced by 36% since we took over the full operatorship of that asset.

And drilling efficiency has improved from 19 days to 15 days now, as we applied our perfect well approach by Margareth.

And, furthermore, we have successfully reorganized.

We have reduced cost and our business has now the ability to scale up to a higher level.

Then we have reduced CO2 emissions significantly in our Bakken operations and we are at the forefront in working to limit methane emissions.

We aim to be the most carbon-efficient oil and gas producer, nothing less.

So based on this we will set new targets for 2018.

In 2016 we benefitted from low supplier cost and a high-graded drilling program.

Going forward, we assume an increase in supplier cost and we will also drill several pilot wells and test future development areas.

We have allocated a pad where we will work together with Margareth and her team to test new technology and new concepts for drilling and completion.

Within onshore there's a short time from improvement to cash flow.

And you have seen here Margareth's team's ability to deliver, so I'm really looking forward to the way we are working together there, Margareth.

With the increasing supplier cost and these pilot wells we need to deliver further improvements to meet the new targets.

This is ambitious, but we are convinced that we can do it.

Despite all of these improvements we are not satisfied.

We cannot be fully satisfied.

We systemically use benchmarking to uncover new potential.

We have access to third-party data for thousands of wells, so we can compare our performance to others in the areas where we operate.

In most areas, I would say that we compare well.

I would even say very well.

And that is within the areas of recovery rates and drilling performance.

In other areas, we need to improve.

We are lagging on the regularity onshore and we are still not good enough on the operating costs.

Over the last years, we have spent five times as much money on CapEx than on production cost, so focusing recovery and drilling has been the right thing to do.

Now the time is right to focus even more on the day-to-day operations.

So we can do better and that is what motivates us to improve each day.

So, our growth certainly needs to be profitable.

We need to grow with quality.

Our old target was to double the cash margin from $5 to $10, while we grew production by 50% -- more than 50%.

Our new target is $12.5 per barrel.

And this is exciting.

And it comes from better performance onshore.

It comes from higher production and improved regularity offshore.

And it also comes from lower costs.

While our new fields offshore do not help much on the $90 to $50 due to the high DD&A rates in their initial phase, these offshore barrels contribute a lot to this one, to the cash margin.

So we still expect to grow around 50%, our production, by 50%, but let me be very clear.

I do not have production targets and, my people, they do not have that either, so we focus on safely producing value, nothing less than that.

Then we aim to be a cash generator for Statoil.

And we have been in an investment phase for many years and, so far, we have spent a lot more money than we have made.

In a couple of years, we will have a positive free cash flow at $50 oil.

And, at higher prices, the cash flow will be substantial, as you can see from the left side of this chart.

And then the CapEx flexibility that we have, that is gold for Statoil.

Our future investment options are increasingly attractive.

We have improved the well economics significantly and we now have more than 1,000 well targets with a breakeven less than $50.

And we are optimistic that we can get many more wells into this category.

Our plans tell us that we now are building a sustainable business at lower prices.

So, let me summarize.

We have still negative -- a negative net operating income.

However, the plan we introduced last year, it is working.

We are on track to make money at $50 in 2018.

Our operational improvements are progressing and we are setting new efficiency targets.

At $50 oil we will have a cash margin after tax of $12.5 per barrel.

So, the US portfolio, it is flexible, it can respond to lower prices and it will capture value in an upturn.

And then we are reducing our carbon footprint as we go forward.

All of this is very much in line with the strategic principles that Eldar outlined earlier today.

It is still early days for the US business.

As of today, we have only produced 11% of our economic resources and our portfolio has a large potential and our business is scalable.

My team and myself, our job is to make money and to create growth options for Statoil.

And we are prepared to add acreage when we see the right opportunities.

With our assets, the capabilities and people, the next chapter of the US journey will be a very exciting one.

And I'm feeling that I'm already now looking forward to update you when we have progressed this journey even further.

So, thank you very much.

I look forward to your questions and to discuss with you.

And then I leave the word back to you, Peter, so, thanks.

Thanks, Torgrim.

Thanks, everybody.

I'm pleased to say that we're right on schedule.

A little bit of choreography now while I invite Eldar and Hans Jakob back on the stage to take your questions.

We're going to have roving mics for everybody in the audience and also mics on the tables where we've got the executives as well, so we'll be able to do those.

So if you want to come through there and stand on that one.

We'd aim to take questions for around 50 minutes.

I know this is a long session.

There's a lot of important messages we think are good ones that we want to get through and give an opportunity to discuss.

I know I have something of a reputation for being fairly disciplined in terms of our approach to the questions and I'm going to re-enforce that discipline.

I'd like to keep it to one question, preferably in one part, with the promise that if we get through those and there are some spare, we will go around again.

This is something where we want to give everybody an opportunity to ask those questions, so we'll do this one.

50 minutes max and there'll also be plenty of opportunities afterwards.

Let me see.

The first hand I saw was Brendan.

Thanks, Peter.

So it's Brendan Warn from BMO Capital Markets.

Just coming back from the last set of results, and probably just looking forward, just this whole deferral production for value and for cash flow, can you give us an idea where the amount, or can you quantify that value for me?

And I'm not allowed to ask part B of that.

You can ask a part B if it's related.

Yes, and I guess for Torgrim, in the past we've heard about the onshore, or, I'd say, the US going to 500,000 barrels a day, a lot of additional promises.

Where are the pushbacks going to be, or where are the -- I guess, the more difficult parts of your portfolio that you're dealing with and in terms of future divestments of your current portfolio?

So, in terms of deferrals, I assume you are referring to the gas flexibility that we have in our upstream portfolio on the Norwegian continental shelf.

So it is important for us to utilize that flexibility to create value, not to run off the production volume targets or anything like that, and we have done that consistently over a long time.

I think the net position, now that we have deferred some volumes, I think it corresponds to around 20,000, 25,000 barrels per day in volume, so not a significant deferral.

But this is something that goes up and down, depending on how we look upon the market at any point in time; highly valuable and we use that flexibility.

Then, I guess, the next question, Torgrim, was for you.

What I could say on the -- I said in my strategic comments that we will continue to operate, improve, and also add acreage.

Torgrim is preparing the business to the stage where we feel comfortable earning the right to do that.

He's pretty much there now.

We are ready to bolt-on, add acreage to this business.

It is a highly-valuable component of our overall portfolio, the flexibility of it, the cash resilience and so on.

So in terms of how we would like to do that, divesting, investing, that is something that we will look at whatever opportunities is at hand and no more specific comments on that.

But I think to the question, Torgrim, you might add some comments.

There is a microphone there I think.

I think this is working.

So, thank you, Brendan.

First of all, 500,000 barrels per day in production targets, those type of targets are long gone.

We don't use those type of targets.

We are focusing on value and we see production as a vehicle to create value.

So we have changed our targets from being a top-line target, production, to be a bottom-line target, earnings and making money.

So that's sort of -- we can just disregard the 500,000 barrels per day.

Then, on the difficult part of the portfolio, I would say it's very encouraging to see that the underlying profitability of the portfolio is changing.

Deepwater Gulf of Mexico has been seen as a very challenging part in the current price environment and I'm very glad to see that also those projects are improving significantly.

We have over there improvements in -- maybe not as impressive as Margareth talks about, but still very impressive.

And I would say, for instance, the Vito development that Shell is developing, and we are joining, is now looking at breakevens in the low 40s.

Onshore, the more difficult part in the onshore portfolio, I would say is Bakken.

The Montana part is still there.

It needs to be worked.

We haven't focused a lot on it and that's why we are joining Margareth with a pad in that area to see how much we can actually get that down, as such.

But it will take research, it will take technology and it will take a bit of stamina, long term, to make that work, but I think ultimately we'll get there.

I can talk about the Eagle Ford and Marcellus as well.

Marcellus, I would say, Ohio part of the northern Marcellus and Utica is coming across as very promising, the well rates there.

And always, of course, the northern Marcellus and the gas, fantastic breakevens, but exposed to local prices, as you know.

Those assets are actually free cash flow in the current price environment, so they are working.

Okay, take the next question from [Teepan].

Sorry, here?

Yes.

Thank you for taking the question.

It's Teepan from Exane BNP.

I just wanted to talk between the balance between investment and levels of investment versus the balance sheet.

My question is, how should we think -- let's say oil prices don't necessarily go up as quickly to the $75 outlook, but in the next couple of years are around current prices.

So how do you see what a sustainable level of investment is, particularly given the good work that you've done improving breakevens against deleveraging the balance sheet and, essentially, initiating a buyback program?

Thank you.

So, investing in new capacity high-quality asset is definitely a priority for us.

That is how we create values and also can distribute capital to our shareholders as well.

So, we have a high-quality portfolio and it is a priority while maintain the commitment to capital distribution.

We can do both.

We have indicated through the presentation that you gave, Hans Jakob, that the current gearing level is sustainable in the mid 30s at an oil price of $50 per barrel.

And if the oil price should turn out to become $70 or even $75, that we have assumed as our long-term price assumptions, this will significantly improve our debt ratio and our financial capacity.

We have the capacity to invest in the current opportunity set, but it will always be value driven.

If we don't have sufficiently attractive high-value opportunities at hand, that will have an impact on how we prioritize in this environment.

In terms of priorities and capital distribution, we're very firm on the scrip program.

We extend that in line with what we indicated last year.

There's no change in that plan.

The Board has the discretion to make adjustments, but there is no plans to extend it or shorten it, so that's basically what you should expect, that we will move forward with that.

In terms of buybacks, that is an option that we keep as a mandate, ask every year at the AGM to give us that mandate, and we will keep that.

As long as we have a scrip program in place I don't think you should expect us to introduce any share buybacks.

And beyond that I think priority will still be to -- in terms of gearing and debt ratio we are very comfortable in the 30s, but we would still say that we have an ambition of -- a long-term ambition of getting into the range of 15% to 20%, so that will still be a kind of a priority to get into that range.

But overall all these priorities are something that will be looked upon at any point in time, given the quality of our opportunity set and the outlooks that we are looking at, at any point in time.

Okay.

Going to do Mehdi and then I'm going to swing over, right at the back, to Lydia.

And then that will give an opportunity to bring the microphone this side, so, Mehdi next.

Hi, this is Mehdi Ennebati from Societe Generale.

I will ask a question regarding the non-sanctioned portfolio breakeven.

So just would like to compare April with April, because last year you've highlighted during the CMU 2016 that the breakeven will be $41 -- is $41 per barrel for the non-sanctioned project starting up by 2022.

Margareth highlighted that now we are, let's say, close to $27 per barrel, but this takes into account Johan Sverdrup.

So, just would like to compare April and April, so excluding Johan Sverdrup, how did you manage to decline this $41 per barrel, just in order for us to measure your efforts?

And just would like to come back to the slide number 23 and this is why, in fact, I am asking the question.

You provide the breakeven average per project and we can see a project which is at $10 per barrel breakeven.

I wanted to know if this the what [is at] Phase 1. Thank you.

So, it's a very good point.

We have tried to be very prudent.

I defined in my presentation exactly what is the $27, the next-generation portfolio kind of a brand.

What is that?

It is not the same portfolio that Margareth talked about last year and referred to here, which was at $41.

That was a portfolio not included -- including Johan Sverdrup.

It was basically non-sanctioned projects at the time of the previous CMU, but still in production by 2022 and Statoil-operated projects only.

That portfolio, Margareth, you have to correct me, would have a breakeven price of around $30 per barrel.

(Multiple speakers).

The same portfolio, so it's $41, $30?

So, it's from $70, to $41, to $30.

So, what I would like to show you now is what I call the next-generation portfolio, the whole portfolio opportunity set with the next-generation mindset, which includes Johan Sverdrup.

It also includes partner-operated projects, which actually has a higher breakeven than our portfolio, but still we include that.

That gives you a feeling for our whole portfolio, which financially will have an impact for the Company.

So the difference is basically the partner-operated components, which is in there, and Johan Sverdrup mainly which is in that portfolio.

So that's the precise difference between those two portfolios.

Then on the -- you had the figure in your presentation, so is $10 the breakeven for Johan Sverdrup?

It's not.

No, it's not.

And we won't tell you which project it is, but there are great projects which is at the very low profitable -- high profitability and low breakevens.

Okay.

Lydia in the distance.

Hello there.

Now I can say it's Lydia Rainforth from Barclays.

If I could ask a question about the cost savings numbers.

And obviously, you've increased that target today to $1 billion and then beyond into 2018.

Is that now a stretch target in terms of that cost-saving number that you have?

And, possibly for Margareth, you have made those cost savings look relatively easy and I know they haven't been.

What do you think is the biggest challenge going forward for those?

Okay, so if you take the first question, stretched or not, and then, Margareth, prepare for the next one, right?

Well, I think it's been very encouraging to see that we have over-delivered by $700 million.

And you're absolutely right, Lydia, it's not been easy.

It's been hard work and across the entire organization, so it's many contributions to that.

And that's why we, with confidence, talk about the culture of continuous improvement.

Is it a stretch target?

It is a tough target and it's for this year.

And we expect to see within facilities related to sanctioning projects, but also further market effects that we have talked about in the past.

So, the market effects in the $1 billion is around $200 million-ish of the total $1 billion?

Yes.

And just for the record, we talked last year about $300 million to $400 million in market effects.

It's actually turned out to be a bit higher, so more around $450 million for last year.

Including the [3.3] and then the additional one is around $200 million?

Yes.

Margareth?

What are the most challenging?

First of all, I would say we have to deliver on it, so it's dependent on our execution capabilities, which I've also proved today that has been very good.

But of course if the price is getting up again we have already said that 10% to 20% of the savings are related to market and market capitalization.

If the price is getting up again you just have to fight that.

But I would like to say once again that we have tried really to reduce the cost side by sustainable reduction, by simplification and standardization.

And what we can do if the price is going up again is, first of all, we can ensure we have sufficient competition.

And there is various forms of competition.

You can have different suppliers or you can have different concepts, for instance, the unmanned platform towards a subsea solution.

So, this is one way we can act.

At the same time, I think it's also very important that we collaborate with our suppliers.

If we collaborate very early we can find the best solution.

So, maybe it was a long answer, but -- yes.

Thanks, Margareth.

We're going to do three questions from this side of the table and then we're going to take some questions that we've had on the phone, so kicking off with Marc.

Great.

Hi, everyone.

It's Marc Kofler from Jefferies.

I just wanted to ask you a question which, I guess, is reasonably similar to the previous question, but on the capital spending and the guidance for this year, particularly in the context of the evolution in the guidance on capital spending that we saw in 2016.

How much will room, flexibility, is there in the 2017 program?

And should we expect -- is it even possible to get the same kind of gradual decrease in capital spending coming through this year that we saw last year.

And then, following on from that, I just wanted to clarify if -- how significant the NOK currency assumption in the capital spending program for this year is.

I think I saw NOK8.5 on one of the slides.

Thanks.

So, I think I'll leave to Hans Jakob to address this.

Yes.

So, thank you for asking that question, Marc.

As you are aware, we started off with a level of doubling.

We're coming from a level of $20 billion down to last year's $10.1 billion and so the efficiency gains has been tremendous.

And what's the further potential?

What's the sustainable level?

So we guide of around $11 billion for 2017 and we say it will be somewhat higher going forward in the guiding period.

And we have maintained the flexibility of $4 billion to $6 billion that we talked about last year.

So, we don't have to sanction the projects according to the plan if -- but we plan to do so, because we think we have a strong value proposition, very attractive returns at this level and a breakeven of $27.

And in terms of the exchange rate, you are correct.

Thanks, Hans Jakob.

Could I just say in relation to the breakeven cash flow that we talked about last year, that was what we could do.

When we talk about $50 this year, that is what we will do.

All our projects is included in that roadmap for 2017 and going forward.

Haythem.

Thank you.

It's Haythem Rashed here from Morgan Stanley.

Eldar, just a question for you on the DPI business, the international upstream business.

If you take a step back, broader than just the US, you've said in the past that you've not been so happy with performance there and there's room for improvement.

I just wondered if you can give us an update on where you see that business going in 2017.

It sounds like some of the headwinds around DD&A mean that maybe results from that business will still have a bit of a transition phase in 2017.

Is that a fair assessment, or do you think that we'll start to see some of that improvement already this year?

Thank you.

I think I will offer an opportunity for Lars Christian to comment on his part of the business.

He will address the US business.

But in general, from my perspective the international business in the balance sheet looks slightly different from the Norwegian continental shelf.

It is a younger portfolio, obviously, then also a higher cost portfolio.

It has been accessed in slightly different ways as well, at least part of the portfolio, which actually make us reflect market values in the balance sheet and not historical development cost.

So that gives us depreciation, DD&A, per barrel which is, I think in this quarter, two and a half times what you see on the Norwegian continental shelf.

Nothing I can do about that.

This is history and this is where we are.

My focus is on value and value, to me, is about cash and improvements.

So my focus is on improvement and on cash generation.

On cash generation, we are on par.

It was mentioned by Hans Jakob that $17 per barrel cash from our operations internationally, including both Lars Christian's and Torgrim's portfolios, onshore and offshore.

That is the average.

That is exactly the same as we have on cash generation from the Norwegian portfolio, excluding exploration.

So it is really a cash-generating portfolio internationally.

I think really we're demonstrating that we have a good starting point to develop this portfolio.

It will be part of our strategy going forward.

SG&A, OpEx is down around 30% in the international portfolio, which is on par with what we are seeing in the rest of our business, so really, I think there has been really good progress.

Torgrim has addressed his progress.

Lars Christian, if you would like an opportunity to comment on your achievements.

Thank you, Eldar.

In addition to SG&A down 30%, our operating expenses is down 30% since 2013, CapEx spending down 50% in 2013.

We expected a [money] increase in a range 20% to 22% towards 2016.

It's actually down 20% compared to 2013.

So, this is across the whole board.

If I look at my portfolio of assets, I have some of the best assets in the Company internationally, and then I have some not so good assets, which is the case across the whole board, actually, for the Company.

Last year I said that the net operating income before exploration would be positive at $46 a barrel.

I delivered that result, at $45 a barrel.

And then the realized oil price for last year was just south of $45 a barrel.

And it's so easy to just focus on the oil price last quarter, which was higher definitely, but the first quarter for 2016 the realized oil price for the international part of the business was well below $30, actually, so that is what I have in the baggage for the whole year of 2016.

As Eldar is saying, the DD&A is two and a half times the Norwegian continental shelf for fourth-quarter 2016.

For the full year, it's twice as high.

And the cash flow after tax, per- barrel basis, is at par with NCS.

So it is a strong portfolio, but it has its challenges and has had.

We have worked extensively to improve it and we are not fully where we would like to be.

And you see also us doing some portfolio adjustments.

We have exited one asset and we have acquired a couple that will definitely also improve the composition for the international part of the portfolio.

One comment regarding the new projects going forward for the international part of the business.

We see the exact same improvements as we do for the NCS projects.

Breakeven is down by $40 so far and we're still working many of these projects to bring them forward in due time.

Thank you.

Thanks, Lars Christian.

Going to do one more from the floor, then we're going to take some from the phones, and then I've got a cluster of questions in the middle here, so, Hamish.

Thanks, Peter.

It's Hamish Clegg from Bank of America Merrill Lynch.

I think we can all agree you've done an excellent job on the cost-cutting program.

The efficiencies have gone extremely well and appear to have brilliant momentum going forwards as well.

As we feel we're exiting the trough in the cycle for the sector, with oil prices starting to look slightly better, and a good outlook, the focus for some of us shifts onto the discipline side.

We see the momentum in your cost-cutting program, but would like to -- maybe if you could allude a bit more to the options in your portfolio for your resource base.

You gave us a 20 billion 2P resource number today, which is great, nearly 30 years.

Could you expand a little bit on a couple of things for me?

First is, how much of that is coming from Lundin and Johan Sverdrup?

And second, beyond that, with that exploration program where will the focus be?

Can we see more opportunities in Brazil?

And you didn't mention the prospectivity in the northern Barents as well, so -- thank you.

Okay, so, I'm glad to have Tim Dodson here, who is heading up our exploration business.

I addressed exploration briefly in my presentation.

That was at an aggregate level.

I will give Tim the opportunity to answer that question.

On the resources reserves, the nature of that, Hans Jakob, could you add some color to that?

Yes.

So, thank you for the question.

I had a slide on the organic 2PR of 90%.

In a year with limited contribution from exploration we had very strong operating momentum, adding volumes from the existing fields.

And on Lundin it's 1.65.

Could I also just say before you give the word that Tim that -- referring to Lars Christian?

A lot of the resources is outside of Norway.

We have some assets.

I pointed towards the beyond 2022 portfolio, which is, in many ways, predominantly a portfolio outside of Norway.

There are also Norwegian assets, but most of the big Norwegian assets will be done.

That we know today will depend on exploration.

The big assets are outside of Norway.

We are improving that portfolio, as Lars Christian mentioned, quite significantly.

We are not prepared to give details.

You will find them in the graph on the page that, Hans Jakob illustrated there, are improving, but we really, really have to address them as forcefully as we have been doing on projects like Johan Castberg and others.

So, we expect significant continued improvement of that portfolio and that is really also what is part of the resource base.

Tim?

Okay, thank you very much.

When it comes to exploration, our focus going forward will be more or less the same it has been for the last few years.

Our results have not been as good as they were in the period 2011 through 2013, when we proved up close to 5 billion barrels of the current resource base, the 20 billion.

We have been focusing the last two years in reloading, basically, replenishing our portfolio.

That should come as no surprise, as we drilled out what turned out to be a very good portfolio in 2011, 2012 and 2013.

And that's really what exploration is about.

I always say that if every prospect you drill and test it moves out of my portfolio, whether it's a dry well or a commercial discovery, which I hand on to my development and production colleagues, so it is about replenishment.

Our focus going forward will be as it has been before, a balanced and attractive mix of exploration activity in prolific basins.

We have a very attractive program in Norway, in fact, if I can include UK into that this year.

We have good follow-up opportunities in both Canada and Brazil, again, prolific basins.

And then we have select higher-risk frontier opportunities that can represent break-through opportunities in terms of big discoveries with a potential for standalone developments, so that will be our focus going forward.

A good opportunity set this year, as I say, and I think the perspectives for next year are also fairly good, given the fact that we've loaded up with so much and such good-quality acreage over the last two years.

Thanks Tim.

If we go and take four or five questions from the phones now, please, thank you.

And then we're coming back into the center and I'll kick off with Odd.

We will now take our first question from Anders Holte from Danske Bank.

Your line is open.

Please go ahead.

Good afternoon, guys.

Actually, my questions have been answered already, so I'm good.

We will now take our next question from Teodor Nilsen from Swedbank.

Your line is open.

Please go ahead.

Good afternoon and thanks for taking my question.

One question on CapEx.

You say that a normalized CapEx level going forward will be $12 billion to $14 billion.

I just then wonder what kind of supplier price does that range assume?

Do you assume any increase from today's level?

And then just a follow-up on the exploration level because Tim mentioned some specific prospects in the Barents Sea that you like?

Thank you.

Okay, so in terms of the supplier cost, basically, what we have assumed into the numbers are contracts that, yes, I mentioned $30 billion of contracts that has been awarded and options that is added to these contracts.

The way we have structured them gives us optionalities in terms of using the same contracts into new projects.

So we have I would say a pretty good overview of prices and the cost of supplies in the conventional portfolio.

That is included, so we haven't taken any bets on something beyond that.

When it comes to the onshore in the US Torgrim, we see already, in the conventional part, we see still a lot of capacity into some of the segments, into rigs, for instance.

There is a lot of rigs, spare rigs, that hasn't got a lot to do, marine activity ships.

A lot of capacity in many segments, which will in many ways impact for quite for quite some time the cost of supplies.

When it comes to the US situation, it's more dynamic, more responsive, and I think Torgrim already sees that there are some pressures on cost of supplies.

That is already included in his assumptions and also in fact included in the improvements that Torgrim was showing in his presentation.

So then Tim expected that one on the Barents Sea, so please, your comments.

Okay, thank you.

Thank you for the question.

As Eldar already mentioned in his presentation, we will be testing a number of high-impact opportunities this year.

Just did a quick count.

I think it's six, which I've communicated, whereof three of those in the Barents Sea, Korpfjell, Koigen Central and Gemini North.

The three others, in case, you're wondering, is Verbier in the UK, and it's a prospect in Surinam and a prospect in Indonesia.

And I would hasten to add that the first four are moderate risk.

The second, the last two, are typical high-risk, high-reward frontier prospects.

Thanks, Tim.

Got more questions on the phones.

We will now take our next question from Anne Gjoen from Handelsbanken.

Your line is open.

Please go ahead.

Yes.

Good afternoon.

Thank you for taking my questions.

I have a question related to tax.

In fourth quarter, the tax in Norway, I see it as surprisingly high, and my understanding is that it has to do with reduced uplift, with such low investment level going forward that stays low.

What kind of impact will that have on your tax?

I understand that for the Company as such, it is difficult to give tax guidance, but is it possible to say something about the tax rate in Norway.

But if for example oil price of $50, $60, $70, thank you?

So he's the tax expert now.

I used to be.

Yes.

So thank you, Anne, for asking that question.

In the quarter, we had a tax rate in Norway of 72%.

That's in line with our guiding, but you're absolutely right, when the results go up and the CapEx goes down, the tax rate will increase.

But we haven't changed our guiding.

Next question on the line?

We will now take our next question from Halvor Nygard from SEB.

Please go ahead.

Thank you.

Two short questions.

Firstly, in your production guidance, it looks like if you plan to produce around 520,000 barrels a day in DPN flex gas in US onshore in 2020, could you say something about the split between the two?

That is, how much is flex gas and how much is US onshore?

And then secondly, you mentioned that you are looking to add one to two new core areas, both offshore and onshore.

Can you give some more color in terms of geography, type of hydrocarbons, timeline, and if it will be organic or inorganic?

Thank you.

So one to two, yes, expected that question.

I think it's too early to tell.

We are looking at -- we have heard today about a very interesting exploration portfolio.

That could take us to certain places, not all the places that Tim is exploring.

But hopefully, we will get some exploration success that adds much reality to the portfolio and that could be related to places where we already have legacy assets, or it could be totally new places.

So in the offshore, it is obviously there are some good opportunities with the east coast Canada, and Canada is one of them -- you didn't mentioned drilling in Canada, but you will drill wells also east coast Canada this year.

Gulf of Mexico, Mexico -- wider Gulf of Mexico, including Mexico, is definitely one option.

You have accessed acreage and frontier acreage in Gulf of Mexico, two licenses, again, which are not being drilled this year but which is ahead of us.

And in terms of Mexico or Gulf of Mexico, we are in a process of reviewing, taking another look at how to understand geology and prospectivity in this region.

So these are examples of what could be, but there could also be other opportunities to build those kind of core positions.

That doesn't mean that the core or countries will be the only countries where we are, but we see the potential to develop the scale -- scalable and material positions in one to two additional offshore countries.

Onshore, again, it's too early.

We are exploring many opportunities, both from an exploration perspective and from a business development perspective, [John].

Russia is one of the countries where we have -- we are pursuing several opportunities, both offshore and onshore, so that could be one of the onshore opportunities, but it's too early to conclude.

So let's say one to two, and it's just a guiding to telling us that we are doing more than just hanging onto Brazil and US onshore we are really looking to build a more robust portfolio of core countries also outside of Norway.

Then, yes?

That's it.

That's it.

One more from the phones, and then we'll go through to a cluster of questions through here.

We will now take our next question from John Olaisen from ABG.

Your line is open.

Please go ahead.

Yes, good afternoon, gentlemen.

A question to the slides from Hans Jakob Hegge.

Hans Jakob, you say that the orders have started up from 2015 to 2022 will have a return on capital employed, average return on capital employed, of above 10% with an oil price of $70 in 2020.

First, it sounds a little bit low, if only you could comment a little bit on that.

For instance, what kind of gas price assumptions do you have behind that?

And maybe just as importantly, do you think this portfolio of projects will pull up or pull down the average return on capital employed for Statoil in 2020?

Hans Jakob?

Oh, I think I got feedback.

So the last question, it goes up.

About the returns, I think we are coming from a lower level of returns that's been quite moderate the last year, it's fair to say.

But going forward, a return above 10% and an internal rate of return well into the 20s, I think that's a clear direction and a very valuable and attractive value proposition.

In terms of gas price, we are now disclosing the price assumptions, so basically the -- in 2020, we are talking about a $6 per million BTU European gas price and a $4 Henry Hub price.

Yes, note six.

We're going to come back onto the floor now, and then we've got a cluster here.

I'm going to kick off with -- well, actually, I'm going to go first with Oswald Clint.

Nearly there.

You'll all get your questions.

Thank you.

Yes, I really wanted to follow up on one of those previous questions, Eldar, about new growth options in the international upstream business, and obviously looking out to a rising oil price scenario, $75 to $80, it obviously forgives a few sins in terms of M&A.

You've spoken about a lot of impairments through history.

So maybe talk about business development and what criteria you specifically look at today going forward, what's changed there to ensure that you're really acquiring or accessing high-return projects, regardless of the oil price, please.

And then secondly, if I can just follow up on Margareth's, one of her charts, talking about the recoverable resource stepping up 12% or so over the last three years.

Is that the normal level of resource creep that you've seen over your experience?

Is that higher than normal?

If so, what's really doing that, and what -- is that something we should expect to continue on that new portfolio?

Thank you.

So, first, on business development, Tim, you might -- John, you might want to add to my comments here.

But I stated in the strategy that this very conscious strategic direction of being countercyclical is important.

We have been that, and we will definitely try to be even more countercyclical.

That doesn't mean that we could sell and buy at any point in time, given the portfolio and the assets are -- and the buyer and the seller is the correct one, but generally, we would like to do this in an efficient way, countercyclical way.

I think the mindset that we do, that Tim do on exploration, John does on business development, exactly the same as Margareth has on her assets.

It's not about the long-term assumption.

It's really about building resilience, cash flow at all times and the principles that we established.

So we need to see a project, even if we had to put a price on the table to access project, that really has the potential to fit into the kind of resilience in terms of breakevens that we see and would like to see to sustain and be robust against whatever kind of uncertainties that we might have.

I don't know if the oil price is going to be $75.

Just an assumption.

We want to build resilience into that portfolio.

On top of that, John is working on optimizing and looking at projects that we can support cost efficiency, synergies -- for instance, on the Norwegian continental shelf, unlock even small stuff that we did last year, on Utgard and so on.

So it is really a value-driven M&A strategy, has been highly successful so far, but it's even more important that in the future, we hang onto the strategic principles that we have established.

I don't know, John, if you want to add to this.

Sure.

So business development is a mixture of buying and selling.

You saw that we took advantage of the selling side for 2012 to 2014 at about $12 billion.

If you go back over to 2010, that was about $25 billion of proceeds and about $12 billion of profit.

Not that sinful.

And then on the acquisition side, if you look at what we've done this year, we've basically been doubling down in places that we know, and some of those acquisitions around Lundin -- that's about $540 million up on a mark-to-market basis at the moment.

Not that sinful.

And with regard to Carcara, taking advantage of the downturn, and we've had a lot of interest from many companies, including big-name IOCs and farming into that acreage, and we're looking forward to building on that when the next license round is announced in northern Carcara.

There are many -- what we've done in Carcara is the beginning of a very significant opportunity.

I think there's still opportunity for value creation in what Tim and I do in that area.

Thanks, John.

I'm going to go for Biraj, and then Anish, and then Rob.

Biraj is there.

Hi.

Thanks for taking my question.

It's for Torgrim.

Just following up on one of the other questions on service costs.

Could you just clarify what you're seeing right now in terms of any kind of service cost inflation?

What's baked into the plan and do you see that as a risk to getting from 90 to 50 breakeven?

Okay, Torgrim.

You take that.

Thank you very much.

We feel that we have reached all of the bottom of the cost curve within onshore.

We see increasing activities, particularly last of the Permian Basin, and we also notice that our suppliers are starting to want to discuss supply cost again.

We have assumed a 20% increase in supply cost over the next couple of years into the numbers, and that is to me a pretty robust assumptions, so that is consistent to -- so we should be able to deliver on the 90 to 50 with pretty significant growth in supplier costs.

The main driver for 90 to 50 is efficiency, not market effects, so that efficiency is sustainable deliveries, and that will -- we continue to deliver on through this period.

Thanks.

Anish?

Thanks.

It's Anish Kapadia from Tudor, Pickering, Holt.

I had a question on your reserves.

Statoil compares fairly poorly versus peers on reserve life, and I think it's a pushback from some investors in terms of looking at Statoil relative to peers.

When I look at your resource base, it seems like you've got about 3 billion barrels of resource that has been sanctioned and a further 3 billion barrels of resource that works at sub-$50 that hasn't been sanctioned as yet.

So I really wanted to get a sense of how does your reserve replacement -- how do you expect that to trend over the next five years or so as you bring some of those projects online and you also sanction some further projects?

So obviously, the resource base contains both the reserves that is booked today and also resources that we expect to be booked as we drill wells and creates more certainty according to the criteria that is established for that certainty going forward.

Some of the project is still not at the breakeven levels that we would like to see.

In particular, in the international portfolio, significant improvements but still room for further significant improvements, and we are confident that these projects will translate into resources, but it will take time to develop these resources into reserves.

And I think we have a track record now of showing what we are capable of doing.

And all I have to do is put Margareth there on the task, and she will deliver the kind of returns that we see both from our current assets, and we will also make sure that we pursue the same strict criteria in terms of assets that we acquire, that we explore for, that these are assets that have the potential to feed into the future reserves base.

In terms of expectations, I said briefly that we expect our reserve replacement ratio to be on average above 100% over the next few years.

I can't guarantee on a specific year, but looking at what we have at hand and how we are working to mature these assets, drilling more wells, I am sure we will get more reserves.

Also, [Julia], Torgrim, so that's the nature of it and that's what we expect to see over the next few years.

Thanks.

Rob.

Thanks.

It's Rob West, here from Redburn.

One of the messages I'm taking away from today is that you could have taken CapEx much, much lower if you'd wanted to.

You haven't given us a number of where you could have taken it, except when I get my ruler out later and read off your slide.

If you wanted to say a number, that would be welcome.

But you're spending more than that because of countercyclicality and desire to grow.

And on page 23, you give us a useful 20% IRR at $50 oil on these upcoming projects, which are the basis of the growth.

So my first question for you is, to me, 20% IRR makes sense to put that money into new projects rather than getting rid of the scrip or paying more of the dividend or a buyback.

Is there a hurdle that you need projects to clear where you maybe are not so sure and say, actually, at say 10% or some lower number, yes, I'd rather give it back in cash?

That's the first bit, and secondly, related to that -- sorry to break the Hutton rule about the two questions -- it's one for Margareth, I think.

That 20% IRR pre-sanction, I'm guessing that would not be too dissimilar to IRRs on projects that you saw pre-sanction at previous points in previous cycles.

I guess one reason those IRRs might not have been achieved previously is because of re-inflation once projects get going, and change orders, and design weaknesses.

So could you talk a little bit about higher levels of design certainty going into these projects today?

I guess you talked about simplifying them so they should be less complex and less prone to overrun, but is there more engineering per project going in on that list of projects that you showed us a little bit later in the presentation?

If you could say anything about that, that would be great.

So, I'm very reluctant to give any hard lines anywhere, really.

That locks in flexibility, and you know, in terms of what is good enough for a project, I think we are impressed with what we have achieved, and what Margareth has achieved, $27 breakeven, and you see there is a range of projects and a lot of them hasn't been worked yet.

So, to say this is the kind of project that we won't invest in, and we will do something else with the money, I can't offer that kind of hard line and criteria.

But what I can say is that, you know, the oil price assumptions, gas price assumption is not kind of a criteria that it used to be.

We look at NPBs and so on based on our long-term price assumptions, but really, what is the key criteria now is okay, is this project as good as it can be?

We are value driven, so we have time to wait to make it as good as it can be, and to have the resilience and the best outcome.

And then, that is the more important criteria in terms of break-evens than actually, does it meet the criteria in relation to an oil price assumption.

So a very different mindset.

I would say the oil price assumption is more actually for an accounting purpose than a decision-making purpose in terms of the new projects.

In terms of project, and uncertainty on this, I would say Margareth was very clear again that we take the time.

We did -- you mentioned the Peregrino 2 project.

We spent one more year.

We felt it was not good enough.

One more year, and we significantly improved the returns in that project.

We had actually FID'd the project, then we stop it.

Hey, we can do better, and we spent the time that it takes to improve this project, and that means a lot of processes, more up-front loading in a way, but also in terms of challenging the projects.

This is not setting a team to design something, it's really is this the best design, and that kind of process is really also very important for us, that we have teams that circles around and address -- challenges the projects.

The Snorre, for instance, project, future of that is a project that was a new platform.

Then, we start to challenge that, and suddenly it's a subsea.

We didn't think it could be, but by doing that process, you know, taking the time, we turn around, come up with totally different solutions.

So you need to do that.

Then, once we have the project, I don't think we do more engineering or any more work into the scoping, but we take time to make sure that we have the right, fit-for-purpose solution.

Now, Margareth, you have at least an opportunity to add to this.

First of all, I think we do it in another way.

We start with the minimum solution, we start with design-to-cost, and if we need to add something it must be value creation.

I feel we are maturing the projects in a better way, and I think we start earlier with the involving of the suppliers to really get the best solution.

And it's not only with Castberg we have postponed a bit because we thought we could do it better.

We have proactive teams to really challenge us, and it's the same with Trestakk.

So, I think we work differently, because we have people challenging and we start by the minimum solution and not the very big solution as we used to do.

So we are not using more engineering hours, but we are maturing the projects better prior to sanction, I would say.

Margareth, thank you.

We're going to take the last question now, because we're running literally into overtime.

Tom?

Thanks Peter, it's Tom Robinson from Deutsche Bank.

Just one question, and it really relates to strategy in the new energy business, which I think, Eldar, you effectively started your comments off today on.

Would you just talk about the very long-term shape of cash flow in that business, and how you measure success in that business?

And the way I'm thinking about this is, to me it feels like you go through an investment phase that potentially may last a number of years.

I think if you follow the CapEx outlook that you presented in slide 11, certainly a number of years.

When do you move out of that investment phase into something that generates cash for the group?

So, the earnings from Irene were positive in the last quarter.

We don't report it, but it was positive, so we are already there.

I think this is a very different business.

It has a different risk profile, maybe slightly similar when it comes to project execution as such, but when it comes to the revenue side and operations side it's very different.

Also, the risk profile gradually will change as we take on more market risk.

That will make it also more similar, but not quite because it's different markets than we see within upstream oil and gas.

So to me, this is attractive, but you have to relate it, the attractiveness and the reward, to the risk profile of the relevant projects that you are talking about.

That's something we always have done.

We relate projects to project-specific risks.

Pipeline project, for instance, different risks -- they're regulated -- than EFP projects.

So we see -- we are seeing returns in the range from 9% to 11%.

11% is basically with the Dudgeon project, and (inaudible) is more at the 9%, the pilot project.

So that's the kind of returns that we see, and these are quite a distance from the cost of capital to these projects.

So they are creating value on behalf of our shareholders.

Forward, we will look at the same type of returns, but they will always, if we see higher risk or market exposure we will look for returns that is capturing that, and rewarding us for that, but it also offers opportunity in the marketplace.

Instead of having a fixed revenue, you can really work the market.

So the condition for all of this is that Irene here is able actually to deliver projects.

I don't allocate 15% to 20% of anything.

I give a roadmap here on the slide in terms of how this could look like.

I think it will be backloaded.

I think Irene will have to struggle, fight really hard, to get project to fill in to something like that.

If she doesn't, we won't.

If she does, we will.

But it's really a tough, commercial exercise, exactly in the same way as we do within oil and gas.

Thank you.

With that, I'm going to call the Q&A session to a close.

If there's -- is there any summaries at the end, Eldar, that you'd like to say?

I could repeat the -- no.

I hope you got a good understanding of where we are.

I really tried to come through today, explaining that we have fundamentally reset this company in terms of cost, how we run it, in terms of efficiency, but also the opportunity set.

And that, in many ways, comes together into -- when I can say that we can actually be cash flow neutral at $50.

Not only today, we can do that going forward.

That's a place I didn't think that we would be, actually.

Now we are there, and that gives us a whole set of new opportunities, high-value opportunities, and I think also we have, for the longer-term, strong organization, strong capabilities to add resources to our business through business development.

We have demonstrated it through exploration, be patient, we have demonstrated it in the past, and I feel confident in our capacity to not only run the short-term and our current portfolio, but also sustain our oil and gas business while also developing a highly profitable renewables business, Irene.

So, thank you very much for coming, really appreciate it, look forward to seeing you all again next year.

Thank you very much.