Equinor ASA (EQNR) 2012 Q1 法說會逐字稿

Ladies and gentlemen welcome to Statoil's first quarter earnings presentation both to the audience here in Oslo and to all the webcast audience.

My name is Hilde Nafstad.

I'm the Head of Investor Relations in Statoil.

Before we start let me say that there are no fire drills planned for today in case the fire alarm goes off you will need to exit through the two back doors on each side and gather towards the same side and gather outside.

This morning at 7.30 Central European Time, we announced the results for the first quarter 2012.

The Press Release and presentations for today's event were distributed through the wires and through Oslo Stock Exchange.

The quarterly report and the presentations can as usual be downloaded from our website, Statoil.com.

I would ask you to kindly make special note of the information regarding forward-looking statements which can be found on the last page of the presentation.

Today's program will start out with Statoil's CFO Torgrim Reitan going through the earnings and the outlook for the company.

As usual, the presentation will be followed by a Q&A session.

Please note that questions can be posted by means of telephone only, not directly from the web.

The dial-in numbers for posting questions can be found on the website.

It is now my privilege to introduce Chief Financial Officer, Torgrim Reitan.

Thank you, Hilde, and good afternoon to all of you here in Oslo and good morning and good afternoon to all of you on the webcast following us there.

So it is a pleasure to present our results for the first quarter today.

This is our best adjusted earnings ever, 11% production growth but that is as expected.

We are continuing our exploration success and we keep on streamlining our portfolio for the longer term.

So a strong quarter.

But before I get started on production and financials I want to start with our strategic progress.

We made three new high impact discoveries this quarter, Norway, Tanzania and Brazil.

Two out of these three are operated by Statoil and this means six high impact wells over the last 12 months.

So we will keep on drilling for more and I'll get back to this later today.

This weekend we signed a strategic cooperation agreement with Rosneft.

This is an important milestone in our arctic exploration program.

Also this we will come back to later, and we have the pleasure to have with us Tim Dodson our Head of Explorations, so he will be available in the Q&A session, and I'm sure he looks very much forward to tell you all about this.

We continued to streamline our portfolio towards being a technology-focused upstream E&P company, and in April we accepted a cash offer for shares in Statoil Fuel & Retail.

Couche-Tard is a strong industrial buyer.

They are offering an attractive price, a premium of 53% so SFR will continue their strategic development under a long-term industrial ownership.

And for us it frees up capital so we can put our money where our strategy is.

The offer period will last until May 21 and we expect to close the deal in the second quarter.

And finally we are maturing our project portfolio.

We signed the pre-unitization agreement on Johan Sverdrup and that means that we are operator up to the PDO approval.

We started production on Marulk where Eni is operator and Marulk is connected to the Norne FPSO.

We also put together or put the subsea tie-back project the Smorbukk North East in production, that's only 30 months after discovery.

That's a satellite to Asgard B.

Our PDOs for Skuld and Asgard subsea compression were approved.

And finally, first oil was produced from Caesar Tonga in the Gulf of Mexico and that was one month earlier than planned and a great job there by the operator Anadarko.

So we are making progress and we will move ahead as planned.

So over to production.

In the first quarter we grew production as expected.

2.193m barrels per day and that's an 11% increase over the first quarter last year.

But it's important for me to say that this is not more than what we need to deliver in accordance with our guiding.

We see growth across the board.

We have grown both our oil and gas production and production in Norway and internationally.

Gas is an important part of this story.

We increased our gas production by 16% and this demonstrates the capacity and the flexibility.

And you know our gas strategy well.

We are using our flexibility and in the first quarter we have especially used the flexibility at Oseberg and Oseberg is the world's largest short cycle storage as I put it.

We can produce Oseberg in 80 days.

So we have used the full annual production permit in Oseberg in the first quarter picking the best prices.

So that demonstrates the value of flexibility.

Liquids production has increased by 8% from 2011 and that's a stable liquid production on the NCS.

Then we see increased oil recovery and we see that is paying off.

On the Statoil fields we now have a recovery more than 50% across the Norwegian Continental Shelf.

In other regions, people expect around 35% and 1% increase means actually 300m more barrels of recoverable oil.

In addition, we have started up and ramped up new fields internationally.

This leads to a record international production this quarter.

Let me give credit to Total for the startup of Pazflor in Angola which is performing really well.

Pazflor started producing in August last year, ahead of schedule and that field has produced more than 40,000 barrels per day for Statoil in the first quarter.

Also Bakken, the Bakken asset in the US contributes well for reproduction of more than 26,000 barrels per day in the quarter.

So we have taken on our first onshore operatorship and this is part of our step-wise build up in unconventionals.

But it is also my job to remind you of the uncertainties in the production going forward.

BP they have announced another delay on Skarv.

They now expect production started in the fourth quarter 2012, and this will of course have negative impact on our production.

The original Statoil capacity for Skuld was estimated at 50,000 barrels per day assuming a startup last year.

So now we expect low contribution from this asset in 2012.

We are making good progress on the riser issues at Snorre but there are still uncertainties related to this and we are progressing with the build-up but it will still impact production in 2012 as expected.

And we will continue with our gas optimization.

I said earlier that we had used our flexibility this quarter, with the great gas machine like Oseberg.

But that also means that we have already taken out some of our gas potential.

So that will also impact coming quarters.

Then to turnarounds.

Yearly impact on production from turnarounds will be 50,000 barrels per day.

In the second quarter, the effect will be 40,000 barrels per day on a quarterly basis, but in the third quarter I expect the impact to be as much as 110,000 barrels per day on a quarterly basis.

Then I also would like to remind you that the Centrica deal closed on April 30 leading to -- that will lead to lower production from these assets for the rest of the year.

In the first quarter, the contribution from the Centrica package was around 40,000 barrels per day.

So to be very clear there will be a significant growth from 2011 to 2012, but first quarter is as expected we maintain our current guiding and as I said, have said over several quarters there are more risks to the downside than to the upside.

So to the results.

In the first quarter of 2012 net operating income NOK57.9b, that is up more than NOK7b from last year or 14%.

Net income NOK15.4b, when you compare that number with the quarter last year you should remember the large and almost tax-free profit we booked on the divestment on KKD.

So we do as usual make adjustments to better reflect our underlying operations.

And this year the adjustment amounts to NOK1.2b and that is mainly related to negative changes to fair value of derivatives.

So the adjusted earnings before tax was NOK59.2b and that's a record for Statoil in one single quarter.

That's a 25% increase over last year and this stems primarily from higher prices and increased production.

Production growth counts for an increase of NOK7.2b and increased prices in kroner accounts for close to NOK8b.

Then the costs.

SG&A and operating costs, they increased by 19% on a quarterly basis.

I'll come back to that, but this increase mainly is related to increased production and higher prices.

After tax we made NOK16.8b in the quarter and that is up more than 40% from the same period last year.

All segments have delivered increased earnings this quarter.

There's a lot to say about these results, but let me reflect on the cost development.

The operating expenses and SG&A increased by 19% this quarter, and you know cost that is something that I watch closely.

So most of these cost increases result from production growth, higher prices and more projects underway.

So I will take that segment by segment.

Development and Production Norway, they had a result of NOK47b, that's an increase of 20%.

NOK900m in increased costs is related to higher production and increased well maintenance at several fields.

International Development and Production had adjusted earnings of NOK7b and this is an increase of 35%.

Here we see NOK1.8b in increased operating costs and SG&A, and NOK1.2b out of those comes from increased royalties.

And the increased royalties comes due to higher prices and higher production.

And you know we like both -- both higher production and higher prices.

So the main contributors are Tahiti, Gulf of Mexico and the onshore fields in the US and Peregrino.

Then you have NOK600m increase which is linked to ramp up from fields like Leismer, Peregrino, Marcellus and Bakken.

Marketing, Processing and Renewals delivered earnings of NOK4.6b and that is up 68% from the same period last year.

And this is in spite of NOK1b in lower tariff income due to the divestment in Gassled.

So that NOK1b will impact coming quarters too.

For Natural Gas the increase was mainly due to higher margins on gas and strong trading results, using the flexibility we have in the upstream portfolio.

For Crude Oil Processing Marketing and Trading we have turned a loss in the first quarter last year to a gain of NOK600m this quarter.

So a great job by our traders in the first quarter.

We also see improved Refining margins on oil products and very strong operations from oil refineries.

But there is still a demanding market for the business.

So we will continue our improvement program with full force.

And you should note that you should expect fluctuations in the results from MPR from quarter to quarter and you should also remember that a certain part of the result is actually volume driven, so the first quarter had high volumes.

The reported tax rate was 73.3% in the quarter, based on adjusted earnings, it was 71.6% and our guiding is a range between 70% and 72% and I've said earlier that you should expect it to be in the upper part of that range and this is still valid.

Then to the cash flow.

This quarter the cash flow from operations was NOK70.8b and that is up from NOK56.4b in the first quarter last year.

And we paid NOK19.4b in taxes.

Then we received proceeds from the Gassled transaction that provided NOK13.9b and on April 30 we closed the agreement with Centrica divestments of NCS assets.

So that will bring -- that has brought $1.525b to our account, so that will show up in the second quarter cash flow statement.

And finally we expect to close the Statoil Fuel & Retail transaction by end of second quarter.

This will provide an additional NOK8.3b when we adjust for dividend received.

And SFR will be deconsolidated from our balance sheet at completion and we have also stated in the report that we expect an accounting gain between NOK5.5b and NOK6b on that transaction, but that is to come.

As you know, we pay tax in Norway, six times a year.

In the second quarter we will pay two installments, both around NOK17b each and then we will pay more than NOK20b in dividends this quarter.

So there will be a lot of money coming our way and there will be a lot of money going the other way during the quarter.

We have quite a comfortable position with a strong balance sheet.

We have a net debt ratio of 15%, that has been reduced significantly over the quarter and I expect it to be further reduced by year end.

And financial robustness is still a very important and strategic issue to us and we will continue to run Statoil with a strong balance sheet.

And we will keep on putting our money where our strategy is.

We will develop a portfolio of 150 new projects that we have in the funnel, and you know this will take considerable investments over this decade.

And this will lead to an attractive growth and you know very well that we have an ambition to produce more than 2.5m barrels per day in 2020.

So we will deliver visible and high quality growth.

So let me go into more detail on another building block in our strategy.

A great oil and gas company must be good at exploration.

And I dare to say that we are progressing well.

We had 22 wells with drilling activity in the quarter.

We completed 12 wells with eight discoveries.

So we made discoveries in 67% of all of our completed wells.

Last year was a pretty good year for exploration.

Then we added a total of 1.1b barrels from exploration in new resources.

During the first quarter of 2012 we have already added more than 500m from exploration so far and a lot of that comes from the three high impact discoveries.

Havis, in the same license as Skrugard in the Barents Sea and combined these two hold around 400m to 600m barrels of recoverable oil and this is the second high impact discovery in the North in nine months.

Then Zafarani, meaning saffron, is a gas discovery offshore Tanzania.

So far producing up to 5 TCF of gas in place and this is the first Statoil-operated discovery in East Africa.

And this will be important for the future development of Tanzania's gas industry.

Then Pao de Acucar, the Sugarloaf Mountain, that's a Brazilian pre-salt oil discovery.

This discovery is operated by Repsol.

It is 200 kilometers from Rio at 2,800 of water.

And the hydrocarbon column is 480 meters and a total pay of 350 meters.

So this indicates that our exploration strategy is paying off.

Simply put, our strategy consists of two elements, early access at scale and then taking more risk, prioritizing high impact values.

During the quarter we had accessed new acreage as well.

In January we secured 11 licenses on the NCS and we will operate eight of these.

We then farmed into a license in West Greenland, P2, in the Baffin Bay and in April we entered our first acreage in Ghana, farming into deep water license just south of the Jubilee field.

Not to mention the seismic preparations for drilling subsalt Angola, and then we have secured new acreage in Russia through the agreement with Rosneft.

So we will continue with momentum.

We will drill around 40 wells in 2012.

There will be around 20 high impact wells around the world in three years.

We continue to drill the NCS both mature and in frontier areas and we are also stepping up our operating activity internationally.

And you know we look at cold parts of the world, Barents, Alaska, Canada, The Faroes and Russia.

We are positioned in the Gulf of Mexico and pre-salt Brazil and there are also other important areas to watch going forward, like Angola, Tanzania, Ghana and Indonesia.

So let me give you the names of three wells to watch in the near future.

Kilchurn in the deep water Gulf of Mexico was spudded in January.

This well is expected to be completed towards the end of second quarter.

Then we have Lavani in Tanzania, that is in the same block as Zafarani.

The well was spudded late April and we expect it to take around two months.

And this prospect is very interesting based on the Zafarani discovery, but you know as with exploration, all exploration there are many uncertainties.

And then King Lear in the mature North Sea is coming towards a conclusion.

Based on Statoil's high equity this is a potential high impact discovery for us but the structure is large so several wells may be required to appraise the whole prospect.

This is high temperature and high pressure.

We also plan to spud the Bioka Well in the Gulf of Mexico in May and the Peregrino salt appraisal in mid-June.

So we are looking forward to a lot of exciting exploration activity this year as well.

Now let me describe another key building block.

And that is to continue developing our international portfolio.

Towards 2020 we aim to establish material positions in three to five offshore clusters outside NCS and step up our shale gas and liquids production, and we aim to produce more than 1.1m barrels per day in 2020.

And actually even if 70% of our production is coming out of Norway currently actually 50% of the resources sits outside Norway and that resource base has grown significantly.

Much of our growth will take place internationally in places like Gulf of Mexico, Angola, Azerbaijan and Brazil and onshore in North America where we are expanding stepwise in the unconventionals.

And as you can see, we have increased our international production significantly.

In 2001, the international production of Statoil and Hydro combined was less than 100,000 barrels per day.

In 2007, when we merged we produced around 400,000 barrels abroad and this quarter we produced 662,000 barrels per day.

That's more than 50% growth over five years.

And we intend to almost double this by 2020.

So we are investing for growth and in the next five years 40% to 50% of CapEx will go to international projects.

Around 90% of our CapEx will be upstream related.

70% of investments will be in greenfield and there's a clear bias towards liquids around 60% of our investments will go towards liquids.

So we will grow with quality and profitability.

And we are already doing quite okay.

The international segment contributes significantly to cash flow.

In the first quarter it amounts to 17% of EBIT there.

So we are positioning Statoil for the long term and we are building our resource base for future production growth.

Now to the agreement with Rosneft.

And this is big, more than 100,000 square kilometers and that's an area that equals around 200 blocks on the Norwegian continental shelf.

Two-thirds of all Arctic resources are expected to be found in Russia.

And the agreement is an excellent strategic and technological fit and it builds on existing positions in Arctic, Faroes, East Coast Canada, Chuckchi Sea, Beaufort Sea, Barents Sea, Stockman, and it strengthens the relationship between Rosneft and Statoil and Russia and Norway.

Under the agreement Statoil and Rosneft will set up joint ventures with Statoil holding 33% in each and the established joint venture relationship will govern the asset cooperation.

We will enter into a phased work program commitment and this means a stepwise approach enabling us to phase expenses over time.

The acreage will provide drilling targets in the medium term from 2015 to 2020 and this will bring new high impact opportunities.

Finally, the agreement also provides Rosneft with an opportunity to acquire interest in Statoil assets in Norway and internationally.

And this will be under negotiated terms.

So this is an important long-term agreement for both parties.

Going forward, we are progressing as planned and we expect to spend around $17b in investments in 2012.

But if we continue with exploration success we'll end up capitalizing more of our exploration costs and that actually could push up that number, but actually I can live with that.

As long as Tim keeps on discovering oil and gas.

We also maintain an exploration level as last year, around $3b.

So we will complete around 40 wells this year and we have actually an inventory of drill ready wells that is larger than this, so it can be optimized.

And there will be around 20 high impact wells from 2012 to 2014.

I see no reason to change our production outlook, but I have reminded you of the uncertainties, so I don't want to go through all of them once more.

So just remind you that guiding remains firm but there are more risks to the downside than to the upside.

So in summary, it has been a very good quarter with significant progress for Statoil, our best adjusted earnings ever, significant step-up in production, continued exploration success and streamlining of portfolio, putting our money where our strategy is.

So thank you very much for your attention.

And then, Hilde, I'll leave the word to you to guide us through the Q&A session so thank you.

Thank you, Torgrim.

For the Q&A session, Torgrim will be joined by the Executive Vice President for Exploration, Tim Dodson who will be able to expand on the cooperation agreement with Rosneft for you.

He will also be joined by the Senior Vice President for Accounting and Financial Compliance Kare Thomsen.

We will take questions from the audience and over the telephone.

So I will first ask the operator to explain the procedure for asking questions over the telephone.

Operator please.

(Operator Instructions).

Thank you.

We'll start out with questions from the audience here in Oslo.

Trond, you're first.

Can Trond have the microphone please.

First, congratulations on the very strong result.

Of course a lot of it is also on high gas offtake.

There seemed to be some comments earlier by Helge that some volumes may be moved to 2013.

Can you have some comments on your view of the very high level of you on the gas market?

And also of course you had a higher production permit for Troll.

Can we assume that will be as expected prolonged into the next gas year?

Okay, thank you, Trond.

We have a lot of flexibility in the gas machines and we intend to use that to earn more money.

To us money is actually more important than counting barrels and so on.

So if opportunity arises to move gas production in time, we will do that.

But we have that flexibility as we go so if price curve changes and so on, we might elect to say, okay, we don't want to produce, for instance, that much Troll this summer, let's sell it forward into next summer if the prices are much better there.

We did that significantly in the summer 2009 then gas prices was GBP0.20 per therm and the next summer GBP0.40 per therm.

So we turned it down and sold it forward and we gained 100% premium on that gas.

That brings me into a related issue and that is the importance of carving back flexibility, because we hold a lot of flexibility in our portfolio on behalf of the long-term customers.

So we have taken back quite a bit of flexibility that we now use ourselves as a trading tool.

We intend to use that going forward as well.

When that is said, currently the prices in the UK are strong, GBP0.60 per therm, around that.

So that is strong prices in an historical context.

And we see actually a quite firm gas market in Europe going forward.

We see LNG heading in other directions to Asia and we are actually taking our own LNG from Snohvit to Asia from time to time, South Korea and other places, realizing significantly higher prices than in Europe as well.

So I have quite an optimistic perspective on the European supply of gas.

When it comes to uncertainty in the short term it is very much dependent on how the market will develop, especially in the summer periods.

So that is something you can watch.

Then on Troll permits we have in place the full permits and you can expect that -- I don't expect there to be any changes in that going forward.

I also have one question on Rosneft deal.

Of course, this is an enormously -- opportunity but can you also talk a little bit of your view on the risk on changes in fiscal conditions and whether you see any changes in that legal framework in Russia?

And could you also maybe that's to Tim - there seems to be on Rosneft they published some yet-to-find estimates, seem to be 15b barrels and 65 TCF of gas on that.

So what kind of -- is that based on?

How much seismic has been shot.

And there's also in the release Rosneft says that Statoil should pay historic costs on these licenses, are they major expenditures?

Okay, I'll start with the tax and then, Tim, you continue.

Country risk is something that we are facing across the portfolio.

We have it actually in the UK.

We have it Ireland, we have it in the US, we have it in Angola, in Brazil in Venezuela, Algeria, Azerbaijan and of course in Russia.

So this is part of running an oil and gas company.

And government take is of course key element to that country risk and predictability in what you can believe in is very important.

In Russia, in particular, it's quite special these days.

Politicians clearly signal improvements in the tax terms and also providing sufficient predictability to facilitate offshore developments and so on.

So Russia is actually moving in another direction that quite a few other countries are doing currently.

So we welcome that very much.

Then it will be very important for us to have those frameworks in place before we make any investment decisions and so on.

Currently we have to live with some uncertainties and for us it's very important to be able to do that and then see that things are coming together before we start investing and so on.

But there are positive signals currently from Russian politicians and so on and we all know that there's a large incentive in Russia to attract international capital and competence and making all of these resources happen.

Tim.

Okay, let me address the yet-to-find estimates from Rosneft first.

I think it's important to say these are very immature frontier exploration acreage.

And by that I mean all of the four licenses not just the three in the Far East.

Rosneft have studied these to a greater degree than we have, albeit on a pretty sparse database of 2D seismic of varying quality.

So I think when we think about these resources estimates, we should liken them with the resources estimates for the rest of the Arctic, and that there is considerable uncertainty related to these estimates.

Having said that, this acreage is so vast that if you were to prove up oil and gas in these acreage you would basically open up not just a new plate but a new basin with all the potential that that might imply.

Like I say it is very early stage.

There are no wells drilled in any of these license and in fact the license with the least data over it is the Perseevsky license in the Northern Barents Sea.

When it comes to the historic costs, then they are limited.

There is a small signature bonus which is paid by the equity holders to the Russian state.

Otherwise there is basically no license history here.

So the historic costs are expected to be very limited in nature.

Do we have any further questions from the audience?

Yes.

Please state your name and company you represent as well.

Espen Hennie from DnB Markets.

Regarding the cooperation agreement with Rosneft, I wonder if you could provide some details regarding timing and size of those potential asset deals, including NCS assets.

Okay, I can at least speak on the Russian side, then, the commitments which we've entered into are related to the exploration program.

For the four licenses in question we will have to drill a total minimum of six exploration wells.

So that's six for all the four licenses, not six times four.

That is the minimum commitment.

In the case we make a discovery which we think is worth appraising, then we will also have to finance a limited amount of the appraisal program.

In terms of timing, then the first well has to be drilled.

I can't remember which license it is, but it's one of the licenses in the Far East by 2016.

When it comes to the Perseevsky license in the northern North Sea then the first well has to be drilled by 2020.

So these are very long term licenses much longer term than we're used to.

That's actually good.

Again gives us a lot of flexibility.

It gives us a reasonable amount of time in order to acquire the necessary seismic data to interpret that and then to be able to place the wells in an optimum position.

So this six well program will be spread over the period from 2016 until 2021 and then I guess depending on success then there will be an appraisal program following on from that.

The license period is 30 years.

These licenses were awarded the ones I guess both in the Barents Sea and the ones in Okhotsk, they were awarded on December 29, 2011.

So the licenses will run until 2041.

And in terms of the assets on their side, I'm not at liberty to disclose names on that.

But as you've seen then Rosneft has the opportunity to negotiate further equity interest in Statoil assets both in Norway and internationally.

And we will also be forming a couple of joint technical studies.

That's also been communicated onto Russian onshore assets.

The one is the biggest greenfield in West Siberia.

It's not unlike Troll, it's a huge gas cap with very significant oil lag.

And the other one is in the Stavropol area, down towards the Caucasus and that's a shale oil opportunity not unlike the fields to which we're exposed for in the onshore US.

Do we have any -- yes, please.

Hi, this is Kim Evjenth, ABG.

Just a quick question on the jurisdiction on any conflicts arising from the Rosneft agreement.

Where would that take place and what are the mechanisms?

I don't know the specific answer to that, because as I say we've now entered into a strategic cooperation agreement.

There will be joint ventures established for each of the different assets, both in Russia and outside of Russia.

We expect that to take some eight to nine months.

I think we're targeting a signing date for all these detailed agreements in March in 2013.

And that will equate to the period with ExxonMobil have used to finalize all the detailed agreements on the Kara Sea deal.

Do we have any further questions in Oslo?

No.

I actually can't see any questions on my screen.

Operator, do you have any questions?

Yes, actually now I can see Brendan Warn from Jefferies.

Please go ahead, Brendan.

Thanks, Hilde, it's Brendan Warn from Jefferies.

I think you'll have more questions, the questions weren't registering.

Just firstly actually to Torgrim, I appreciate your comments on the European gas market, but I was wondering if you can actually give us some more insight into any of your longer term gas contract negotiations.

I know it's a regular question you get but I appreciate there's a number of gas contracts up for renewal this year.

Just any push for breakage of linkages with oil.

And then benefitting from having exploration team there.

Just in terms of your farm in to Ghana, what in terms of discovered resource have you farmed in on and what sort of activity in the near to medium term are you looking for Tim?

Okay, thank you, Brendan.

On the long-term gas contracts change is happening.

On Continental Europe the structures in the gas markets is changing.

So we are in the middle of a transition as I see it and we actually very welcome a change in the market dynamics.

So on the long-term contracts with our gas customers have served us well for 30 years.

We have renegotiated with them every third year.

So what we are discussing currently is something that we are used to discuss.

In 2009 when the financial crisis hit the first time we said to our customers, okay, let's renegotiate now and then we don't talk to each other in three years and that's three years ago.

So 2012 is a year where we are in discussions with a lot of customers.

So the key points to take away from what's going on.

We are selling energy security and we are selling flexibility.

We are willing to make changes to the long-term contracts and put more spot indexation into the contracts.

But, we are not selling a spot product and so on.

So, what is very important when we do that is to carve back flexibility from the contracts and also having access to the liquid hubs so these contracts can be served in the liquid market as any other contracts, and so on.

And that flexibility is extremely valuable to us.

Currently, we hold capacity, both in the transportation systems and in the production systems for the customers to nominate on a daily basis between 40% and 110% of the contract value.

When we put spot indexations into contracts, we take back that flexibility, and then we trade it.

And then we pick the best prices.

And then we decide ourselves where the gas is going and to where that is going to head.

So, all of this is ongoing.

I think it's fair to say that the negotiations are progressing well.

We are preparing ourselves for a different gas market, building up our own end-user portfolio.

That has doubled over the last few years.

So, we now sell directly to the end user, [stadtwerker], power plants, industrials, large industrial customers, and so on.

And we see that the liquidity on the various hubs are increasing.

So, this is progressing well, and we achieve good prices on our gas, as you see in this quarter.

And we are well equipped to handle the European gas markets in the future.

So, remember that we have preinvested everything that is needed to handle our gas.

We are close to the market.

Our gas has to travel one-fifth of Algerian gas distance, one-eighth of Russian gas, and one-tenth of Qatari gas, and so on.

We -- I think I dare to say that we have one of the very, very best gas organizations in Europe.

So, we are set up to handle this.

And then flexibility comes back to where it belongs, is actually with the producer.

And we will make money out of that.

So, there's a lot of discussions with the customers currently, progressing well.

And we actually see that not all of them would like spot products.

Actually, customers that want oil-linked gas contracts still.

Okay.

Maybe I should just take the Ghana question.

It was related to the resource potential.

What I can say on that is that we've committed to drill at least one well.

That well is drilling already and progressing very well.

And we are -- that well will be testing a new play.

It's a high-impact well in a proven hydrocarbon province so that I guess if we wanted to add to the list on the wells to watch, then that more than likely will also be one that we will know the result of -- by the end of the two -- second quarter as it looks at the moment.

Could you just expand on the comment of being a new pla in Ghana?

Appreciate it.

No, I can't.

I don't want to disclose that because, if this works, then I would like to exploit it further.

Fair comment.

All right.

Thanks, Tim.

Thanks, Torgrim.

Thank you.

Next question goes to Jason Kenney from Santander.

Please go ahead, Jason.

Question, so, I was wondering if you had a net reserves estimate for the Brazil pre-salt find.

I noticed you mentioned reserves with the other two high-impact finds in your commentary.

Secondly, on what could be a potentially significant excess cash flow, I wonder if you could just rank again the possible options for this going forward with be it special dividends or share buybacks or simply maintaining a higher cash balance on the balance sheet.

And then finally, if you could give me some guidance on the exploration charge, certainly a lot lower in the first quarter than I was anticipating.

I wondered how it might pan out for the rest of the year.

All right.

Tim, I suggest you start on --

Okay.

-- Brazil question.

And I'll --

Okay.

-- the rest.

Torgrim basically told you what we can tell you at this point in time.

The only thing we've said that this is most definitely a high-impact discovery, greater than 250m barrels.

As yet, we're not in a position to disclose the more specific numbers than that.

But, as Torgrim alluded to.

We have very significant both gross and net hydrocarbon column on Pao.

So, I'm afraid you'll have to be patient on that one.

Okay.

Then on the cash flow, it is a strong cash flow.

We have a net debt of 15%.

By year end, I expect it to end around 13%.

If Statoil Fuel & Retail transaction goes ahead, the net debt at year end is expected to be reduced by another around 4 percentage points by year end.

So, it is strengthening the balance sheet further.

And as I said, to us, it's extremely important to run with a solid balance sheet.

Good company or a great company must be able to take long-term decisions and strategic decisions, even if the weather is poor, even if uncertainty increases and/or prices drops and so on.

So, we will carry out our strategy, even if the better becomes worse.

And to be honest, on that note, we use quite a bit of resources and energy to understand what's going on around us.

And to be honest, it is very hard to estimate where it ends.

A lot of the experts that we use was the same.

They didn't see what was coming in 2008.

But, we're perfectly able to explain it afterwards.

So, my conclusion is, the best that I can do or we can do is actually to be prepared.

That is what we can do.

And very much about that is to run with a solid balance sheet and significant liquidity on our hands.

When it comes to the share buyback, we are asking the general meeting next week for a mandate on that, like we have done for many years.

So, that is for us to have the toolbox in place if that is found appropriate to use.

But, no decisions to use a share buyback program has been made at all.

This is just to have the toolbox in place.

So, that's on the cash flow.

Then on the expiration charge, so that is low in this quarter due to exploration success.

The guiding we have given is that you should expect two-thirds of the exploration activity to be expensed in general terms.

But, with significant exploration success, that expensing will be less.

And more will be capitalized.

But, I have no reason to change that assumption going forward unless you, Tim, here now can promise that everything that we do will still be a success.

Okay.

Many thanks.

Thank you.

Our next question comes from James Milligan from Olivetree Securities.

Please go ahead, James.

Yes, first of all, congratulations on a great quarter.

I have a quick question on Marcellus volumes and pricing.

Given that Cove Point has received the LNG export authorization, can you use your existing relationship with Dominion to access better prices?

Okay.

Thank you.

So, for those of you -- Dominion is operating their Cove Point plant in Virginia.

There's a re-gas facility for importing LNG to the US.

Very little gas is going in that direction.

We hold capacity related to Snohvit.

And then we also have some capacity on Cove Point expansion.

We are not using that terminal currently.

We are rerouting the ships typically to Asia to take better prices.

So, we appreciate $18 per MBtu better than $2.

So, that is good money.

It's actually shipping the other direction.

We have a good and long-lasting relationship with Dominion, working very constructively together.

They are evaluating to make investments there to make it liquefaction plant to export LNG instead of importing LNG.

So, this is something that we follow closely.

But, it takes quite a bit of investments to do something like that.

You need to believe in a spread of gas prices around $4 per MBtu over 20 years to justify an investment like that.

There are several initiatives in the US currently in that respect.

And we are following development closely.

You touched upon Marcellus in that respect.

And our Marcellus asset is producing well, close to 50,000 barrels a day currently.

And as you know, it's in an area with low breakeven prices and all of that.

We are adjusting production together with Chesapeake, taking down the rig counts somewhat.

So, Chesapeake is acting as we like.

And then there is, of course, a big important issue related to Marcellus gas.

And that is to take care of your gas.

I know I can keep on going for a couple of hours because we were through this earlier.

But, it is extremely important to take care of your gas.

And we have entered into transportation capacity to Canada and Toronto.

So, currently, our Marcellus gas from October will go in that direction to a different price than actually around Marcellus.

All right.

Thanks.

Thank you.

Our next question comes from Jason Gammel from Macquarie.

Please go ahead, Jason.

Yes, thank you very much.

I noted the progress that you made in your Bakken production.

I was just curious if you could share the rig count that you've been running in the Bakken to achieve these higher levels of production and whether you're seeing any inflation on the cost side of things and then also if you could just address the type of pricing differential you're receiving there relative to either Brent or WTI and what sort of transportation arrangements that you have in place in the Bakken.

Okay.

Thank you.

So, we have stepped up in the rig counts.

When we acquired it, I think it was 12 rigs that were operating there.

Currently, 16 rigs are working for us, actually progressing very well, good results so far.

When it comes to costs, it is developing fairly okay.

We see that suppliers actually would like to work with a company like Statoil due to that we take a long-term perspective and the predictability for a long period in the industrial relationship.

So, we are able to attract high-quality counterparties.

And that is very much appreciated.

When it comes to price differentials, that is the case currently.

And we expect that to continue for awhile still.

And that was also the assumption we used when we acquired the assets.

And then the key is, of course, to look for transportation solutions.

And we are looking for opportunities to use rail or train transportation of crude from Bakken and onto the Cushing area.

So, there are initiatives going on to do that as well.

So, that is ongoing.

So, producing well, differential, yes, and we expect that to be in place for awhile.

But, we delay dealing with it.

Great.

And can I just ask one quick follow up?

Is there any word on when or if you'll be taking over any operatorship in the Eagle Ford acreage?

Operatorships in Eagle Ford, yes, we have -- that is together with Talisman.

And we plan to take over operatorship of half of that in next year.

Thank you.

Thank you.

And our next question from Oswald Clint, Sanford Bernstein, please.

Yes, thank you very much.

I would like to just ask a question on your improved oil recovery activities in the quarter.

You mentioned the relatively low decline rate.

Can you give us what that number was and how that compares to the first quarter of last year to get a comparison?

Thank you.

And also, just -- you mentioned your Kilchurn well coming up subsalt Gulf of Mexico.

Tim, is there any read across from yesterday's Kakuna well with Nexen?

Thank you.

And Torgrim, sorry, just one final one on Iraq, a couple of steps to start exiting Iraq, can you say what those steps are?

And will there be any fines or cost implications of coming out of Iraq?

Thank you.

All right.

Increased oil recovery and decline rates, so we see decline developing as expected.

We estimate it to be around 5% on an annual basis.

And that has been so for many years.

And it is still the case.

There will be fluctuations from quarter to quarter on increased oil recovery.

But, we are very -- monitoring very closely the long-term trends on this one.

So, we don't see any reason to change that guiding.

However, we see a very positive contribution from increased oil recovery.

And those projects are typically very profitable to realize as well.

So, a lot of effort is put into that.

Before you start on Kilchurn, Tim, on Iraq, exiting Iraq, so that is progressing as planned.

And we see that that is progressing well.

When you come into specific issues there, I'm not ready to comment on that.

Okay.

I think your question was related to two wells in the Gulf of Mexico Statoil operate Kilchurn.

And the comment on that, it is progressing more or less according to plan.

And as Torgrim indicated, we expect to finalize that well during the second quarter.

When it comes to Kakuna, then the operator Nexen have announced that as a dry well today.

So, that means that our share of the well costs will have to be expensed in the second quarter.

Okay.

That's great.

Thank you.

Thank you.

We'll take the next question from Haythem Rashed from Morgan Stanley.

Please go ahead, Haythem.

Thank you, Hilde.

Good afternoon, all, and thank you for taking my questions.

I have three quick questions, if I may.

Firstly, just on -- going back to the cost in Q1, which I understand in some part was impacted by higher royalties there, can you give us any color or indication as to how we should see these costs progress through the rest of 2012?

Is it likely to be sort of linear in line with production increases, or is there some volatility here that we should sort of bear in mind?

Secondly, just on Johan Sverdrup, just an update there would be very helpful, particularly with regards to the appraisal program.

I -- Lundin has sort of indicated in past releases that they're unlikely to provide any updates or estimates until later on in the year.

But, just wondered from your side what the sort of latest plan was there and when you'd be ready to perhaps provide an update to the market.

And then finally, just on rig availability, just wanted to clarify with some of the upcoming wells you have, particularly Peregrino South and some of the appraisal work on Johan Sverdrup, what the rig availability was.

Do you have those rigs in place, or is that something that yet is still yet to be sort of completed?

Thank you.

All right, Haythem.

Thank you.

On -- I'll take the cost and Tim on Johan Sverdrup and the rig availabilities and so on.

So, you should expect quite a bit of the costs to be a function of production as such, but also prices.

Royalty is very much driven by prices.

So, that is something you should take with you.

When it comes to whether this is linear or not, I think it's too hard for me to say that.

But, I think it's fair to say that, when it comes to the international segments, we tend to have costs from time to time that is not directly linked to the operations, like we had in the last quarter, related to Angola and Nigeria.

We sort of make -- put aside accounting wise for claims from authorities and so on.

And that will impact the cost picture, though none of that in this quarter.

But, you should expect from time to time there to be some elements in there within the international segments.

So, when it comes to the underlying unit of production costs as such, you should expect that to -- going forward to continue to increase slightly, more or less on the -- according to inflation.

That is what you should expect and, of course, linked to production.

And you should also expect us to be a first quartile company when it comes to unit or production cost.

We were that in 2001.

We are still that and aim to maintain in such a position going forward as well.

Okay.

On the Johan Sverdrup question, then the -- our plan for going forward is we'll agree to at least another four wells, four further appraisal wells or in fact one of those will be an exploration well.

Three of those wells will be drilled in the Statoil-operated license, the PL265.

One of those wells will be to test what was previously the Aldous north segment.

So, that has the potential to prove up new or additional resources.

The two others are appraisal wells in order to reduce the uncertainty in the resource estimates, which we have for 265 and in order to gain important and relevant information for choice of our development concept.

And then Lundin plan -- have approval for one more appraisal well in PL501.

That is how it stands at the moment.

And for us, it makes sense to complete this program before we provide a new resource update.

When it comes to rig availability, we have secured rigs for the appraisal program, the three wells in the Johan Sverdrup license.

And we also secured a rig for the Peregrino South appraisal.

Great.

Thanks very much.

Thank you.

Our next question comes from Blake Fernandez from Howard Weil.

Go ahead, please, Blake.

Actually, guys, most of my questions have been answered.

The only one, I wanted to go back to Ghana if I could.

I was just curious if you could disclose the price tag that you paid in order to enter that position.

Blake, can you help me with repeating that question?

Sure.

I'm just curious if you can disclose what you paid in order to enter Ghana.

Was there any kind of financial transaction associated with that?

All right.

Tim, please?

Yes, it's a fairly simple agreement.

It's a promote on the well cost.

I'm not at liberty to share sort of the magnitude of that.

Okay.

Thank you very much.

Our next question comes from Hootan Yazhari from Merrill Lynch.

Please go ahead, Hootan.

Hi there.

I just wanted to refer back to some tax disputes or the like that you had on agreements with Angola and Nigeria, which weighed on your D&P international results in Q4.

Are these continuing to weigh, or has there been a resolution there?

And what should we expect going forward on that front?

And then the second question I had was regarding Tanzania.

Obviously, the next well coming forward there, can you give us some guidance in terms of at what stage you would look at making this a standalone development, i.e.

not necessarily having to cooperate with your partners or your peers across, i.e.

BG and Ophir and whether that's what you're aiming for right now, or are discussions with BG and Ophir progressing well there?

Thank you.

All right.

Thank you.

I have with me Kare Thomsen.

So, Kare, can you address the Angola, Nigeria question?

Yes, we had in the fourth quarter -- we made a provision by -- based on updated assessments.

And we have continued based on the same principles also in the first quarter to make the necessary provisions and the accounts as such reflect our best view also for the first quarter.

But, as you have noticed, there are no bumps or jumps in the accounts as such.

So, it's more like reflecting the quarter as such.

Okay.

In Tanzania, as Torgrim alluded to, we are now drilling our second exploration well on an independent structure called Lavani.

Our goal is to prove up sufficient volumes to be able to support the standalone development based on our own resources.

And in terms of guiding, then we expect that we will need to prove up something like eight to 10 Tcf of gas in order to support the onshore-based LNG development solution.

We are currently looking into other options for more recapacity towards the end of 2012, 2013 so that we are in the position to drill up additional targets.

And to that question, then yes, we have addressed additional targets so that we think the block has the potential to produce or to the resource base at which we need for a standalone development.

Understood.

Thank you very much.

Thank you.

Before we got to the -- what I can see as the last question on my list, maybe the operator could remind the audience on the procedure for asking questions.

Certainly.

(Operator Instructions).

Thank you, ladies and gentlemen.

Thank you.

Our next question comes from Michael Alsford from Citi.

Please go ahead, Michael.

Good afternoon.

Thanks, Hilde.

I've got two quick questions if I could.

Just firstly, given that Tim's on the line, on exploration plans for the Barents Sea, could you maybe give a follow up on the timing of I guess follow-on drilling at the [also] Skrugard and Havis and maybe a little bit more on the sort of development plans, how they're progressing, and I guess timing on those potential developments?

And then just secondly on the -- just the taxation guidance for international E&P, it seemed quite low in the quarter.

And I was just wondering if you could give a bit more color as to where we might see that charge going forward for the rest of 2012.

Thanks.

All right.

Thank you, Michael.

So, Tim, if you can answer the Barents question and the quarter on international taxation?

Okay.

If I take the Barents Sea first, I think I will have to refer you to more information on this, which is planned to be communicated on this week on Thursday in conjunction with the energy seminar in Bergen.

The tax for the international segment, we have guided 50% to 55% tax rate for the adjusted earnings.

And the guidance still remained for 2012.

We expect the tax rate over time after 2012, the average tax rate, to come down more to the level we had in the past years, below 50%.

But, for 2012, it will be in this range.

Between the quarters, we will see variances.

And that depends on many factors.

But, in short, it's the combination of -- or the composition between what you can call high and low tax regimes, which might vary over the quarters.

We will also get some -- now and then some one-off effects, like we have in this quarter.

We have one a tax case in Norway for a foreign subsidiary, which influenced the tax rate for this quarter, where you see that that's down to 37%, exceptionally low.

But, this is not a trend.

The expectation should be between 50% and 55% but might vary between the quarters.

That's great.

Thank you very much.

Thank you.

Our next question comes from Peter Hutton from -- with RBC.

Please go ahead, Peter.

Hi, thanks.

Yes, two quickies, first of all, you're talking about the flexibility on the gas volumes and selling into future summers.

Can you just confirm whether there's any commitment this summer from arrangements made previously to sort of the fixed price that was pertaining in, say, a year ago?

So, what are the already contracted volumes for, for this summer in European gas?

And the second one, in Tanzania, in the Lavani field, can you just remind me, is this targeting cretaceous or tertiary, and how does that link with the Zafarani?

Okay.

Thank you, Peter.

On the gas side and our flexibility, the commitment we have to deliver, that is towards the gas customers in a way.

If we have sold thing forwards, they are not a commitment to deliver.

You can source that in the market if you like and so on.

So, in a trading organization, they do quite a bit of transaction in the forward markets.

But, then you can actually source the gas either through the market, or you can put your own gas behind there.

So, when it comes to the flexibility strategy, there are no commitments to deliver this summer as such.

That can be sold through the market if we would like to do that, yes.

Okay.

On Tanzania then, the Lavani well is testing a tertiary target with a very strong amplitude response.

It looks very similar to the Zafarani.

But, the Zafarani is almost certainly cretaceous.

There is deeper potential on the Lavani.

We won't be able to test that with this well.

The structure is segmented.

And the plan would then be, given the discovery in the tertiary interval, that we would come back and appraise that and drill to the deeper level with the next well.

Okay.

Thanks.

Our next question comes from Nitin Sharma with JP Morgan.

Please go ahead, Nitin.

Afternoon.

Two questions, please.

There's been a strong momentum on the portfolio front.

You mentioned streamlining of portfolio.

Now that you've divested some significant chunks of assets, businesses over the last few years, how should we be thinking about the agenda on asset divestment front?

And second one in relationship to North America, now that you got a critical mass in North America, what are the next steps for you in unconventional space in that geography?

You've already given an update on assets, but more from a portfolio angle, more growth/acquisitions or focus on development now?

Thanks.

Okay.

Thank you.

First, on the portfolio management perspective, we have worked diligently over the last 10 years to streamline the portfolio, selling assets that we don't consider core, like shipping activities, the Gassled, Statoil Fuel & Retail, we are in a process with petrochemicals, and so on.

So, we will continue with looking critical at our portfolio if our money can make more use of themselves or the places in the portfolio than where does it sit currently.

So, that is something you should expect, a certain turnover in the portfolio going forward as well.

And then we use M&A and business development to acquire assets as we go on.

We do that all the time.

So, for instance, in 2011, we announced divestment or closed divestments of $10b.

And then we acquired assets for $5b.

So, this is a natural part of how we deal with portfolio management.

So, you should expect that to continue going forward as well.

Within North America and unconventionals, we are very satisfied with the three positions that we have in Marcellus gas.

We have Eagle Ford liquids, and then we have tight oil in Bakken and so on.

And then, of course, we'll always look for good opportunities to grow even further.

But, we are quite comfortable with the positions that we have.

You asked specifically about other geographies when it comes to unconventionals.

And I think it's -- there's a lot of opportunities around the world.

What is special with the US is that you can actually buy things.

You can actually transport your hydrocarbons.

And there's a traded market for it.

And there are users of the products and so on.

So, it's a very available market to grow and grow that business.

But, there are interesting opportunities other places as well.

Thank you.

Thank you.

We have two -- the two last questions, the first one comes from Rahim Karim with Barclays.

Hi, good afternoon, gentlemen.

First question was for Tim.

I think it was just a clarification.

I think last time we met you talked about testing a deeper target on the Zafarani well.

I was just wondering if you could make any comment on that front.

And then the second question was for Torgrim, just around taxes, a talk from the potential increases in the CO2 taxes the Company might be facing offshore Norway, just if you could give us any color on that and whether this would be impacting your way that you're thinking or developing some of the fast track or projects that you're looking at.

Okay.

Maybe I can take the Zafarani well.

That's -- you remember well.

In fact, we did drill somewhat deeper on the Zafarani well, not because we saw a great lot of potential there, but we wanted to check the stratigraphy below the main target.

And we didn't prove up any additional reservoir deeper.

As I just alluded to, on the Lavani well then, there are indications that there could be hydrocarbons at both levels, both in the tertiary and the cretaceous.

Okay.

Thank you.

And then on the CO2 taxes, so, the offshore in Norway, the CO2 tax, we increase from NOK180 per tonne to NOK380 per tonne.

And as an operator, we emit 9m tonnes.

Our share of that is 5m tonnes.

So, if you multiply 5m tonnes by NOK200, I think you get to NOK1b.

So, that is the pretax cost related to that new legislation.

Whether this will impact any developments going forward is hard to say.

It will, on the margin, reduce profitability of new projects and give incentives to invest in lower CO2 emissions as well.

I don't expect it to have a large impact on the development of the shelf going forward.

But, it is an additional tax that we need to relate to.

Great.

Thank you very much.

Thank you.

We'll take the last question from Teodor Nilsen with Swedbank.

Please go ahead, Teodor.

Hello.

Good afternoon.

Just first one question on the realized prices, it did imply the discount to the average Brent throughout the quarter has increased both for D&P Norway and D&P International the past few quarters.

And I guess that's related to high portion of NGL.

What should we expect in terms of the discount to the Brent price going forward?

And second question is related to Marcellus.

Torgrim, you have already mentioned that you have reduced the rig count in Marcellus, but still the production is increasing.

What should we expect in terms of production growth from Marcellus over the next few quarters?

Thank you.

All right.

Thanks.

When it comes to the realized liquids price, it is the NGL part of it that sort of explains that.

So, going forward, you should follow NGL prices and look for the content of LNG into our liquid production.

When it comes to Marcellus going forward and rig count, we had -- let me see here.

We had 36 rigs working in Marcellus by year end.

That is now being reduced.

So, we are at 24 I think, and then we should expect to be around 20 by year end, maybe 18 by year end.

So, this is according to how we should operate in the current price environment.

And that is sort of the beauty of the assets.

You can actually adjust your activity to the current price environment.

So, to us, it's important to drill to sort of keep land and keep the rights to the land.

When that is said, we have currently, let me see, 300 wells producing in Marcellus.

And then we have 400 wells waiting for completion and the gathering systems.

And those 400 wells are, as you know, extremely cheap to put into production.

So, that sits there.

So, there's quite a bit of inventory of wells there.

So, you should expect production from Marcellus to continue to increase.

Yes, thank you.

Okay.

Thank you.

Thank you.

That concludes our Q&A session and our event for today.

The presentations and the Q&A session can be replayed from our Website.

And in a few days, you'll also find a transcript available there.

If you have any further questions, please don't hesitate to contact the Investor Relations Department.

Thank you, all, very much for participating and have a good day.