Equinor ASA (EQNR) 2012 Q2 法說會逐字稿

Ladies and gentlemen, welcome to Statoil's second-quarter earnings presentation both to the audience here in Oslo and to the webcast audiences.

My name is Hilde Nafstad.

I am 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 doors in the back of the room or the one to my left and continue downstairs.

This morning at 7.30 Central European time, Statoil announced their results for the second quarter of 2012.

The press release and presentations for today's events were distributed through the wires and through Oslo's 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 on the presentation.

Today's program will start with Statoil's CFO, Torgrim Reitan going through the earnings and 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 but 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 Statoil's Chief Financial Officer Torgrim Reitan.

Okay, thank you, Hilde.

And good afternoon to you here in Oslo, and good morning and good afternoon to all of you on the webcast, and particular greetings to our good friends in London, who are gearing up for a big day tomorrow, their opening ceremony.

It is a pleasure to present Statoil's result for the second quarter of 2012, strong financial results, 17% production growth, in line with our expectations.

Yet another quarter with significant discoveries, and we keep on streamlining our portfolio.

So another good quarter, but before I get started with production and financials I want to talk about the strategic progress.

We have made two new high impact discoveries in Norway and Tanzania.

King Lear in the North Sea, this discovery is between 70m and 200m barrels.

It is in the mature areas of the shelf, just 20 kilometers from the Ekofisk field.

The Lavani gas discoveries offshore Tanzania supports our ambition for East Africa.

We now have access to nine TCF in this block.

Both are operated by Statoil.

This means eight high-impact discoveries over the last 15 months.

And then we have added new acreage including 26 new licenses in the Gulf of Mexico, and shale opportunities in Australia.

So far, 2012 has been a very good exploration year.

We have discovered more than 1b barrels of resources.

And this is actually similar to the full year result of 2011, a year where we discovered Johan Sverdrup, Skrugard and others.

We have taken steps to implement the strategic cooperation with Rosneft, signed agreement on the joint bidding for exploration in the Norwegian Barents Sea and a joint technical evaluation covering two Russian onshore assets.

The speed ahead reflects our joint commitment and determination, and it marks an important milestone in our Arctic exploration program.

We continue to streamline our portfolio.

In June, we completed the divestment of Statoil Fuel and Retail to Couche-Tard, a strong industrial buyer.

And we received NOK8.3b for our 54% share.

And this quarter we book a net gain of NOK5.8b.

And all in all we have realized around NOK20b from SFR, including their IPO proceeds, dividends and the deconsolidation of debt.

We also closed the sale of NCS assets to Centrica at a net gain of NOK7.5b.

So through these deals we have realized substantial value, and we will redeploy our capital into core assets.

Finally, we are maturing our project portfolio.

Key milestones have been set for Johan Sverdrup with a PDO to be submitted in late 2014.

We submitted the PDO for the Svalin fast-track project in the North Sea.

The government has approved the PDO of partner operated Martin Linge.

That is the field formerly known as Hild.

And we are enhancing recovery further through subsea compression at Gullfaks.

Valemon has seen its steel jacket installed, and we have taken the first steps towards development on Aasta Hansteen in the Norwegian Sea.

In Angola, the Kizomba satellites phase 1 started production on May 18, and we continue to ramping up new production.

So, we are progressing and we are moving ahead as planned.

Let's turn to production.

In the second quarter we grew our production as expected.

2012 is a year where we will see significant growth.

Well, now we are halfway through the year and we produced 1.98m barrels in the second quarter.

And this is consistent with our guidance.

And it is a 17% increase from the second quarter last year, and that means that we are on track.

Again we see growth across the board increasing both our oil and gas production, and our production in Norway and internationally.

We increased our gas production by 33%, and we also grew our liquid productions by 8% mainly through start-up and ramping up production.

But remember that we had higher maintenance effects in the same period last year, and I'll get back to this later.

On the NCS we saw an 11% total production increase, mainly through high gas sales.

And international production grew by a solid 32%, including more than doubling North American production from the second quarter last year.

When it comes to growth, let me particularly mention the Troll field in the North Sea.

Troll is the very cornerstone of Norwegian gas production.

And as you know, this is a great and flexible machine.

Troll gas increased production by 100,000 barrels per day for us this quarter, amounting to a total of 176,000 barrels.

Pazflor in Angola continues to perform well with production now reaching 44,000 barrels per day for us.

This is operated by our partner Total.

Also the Bakken area in the US is growing and it produced 35,000 barrels per day in the quarter.

We have increased the number of rigs from 10 to 16 since acquisition.

Marcellus also grows with an increase of 32,000 barrels.

On Eagle Ford we will take operatorship from the start of 2013.

Then I need to remind you of the uncertainties.

Impact -- we said last quarter that upcoming turnarounds will impact the yearly production by around 50,000 barrels.

And I expect a significantly higher impact in third quarter than last year.

In the third quarter I expect it to be around 110,000 barrels per day.

Around two-thirds are planned at the NCS and most of the effect is on liquids.

I will remind you once again about Skarv and the delay there.

Start up will be in the fourth quarter according to the operator BP.

And also please remember that the Centrica deal closed on April 30, leading to lower production of -- some 30,000 barrels per day from these assets for the rest of the year.

We will continue our gas optimization.

We have again used our flexibility on gas.

But that also means that we have taken off quite a bit of the potential.

And furthermore, gas off-take has been strong in the second quarter, so we expect gas production to be significantly lower in the third quarter.

So, to repeat from last quarter, there will be significant growth from 2011 to 2012.

The production in the first half of the year is in line with our expectations, nothing more than that.

So our production guiding remains unchanged.

And as we have repeatedly said, the risk is more on the downside than to the upside.

I will come back to our guiding on investment and exploration later.

So, over to the results, net income in the quarter was NOK27b.

This is a 2% decrease.

It is worth mentioning that we had significant gains in the second quarter last year related to the sale of 40% of Peregrino.

In the second quarter of 2012 our net operating income was NOK62b.

And that is up NOK1b from last year.

As usual, we make adjustments to better reflect our underlying operations.

And this quarter it is at NOK16b, mainly related to a gain on sales of business and assets of NOK14b and a reversal of provisions related to the discontinued part of the early retirement pension.

So the adjusted earnings before tax was NOK46b.

That's a 5% increase over last year.

Increased volumes of liquids and gas count for an increase of NOK10b.

And we see better trading results, especially in the gas area and higher prices for gas.

The increase was partly offset by lower prices for liquids and higher costs mainly reflecting high exploration activity with expensing of wells and increased DD&A due to new fields coming on stream and ramping up.

And please note that the operating expenses and SG&A is stable at around NOK21b for the past three quarters.

That is even with a growing portfolio of assets.

After tax we made NOK12b in adjusted terms.

That is down from NOK13b in the same period last year, mainly due to higher taxes.

And I will come back to that in a moment.

So let's move to the segments.

Development and Production Norway delivered NOK39b in adjusted earnings.

That's an increase of 5%.

This is mainly due to increased gas production with increased deliveries from Troll in particular.

Increased production positively impacted the results by NOK2.5b.

It is also worth mentioning that there has been limited maintenance this quarter while it was extensive in the second quarter last year.

And please remember the Heidrun redetermination where our new share is 13%.

The make-up for this correction started in July with our share at 0%.

This means no Statoil production on this field for the rest of 2012.

International Development and Production delivered adjusted earnings of NOK3b, down from NOK6b in the second quarter last year.

The increase in revenues and other income was strong from NOK14b to NOK20b and that is more than a 45% increase.

And that is driven by higher entitlement production, which alone added NOK8b.

However, this was offset by two elements.

First, higher exploration expenses, we see a NOK3.6b increase due to higher activity and from expensing.

Secondly, higher production leads to higher costs.

DD&A increased by NOK3.6b.

This is related to ramp-up of Pazflor, Peregrino and unconventionals.

Bakken was not in our portfolio last year.

Other costs increased by NOK1.7b in this segment.

And this is related to increased royalty payments and also other costs related to higher production.

Marketing, processing and renewables delivered earnings of NOK3.9b, a significant increase from NOK0.5b last year.

For natural gas earnings were NOK3.6b compared to NOK1b in the second quarter in 2011.

The increase was due to higher gas sales in addition to a positive contribution from trading activities, but partly offset by lower income due to the lower gass-led ownership share.

For crude oil processing, marketing and trading, earnings were NOK0.5b in the second quarter compared to an adjusted loss of NOK0.4b last year.

The increase was due to better trading results and higher refinery margins.

There is still a demanding outlook for the refinery business, so we will continue our improvement programs with full force.

Please notice that the results of MPR will fluctuate from quarter to quarter, and a certain part of the result will be volume-driven.

The reported tax rate was 55% in the quarter and was influenced by capital gains.

Based on adjusted earnings the tax rate was 75%, and that is somewhat above our guided range which is 70% to 72%.

And I have earlier said that you should expect the tax rate for 2012 to be in the upper part of the range, or slightly above.

And this is still valid.

The higher tax rate this quarter is explained by a higher share of earnings from the NCS, with a marginal tax rate of 78%.

But it was also caused by a higher international tax rate due to a higher share coming from high tax regimes.

And we also see some exploration costs with low tax deduction.

Then over to the cash flow.

This quarter, the cash flow from underlying operations was NOK66b.

That is up from NOK57b in the second quarter last year.

So far this year cash flow from underlying operations is NOK137b.

In the quarter we paid NOK35b in tax and we paid NOK21b in dividends.

And then we received the proceeds from Statoil Fuel and Retail transactions and the Centrica transaction.

And the proceeds from sales provided NOK15b in the quarter.

SFR is from this quarter on deconsolidated from our balance sheet.

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

In the third quarter we will pay one installment of around NOK20b and then two more in the fourth quarter.

We will continue to run with a strong balance sheet and with significant liquidity.

Adjusted net debt decreased from 15% in the first quarter to 13% in the second quarter.

We are progressing as planned, and we now expect to invest around $18b in 2012.

We will drill more wells this year.

And as we build on our exploration success more exploration costs is capitalized.

The successful outcome of the GOM lease sale also contributes to higher investments.

This will increase CapEx, but I can live with that.

We have also increased the number of rigs in Bakken from 10 at acquisition to 16.

And also some of the increase is related to faster progress than expected with the fast-track portfolio.

So they are meant to go fast, but they have actually gone even faster.

And also on other projects, on the NCS.

So this is due to higher exploration activity, exploration success, and a deliberately higher activity than earlier expected.

We will also increase our exploration spending to around $3.5b, as we increase the number of wells drilled from 40 to around 45 in 2012.

And we have an inventory of drill-ready wells that is larger than this, which can be further optimized.

And then we expect to drill 20 to 25 high-impact wells from 2012 to 2014.

I see no reason to change our production outlook.

But I have reminded you of the uncertainties, high turnaround effect in the third quarter.

We expect significant lower gas production next quarter.

Skarv is delayed until the fourth quarter this year.

And finally, the closing of the Centrica deal will lead to lower production from these assets going forward.

So we still see more risk to the downside than to the upside to our guiding.

In summary, it has been a good quarter with significant progress for Statoil -- strong financial results, production growth in line with expectations, continued exploration success, and streamlining our portfolio, putting our money where our strategy is.

So, thank you very much for your attention.

And then I will leave the word to you, Hilde, to lead us through the Q&A session.

Thank you.

Thank you very much, Torgrim.

For the Q&A session, Torgrim will be joined by Senior Vice President for Accounting and Financial Compliance, Kaare Thomsen, and Senior Vice President for Performance Management, Svein Skeie.

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

I will first ask the Operator to please explain the procedure for asking questions over the telephone.

Thank you.

(Operator Instructions).

Thank you.

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

And are there any questions?

If so, microphones will be passed.

Please state your name and your company.

Yes, I see one question.

Trond Omdal, Arctic Securities.

Could you comment a little bit on the lower realized -- or the bigger spread from Brent to realized prices?

How much is related to Peregrino and Bakken Oil and how much is related to NGL?

And on the second also, exploration expense in International was quite high, at almost NOK5b.

Could you talk a little bit of couple of wells that that is linked to?

Okay, Trond, thank you, thank you very much for two very relevant questions.

First, on prices.

You mentioned Peregrino and you mentioned Bakken, which is currently at a discount compared to Brent.

However, the volumes is fairly limited, so it doesn't have a large impact on the average realized price.

The real thing that makes an impact this quarter is the NGL prices.

And we have had high gas production in the quarter and gas production leads to higher NGL production.

And also the NGL prices, they have developed weaker than the Brent price in the quarter.

So the NGL price and the NGL content is the main explanation for that.

When it comes to exploration expense, that is especially valid in the international segment.

So this is driven by wells that has been expensed.

Two wells that I can mention here today, it is the Kakuna well in the Gulf of Mexico, Nexen operated.

And the other one is Jaguey in Cuba, operated by Repsol.

So those have been expensed.

And then there are other ones that I can't comment on from -- due to it is mainly a partner-operated wells.

So that has an impact in the quarter.

And furthermore, we have stepped up our seismic activity as well compared to last year.

And especially I would like to mention what we are doing currently in the Kwanza Basin outside Angola.

We are shooting significant amount of seismic to prepare for exploration in the five blocks that we have there and we'll come back to later on.

So that is the main explanations.

I think I would like to say that you should expect that exploration expenses are volatile from quarter to quarter.

First quarter was a quarter with very little exploration expenses, while this is higher.

So, so far this year, the average capitalization of exploration is 35%, which is a bit higher than the normal assumption that we use.

So, so far this year it's in line with what we expect, but there are swings among -- between the quarters.

(technical difficulty) a simple, while I have the chance.

You talked about Troll production being very strong.

And I assume part of it is of course that it's strong off-take from customers, but also that the production permit from NPD was higher this year.

Is there any -- of course I assume you haven't got confirmed it, but is there any reason that it should not be the same production permit for the next gas year?

So, you know the production permits are very important to us.

They are granted on an annual basis.

But I see no reason why there should be any change to the current permit.

Do we have any further questions in Oslo?

Yes, Helge Andre?

Helge Andre Martinsen, Nordea.

Just a question on the Peregrino ramp-up.

Volumes are dropping a bit this quarter.

So can you comment on when you expect to be on full capacity?

And also if you can comment on development of the water gap and oil water separation?

Is it -- is there any issues there?

Or is it running smooth?

Okay, thank you.

So Peregrino is ramping up.

We had had a few issues with some wells coming on stream.

So that is being worked.

But that has impacted the -- some water production this quarter on Peregrino.

Ramping up towards full capacity, it is within the year, is what we say, that we expect Peregrino to be on full capacity.

Okay.

If there is no further questions in Oslo, we'll turn to the audio audience.

And our first question comes from Jon Rigby with UBS.

Please go ahead, John.

Yes, thank you, Hilde.

Two questions.

The first is I appreciate that you like to give a health warning around your production outlook each quarter.

But we're now halfway through the year.

So given your more risk to the downside than the upside, how would you contrast that with your more risk to the downside than the upside in the first quarter?

Do you have greater comfort on your 2012 outlook now than you did three months ago after the impressive performance in the quarter/

The second is just on gas realizations.

I think there's been some concern that as Europe renegotiates gas pricing, that your realizations will come under pressure.

But it's not obvious from looking at the evolution of oil prices and gas prices.

When you renegotiate it, you've talked about taking back flexibility back to you from the buyer.

And I think analysts and investors have found it difficult to incorporate into their view.

Are you benefiting from that?

And if you are, can you go through how that might be helping you in terms of your effective realizations as you trade and sell gas?

Thanks.

Okay.

Thank you, Jon.

Production outlook halfway through the year, yes, production so far this year has been strong.

For me it's important to give some granularity to the drivers of the production and it's also important for me to get across that in the next quarter production will be lower than what we have seen in the second quarter.

So there is no new signals, no new messages in what I've said today.

It should be the exact same wordings that has been used over the last quarters.

But things are progressing as expected.

Things are progressing as planned.

And there are still uncertainties in place especially related to customer off-take on the gas side.

If they end up taking more than they have to it will certainly have a positive impact on the production.

Maintenance, if that runs smoothly, is also -- also everything is risk related to that.

And then we have start ups over the year.

We have Skarv in the fourth quarter, BP operated, which is the main one to watch in that respect.

So there are -- it is the same risk elements that has been in place, but we are half through the year.

But I still consider there to be more risk to the downside than to the upside of our production guiding.

Then on gas realizations, you are right.

We have been through a period of renegotiations of our gas contract portfolio in Europe.

In those renegotiations, it has been very important for us to say, one, yes, we are willing to put more spot indexations into the contracts.

But it needs to come together with that flexibility, comes back to where it belongs and also access to the hubs.

So the market is developing towards a more liquid market.

So it will mean that the seller sits on the flexibility on the Gas volumes instead of the customers going forward and it provides us with significant flexibility to decide which market the gas should end in and also which period the gas should end in the market.

And this has from time to time significant value to us.

And it has had good values from -- created good values from us over the last year.

But I can particular mention in 2009 when the gas markets more or less collapsed.

Prices dropped from 70p to 20p per therm.

We elected to tune down production in the summer and sell it into the next summer at 40p per therm.

So realized a 100% gain on those volumes.

And that was based on the flexibility that we had and the customer didn't.

So it's just an example on how we use this tool.

And we have some really fantastic, big assets that are flexible.

Troll you can look upon as a seasonal storage.

Oseberg you can look upon as the world's short-cycled gas storage.

So effectively you can see -- would it be fair to conclude that you're seeing that the flexibility is compensating, or at least compensating for what would ostensibly be, at current prices, a lower realized price in the new contract structures?

So net-net you're at least coming out neutral --

I cannot --

-- (multiple speakers) seems to be the case.

No, I cannot give specific guiding in that respect, but there comes a value out of the flexibility that we carve back.

Thank you.

Thank you.

The next question comes from Brendan Warn from Jeffries.

Please go ahead, Brendan.

Thank you.

This is Brendan Warn from Jeffries.

Just -- actually, it's probably on the same topic in terms of production.

I was just wondering if -- obviously because of the rate of growth from the international division, if you can give us some sort of exit rate indication.

And maybe if you split it out international from North America.

Just, secondly, too, obviously in light of BG making some non-cash impairments of their US gas shale business, Torgrim, just see if you can make any comments on what you're carrying for your gas assets in the US.

And do you see anything similar that Statoil may be doing?

And just, lastly, just while we're on North America in terms of gas price and rig count, if you could just step through and tie us back to the production rate rig count in your various regions back in Marcellus, Eagle Ford.

Thank you.

All right, Brendan.

Thank you very much.

When it comes to production from the various assets there is in the supplementary package, which is on the Web, you see a break down on an asset-by-asset level.

So it is all there.

But I think it's fair to say that the US production, the North American production has doubled.

International in total has grown by 32%, so it's a significant contribution to production.

Then over to the US and gas prices and shale.

I can, of course, not comment on BG's accounts, but I can comment on how we look upon that asset.

And I reviewed the production profile for Marcellus a few weeks back and I certainly recognized that when I'm 100 years old this asset is actually still producing on plateau.

So this is here for the long term for Statoil.

Current gas prices in the US is low and in a situation with low prices it is extremely important to take care of your gas.

And I'll give you a couple of examples on what we are doing in Marcellus.

From October 1 we will start selling Marcellus gas into the Toronto area.

Toronto has over the last quarters been priced $1 per MBTU higher than around the Marcellus area, so it's a significant premium market to the area around Marcellus.

And in 2009, I think it was, we took all the capacity at National Fuel to get to Canada, at, I think it was, $0.11 per MBTU to get to the border.

So from October 1 we will realize a higher price on our gas in Marcellus than the alternative was.

And I would also like to mention that we are working on a pipeline solution to Manhattan.

We will cross the Hudson River, first, crossing over with a gas pipeline for 40 years, come up at Penn Station and connect to Con Edison's grid, realizing significantly higher prices.

So this is very much about taking care of your gas, and we are that, and we test -- we test the Marcellus asset regularly for impairments.

And it sits solidly in our balance sheet as it does.

When it comes to gas price outlook I think we must be prepared for low prices for a couple of years more.

We are, but we are not into the Marcellus for 2012 and 2013.

We are in Marcellus for the next decades.

But then I think there are some significant forces in place that will bring this back to more sensible levels.

Then you asked about the rig counts and so on and so on, as I said, we have increased the rig count in Bakken from 10 to 16, progressing well there.

In Eagle Ford we have 11 rigs going or Talisman has 11 rigs going.

On Marcellus we have taken down the rig count down to 15; it was 27 at first quarter.

And when it comes to wells we have a lot of wells producing, more than 180 in Bakken, more than 100 in Eagle Ford and more than 400 in Marcellus.

And the inventory is also significant.

So there's a lot of wells, for instance, in Marcellus, more than 400, waiting for gathering systems and hooking up and that can be done extremely cheap.

So there is more to come and we are looking forward to that.

Thanks, Torgrim.

We'll take the next question from Michele Della Vigna of Goldman Sachs.

Please go ahead, Michele.

Thank you for the presentation.

I had two quick questions.

The first one is, after your successful disposal to Centrica would you consider more disposal of mature NCS assets?

And then the second one is regarding Tanzania.

You clearly had a lot of exploration success there.

And I was wondering how quickly you can proceed with a feed for an LNG plant and whether you've got ongoing dialog to other players there to join forces.

Okay, thank you, Michele.

Centrica transaction, significant value created out of that.

Further portfolio optimization is a natural part of what we do; we do it all the time.

I think in 2011 we had eight transactions on NCS and several internationally as well, so you should expect further streamlining of the total portfolio and also our NCS portfolio going forward.

And we would like to send our money into where we can make the most impact with the money into the core assets and where we want to be.

So that is just a natural ongoing business.

There's nothing special to it than a continuous portfolio optimization.

When it comes to Tanzania I think it's too early to conclude on what will happen when.

We have made two significant discoveries in the block.

There are -- this is a huge block.

There's several other structures that we would like to test, so this is something we would like to work further before we conclude on how to proceed.

And, as you pointed out, it is natural to discuss with other companies in the areas on how to optimize the area.

Thank you.

We'll take the next question from Kim Fustier of Credit Suisse.

Please go ahead, Kim.

Yes, hi, good afternoon.

I had two questions, please.

Firstly, just on CapEx, you've guided to a $1b increase, to $18b versus your previous plan, so half of that is coming from exploration and, presumably, the other half from development.

I was wondering if you were able to say on which projects you're spending more development CapEx, or is this really just to higher CapEx on maintenance?

Secondly, on international D&P you've talked about higher operating costs coming from field ramp-ups for quite a few quarters in a row now.

I was wondering how much of this OpEx increase is structural and how much you see falling off going forward.

Thank you.

Svein, maybe you can prepare on the CapEx question.

When it comes to the operating cost internationally, it is related to increased production.

A couple of examples, royalty has increased due to higher production.

So royalty is normally a function of production and price, and the higher the royalty the more you earn, so that is cost that we think is okay that increases.

Then within international there are some increased transportation costs.

And it is also related to more wells producing, especially within the unconventional area.

So it is structural in a way that it is directly linked to higher production and better earnings.

On the increase in CapEx, we increased the capital expenditure for -- from around $17b to around $18b and it's coming partly from the exploration, as you mentioned, due to the fact that we also then increased the guiding for the exploration activities from $3b to $3.5b.

In addition, it's high activities on the Norwegian continental shelf, as Torgrim mentioned in his presentations on project, the fast-track projects, but also on other projects where we see that we have better progress than we planned for.

In addition, I would also like to mention the successful outcome of the sale -- the lease round in Gulf of Mexico where we have then acquired 26 leases in the Gulf of Mexico, which also then contribute then to the capital expenditures for 2012 and that are the main reason why we increase.

So around 50% of the CapEx increase will be from Norway and the rest from the international part of it.

Great, thank you.

The next question comes from Michael Alsford from Citi.

Please go ahead, Michael.

Thanks, Hilde.

Good afternoon, two questions if I can.

Firstly, just actually following on from that CapEx question, could you maybe more specifically give us an indication of what the cost inflation you're seeing on the NCS for the service industry?

And then, secondly, maybe could you give an update on Shtokman.

A lot of press reports obviously over the last weeks.

And I know that obviously the frame agreement expired at the end of -- I think end of June.

So could you maybe give an update as to Statoil's position on that project?

Thanks.

Okay, I'll take the Shtokman and, Svein, you can continue with the CapEx issue -- or CapEx question.

On Shtokman you are right, the framework agreement with SDAG expired, so that is true.

We are continuing the negotiations related to Shtokman, so those negotiations are progressing.

For us it is very important that investment levels come down to a level where we see a significant profit from the project.

It is also important that a fiscal framework are put in place so it is -- becomes a sound project.

And there are also some other commercial terms.

So negotiations are ongoing more or less on the same parameters that we have discussed among ourselves over the last period.

So we are still negotiating.

Thank you, Torgrim.

On the NCS the main increase is then related then to a higher activity level.

And if you look at the pressure in the industry, yes, there is pressure, but we are responding to that.

I will, for example, mention what we have done within the drilling segments, where we have gone into long contracts for Cat B rigs, dedicated well rigs that could drill wells on the Norwegian continental shelf so that we are able, then, to take down the expected cost for that going forward.

And that we're also seeking in other segments where we see pressure, trying to find good solutions between us and the supplier, going for contracts where we see that we can add benefit both for us and the supplier.

Okay, thank you.

The next question we'll take from Teodor Nilsen of Swedbank.

Please go ahead, Teldor.

Good afternoon.

Just a question on the increased exploration guidance.

Where will the increase or the incremental increase in exploration spending come from?

Will it be in Norway or internationally?

And also a question on the tax rate.

You have said that the 2012 tax rate will be in the upper rate or end of the guided range.

What can you say about the 2013 tax rate?

Okay.

On the exploration guidance, more wells will be completed and more wells will be started during 2012.

It is pretty well distributed across the portfolio.

It is both in Norway and internationally.

So if there are something to mention, we will start a new campaign around the Skrugard and Havis discoveries and that campaign will be started off in the back end of this year.

Further appraisal programs around Johan Sverdrup as well.

And then there are other exploration wells as well.

But this is -- it is fairly spread around.

Tax, Kaare.

Yes, year to date, we have 73% tax on adjusted earnings.

And we have guided 70% to 72% in the upper end of it for 2012.

And we still maintain that guidance.

And you should also foresee similar guidance for the year of 2013.

Okay.

So you do not expect that the tax rate will decline as international production builds up?

Not in 2013.

But as we progress, we expect the tax rate from the international part to come down to the previous level, which we guided on, between 40% and 50%.

Now we guide on 50% to 55%.

And it has to do with the composition, from where we get the taxable profit, what's -- the tax structure in those countries.

And as we see it, at least in 2013, it will be more or less the same composition.

But later on, we expect it to come down, more to the level we indicated or had before.

Okay.

Thank you.

The next question will come from Oswald Clint of Sanford Bernstein.

Please go ahead, Oswald.

Yes, thank you.

My first question is just on the ACG field in Azerbaijan.

It's showing a sort of steady decline over the last year and a half.

It's a good 10% of your international portfolio.

I just wonder.

Is that decline in line with your expectations?

Again, I think you're pointing to well problems, operational problems there this quarter again.

I just wondered if you could talk about that particular asset.

Secondly, on the Bakken, you've talked about the number of rigs you have and the number of wells you've drilled.

I'm just curious to know, with all the new wells you're drilling, are you still seeing the same healthy flow rates or the initial production rates?

Is there nothing there, or at least everything is consistent with, again, with what you saw at the very beginning of the acquisition?

And finally then, just on your oil -- onshore assets, you're participating with Rosneft in Russia.

Could you give us a sense of activity levels or what the next couple of steps are, in terms of appraising that onshore asset?

Thank you.

All right.

Thank you, Oswald.

On ACG, producing well, there has been some issues with wells.

It seems to improve and be working well.

But BP is the right one to answer on that progress, as the operator.

On Bakken, initial production rates are good.

And as expected, it varies, like it is expected.

But it is progressing as it should.

Maybe, when I have an opportunity to talk about Bakken, is that evacuation or marketing of the oil is an important part of creating value out of that asset.

We are taking on train capacity.

That will be available to us from October.

So then we will narrow the discount that we have seen from that asset in this quarter.

When it comes to the onshore part of the Rosneft deal, it is actually very interesting, if you look at the potential on unconventionals in US.

So we have two areas we have access to.

And we will first study and work on a technical program related to it.

And then we will progress from there.

But it is pretty obvious that this is hydrocarbons with a potential -- with a high potential.

So we're looking forward to further exploring those opportunities.

Okay.

That's great.

Thank you.

Our next question comes from Haythem Rashed of Morgan Stanley.

Please go ahead, Haythem.

Hi.

Good afternoon, all.

Thank you for taking my questions.

Just very quickly, I wanted to touch base on three things.

Firstly, on CapEx for 2013, I just wanted to ask if you had any comments you could make there, in particular with regards to the fact that obviously 2012 has been increased.

And in the past you'd indicated that 2013 was likely to be similar to 2012.

So should be expect a similar increase for 2013 CapEx levels?

And secondly, on production guidance, you've clearly highlighted the downside risks on production into the second half.

I just wondered if you could give us a sense of which are the most significant of those three that you talk about, perhaps even if you could rank them, in terms of the gas value volume, the startups and ramp-ups, and also the maintenance.

And then thirdly, just wanted to quickly ask, on the five extra wells to be drilled this year, could you indicate if any of those are high impact?

Or in other words, have you shifted any of the high-impact wells to be drilled over the next two years into this year?

Thank you.

All right.

Thank you Haythem.

On the CapEx for 2013, we will refer to that later.

What is important for me to talk about, when I talk about CapEx, is the project portfolio, more than 150 projects, average breakeven price of $50 per barrel.

We are all set to deliver 2.5m barrels per day production in 2020 from these set of projects.

And I'm always becoming very enthusiastic when I talk about our project portfolio.

But you have heard it before and I'm sure you will hear about that later on, as well.

When it comes to the CapEx development going forward, I can give you some color to it.

And that is that what we have seen over the last years is a CapEx increase, related to increased activity, more projects being developed and not related to cost inflation or cost overruns.

When that is said, we will always have some projects which are doing better and some projects that doing worse, but on an overall level, not a part of the explanations as such.

So we have a large project portfolio that we would like to realize.

And of course the set of projects will cost money to develop.

And that will be reflected in the investments going forward.

For me, it's extremely important to have a firm financial framework around our investment program, meaning a solid balance sheet, meaning a predictable dividend and strict decision criteria around this.

So this will be managed in a very diligent way.

But we will come back to that very interesting issue at another point in time.

When it comes to production guidance and main uncertainties, I think it's fair to say that on top of the list, it is gas production that is the main uncertainty.

So that is the one that is the main uncertainty.

When it comes to high-impact wells, going forward, there are two wells that I would like to draw your attention to in the 2012 drilling program.

It is the Brugdan II well in the Faroes that has already been spudded and it is the Bioko well in the Gulf of Mexico that has also been spudded.

So those two are the most imminent wells to watch.

Furthermore, in the Gulf of Mexico, we are working to acquire or to get a permit on the Candy Bar, which we -- when that is in place, we are ready to move along with that one as well.

So those are maybe the few that I would like to highlight.

So thank you, Haythem.

Thank you.

We'll take the next question from Rahim Karim with Barclays.

Please go ahead, Rahim.

Hi.

Good afternoon, Torgrim.

Just a couple of questions.

The first was just around potential progress in Angola, in the presalt there and if you could perhaps give us an update on how seismic is progressing there.

And then the second question is on the finances.

Perhaps you could give us some guidance, in terms of where we actually expect gearing at year end to be, given the divestment processes that we've seen completed so far.

Thank you.

Thank you.

Seismic in the Kwanza Basin in Angola is progressing well.

There are significant -- it's a big area.

So it takes its time to get it shot.

So when that is done, we will of course work the seismic extensively and prepare ourselves for starting exploration, which we expect to be late next year or early 2014.

So progressing as planned in Angola, in the Kwanza Basin.

When it comes to financing and gearing -- so our net debt rate is at 13%, currently.

It came down from 15% in the second quarter.

And at year end, it think it was 21%, if I recall right.

So it is moving down.

Towards the end of the year, it will of course be very dependent on the oil price development for the rest of the year.

So if oil prices are at a $110 to $115 level that we saw in the end of first quarter, this will come down to around 10-ish, that we talked about at that point in time.

So that is the framework around that one.

When that is said, and as I said earlier, it is extremely important for us to, in the current market uncertainty to run with a solid balance sheet and also run with a significant amount of liquidity and prepare ourselves well.

So we work with several scenarios that we have talked about for the world, to be as prepared as we can.

Okay.

Thank you.

We have one more question from Nick Coleman with Argus Media.

Please go ahead.

Thank you.

Just a question about the industrial action that we've seen this year in Norway.

I presume the impact on production would be extending into the current quarter.

Can you say whether the Oseberg output is now back to normal after the industrial action?

And give any assessment of what the impact has been, in terms of production and your views on any possible recurrence of industrial action later in the year.

Thank you.

First of all, it is very important to us that we are able to solve differences between the Company and the employees, on an ongoing level.

This time it ended up in an industrial action.

The impact of that, we will have to get back to you in the next quarterly result.

But it has been limited in production terms, so not impacting the overall picture significantly.

What was said earlier, that the total impact of the strike was some NOK3b for the NCS at totality -- as a totality, pre-tax.

That was statements from the OLF, which is one of the organizations that faced the negotiations.

Whether this is a further risk going forward is hard for me to comment on it.

To me it's important that we're able to solve the differences that we from time to time have, and do that in the best possible way.

Thank you.

Could you just clarify if the Oseberg production is back to normal?

Yes.

So Oseberg is back and available, as it should be.

Thank you.

We have another question from Kristine Beese from RBC.

Please go ahead, Kristine.

Yes, hi.

Good afternoon.

I was wondering if you could give some color around the NOK2.5b financial item charge.

Yes.

Thank you.

On that, it is higher than normal this quarter.

And it is related to the accounting treatment of the Shtokman investment in the SDAG.

You know, as we said, that the framework agreement expired.

We handed back our shares.

And from an accounting perspective, we have to take the value down of those shares.

So that is explaining the financial charges.

So that is impacting the quarter as well.

So we have -- so that is from, the way we deal with it from an IFRS point of view.

And then we have taken the necessary steps to protect our positions, as we should.

And we are continuing the negotiations for the future of the Shtokman, together with Gazprom.

That was the final question on my list.

So this will conclude our Q&A session for today.

But the presentation and the Q&A session can be replayed from our websites in a few days.

And transcripts will also be available.

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

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