Equinor ASA (EQNR) 2014 Q2 法說會逐字稿

(Audio in progress).

-- here in Oslo and to our audio and webcast participants.

My name is Morten Sven Johannessen, Vice President, Statoil Investor Relations.

This morning at 7.00am CET Statoil announced the result for the second quarter of 2014.

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 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.

Today's program will start 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.

We will aim to end the conference at 2.30pm Central European Time.

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.

Thank you, Morten, and good afternoon and welcome.

I'm glad to report another quarter with solid operational performance.

In short, we continue to produce with high regularity, new production is coming on stream, we progress our projects on cost and schedule and our extensive turnaround program is running as planned.

In the first quarter we delivered adjusted earnings of NOK32b.

The result is impacted by divestments we have made, seasonal effects and lower gas prices.

After-tax earnings were NOK9.9b.

Earnings per share were NOK3.75, up from NOK1.38 last year.

Cash flow from operations before tax is NOK118b year to date.

And we maintain good cost control and strong capital discipline.

Our organic CapEx so far this year is $10b and our guidance for the period 2014 to 2016 is around $20b per year.

This quarter we have used our flexibility in Troll and Oseberg and moved gas volumes into future years to create more value.

This impacts production, earnings and DD&A per barrel in the quarter.

However, even after moving gas the strong operational performance gives basis for maintaining the 2% growth from the 2013 re-based level.

Our exploration -- on exploration the highlight this quarter is the Piri gas discovery in Tanzania.

This brings estimated gas in place in block 2 to 20 TCF.

After Piri we drilled the Barents Sea well, which was a minor technical gas discovery, and now the rig has been moved to the [Giligiliani] prospect.

And, finally, the dividend for the second quarter will be NOK1.80 per share, as we have moved from annual to quarterly dividend payments.

This will be paid in in November.

The dividend for the first quarter will be paid in August.

This level of dividend will be maintained also in the third quarter.

The level for the fourth- quarter dividend will be announced in 2015.

Our reported net income was NOK12b, up from NOK4.3b in the second quarter last year.

The increase is mainly due to changes in net financial items.

Net operating income was NOK32b in the second quarter, but, as always, we make adjustments to reflect the underlying business.

This quarter the divestments of a share in Shah Deniz in Azerbaijan results in a gain of NOK3.6b.

And we have also taken an impairment of NOK4.3b primarily linked to goodwill in the US onshore.

As you know, unconventional resources have quickly taken an important role in the world's energy markets.

We entered early into positions.

We now have operatorships in three US fields.

We are positioned in good assets in the most attractive place.

Our production is going well and operational the improvements are coming as planned or better.

Our onshore business is profitable today and we expect the profitability to increase.

We are making the operations more efficient, drilling and completion -- drilling and completing wells faster and working to take out value in the whole value chain.

At the same time we see that the local prices in the short term are lower than what we had expected.

The impairment this quarter is mainly due to that we now see a sustained period with large price differentials.

This is due to delays in infrastructure development especially related to Bakken and Marcellus.

We are continuously working to increase the value of our production, as you have seen through the rail capacity to transport oil from the Bakken area and the pipeline capacity, which enables us to sell our gas to higher prices in Toronto and Manhattan.

After adjustments earnings were NOK32.3b.

The result was impacted by lower production.

This is as expected and due to divestments, re-determination on Ormen Lange, higher turnaround effect and gas optimization.

Decline was as expected, around 5%.

This effect is more than offset -- more than fully offset by ramp ups and new production.

Gas prices in Europe have dropped and we continue to see low US gas prices.

The increasing cost is mainly due to activity-driven elements like transportation and royalty.

And in addition we see an impact from higher turnaround activity, some increased pension cost and costs related to gas injection.

These effects you will also see in the third quarter of this year.

We have previously guided increased DD&A over time and this quarter we see a higher unit DD&A cost.

This was driven by new fields coming on stream and the ramping up, but also by the composition of production.

Troll and Oseberg both had very low unit DD&A.

So when we use the flexibility to take down production at these fields the DD&A per barrel will increase.

This will also impact unit DD&A in the third quarter.

For the year as a whole we expect it to be somewhat higher than in 2013, as we have previously stated, and lower -- let me see -- yes.

For the year as a whole we expect it to be somewhat higher than in 2013, as we have earlier said, and lower than the second-quarter numbers.

Our field cost remained stable.

After tax we delivered adjusted earnings of NOK9.9b.

The tax rate was 69%, which is slightly lower than the guided tax rate.

Tax is impacted by the higher share of international earnings.

We continue to expect a tax rate for the year of around 70%.

And the tax rate is expected to stabilize below 70% in the coming years as we increase our production in the US and Canada.

In the second quarter we produced 1.8b -- 1.8m barrels per day.

In Norway we continue to see strong regularity.

The reduced production is due to divestments, increased turnaround effects, re-determination of Ormen Lange and gas optimization.

We continued to increase our production in our international portfolio, but please note the following for the rest of the year.

We expect to continue moving gas.

Around 30,000 barrels per day in total will be moved -- we expect to be moved out of 2014 and into future years.

The movement of this gas typically happens in the second quarter and the third quarter.

So the quarterly effect is, as you understand, much larger than 30.

We will continue to ramp up fields.

In the second half we will put two fast- track projects on stream.

We expect to see Valemon in production by the end of the year.

And next quarter NCS production is expected to be around the same level as this quarter due to low gas production and high planned maintenance.

Then let us take a look at the segments.

From our Norwegian upstream business we delivered adjusted earnings of NOK24.1b.

The decrease was mainly caused by the lower production, as explained.

Costs were impacted by turnaround activity, new field startups as well as higher pensions and injection gas.

The field costs remained stable.

From our operations outside Norway adjusted earnings were NOK6.3b, which is up NOK0.4b.

We increased our equity production by 1% as we ramped up Angola fields and continued ramping up in the US.

Revenues were positively impacted by higher oil and gas prices and lower exploration expenses.

This is partly offset by higher operating cost related to transportation and to royalty as production grows.

The results from MPR were NOK2.4b.

We saw good results from our European gas business.

We continue to see good contribution from our LNG business.

And the second quarter saw an improvement in the trading of gas liquids over the same quarter last year.

However, the refinery margins are still weak.

So to the cash flow year to date.

The cash generation continues to be strong.

Cash flow from operations after tax is NOK68b, or $11b.

We paid the full-year 2013 dividend of around NOK22b and we received proceeds from SOCAR and BP for the sale of 10% of our stake in Shah Deniz.

Cash flow to investments was NOK62b year to date, leading to an organic investment of around $10b.

Our net debt to capital was 16%.

The first-quarter dividends will be paid end of August with around NOK5.7b.

And we expect gearing at the year end to be around 20%, in line with earlier guiding.

So we continue with a firm financial framework and a solid balance sheet.

So our efficiency programs are progressing.

We are well under way and start to see the effects.

Our staff and services functions have been reduced by a headcount of around 1,000 people.

We have identified further potential for manpower reductions in the range of 1,100 to 1,400 positions in staff and in other functions.

We are already competitive -- very competitive with regards to OpEx and SG&A.

And these programs will further enhance our competitiveness, resilience and profitability.

The technical efficiency program consists of six specific projects, first, end-to-end well delivery reducing drilling cost by standardization and planning.

So let me give you an example.

At Oseberg East we recently drilled a well in 83 days versus the plan of 146 days.

We did this by avoiding time-consuming sidetracks, a breakthrough in planning and execution for this type of well.

And if you look at the result so far this year we see an impact of 15% within drilling and well.

Then, secondly, strengthening the early phase, ensuring the right solutions and developing lean concepts; another example.

We have placed frame contracts early with Kvaerner for the Johan Sverdrup development to standardize the delivery of steel jackets and reducing engineering cost.

Third point, standardization and industrialization, reusing concepts and taking advantage of synergies and scale; our fast-track projects demonstrate that this works.

And we are working on three more projects; operations, maintenance and modifications excellence, improving planning and execution; working even closer with suppliers to take out synergies and aligning incentives; and finally we will continue simplifying our work processes.

Work has started in all of these programs and I follow it very closely from my organization.

It is still early days, but I am satisfied with the progress.

This will translate into higher returns and better profitability.

And I will revert with an update on progress at our capital markets day in 2015.

So we expect to deliver annual savings of $1.3b from 2016.

We have reduced our gas production, but we maintain our guiding for a production growth of 2% from our 2013 re-based level.

This is due to strong operational performance in the first half of the year.

New fields will also contribute to this growth, Gudrun, the fast tracks, and, towards the end of the year, the Valemon field.

We plan to invest around $20b this year.

However, this will require hard work from ourselves and in our partner-operated projects.

We deliver projects on time and cost.

We continue with a high exploration activity, around $3.5b.

We expect to complete around 50 wells.

We have spudded the Dilolo prospect in the Kwanza Basin in Angola and the Martin prospect in the Gulf of Mexico, and the Mercury well in The Barents.

Later this year, [Bay de Verde] in east coast Canada will be drilled.

And in total we will drill 20 high-impact wells during 2014 to 2016.

We are in the middle of an extensive maintenance period.

For the full year we expect a maintenance effect of around 50,000 barrels per day, for the third quarter around 60,000 barrels per day.

Out of this 50% will be liquids and 60% will be on the NCS.

So, to round off, we deliver strong operations and cash generation.

We are well under way with our improvement program and we maintain our guiding.

So thank you very much for your attention.

And then I'll leave the word to you, Morten, to lead us through the Q&A session.

Thank you very much, Torgrim.

We will now turn to the Q&A session.

Torgrim will be joined by the Senior Vice President for Performance Management and Risk, Svein Skeie, and Senior Vice President for Accounting and Financial Compliance, Orjan Kvelvane.

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

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

Please.

(Operator Instructions).

We will start with questions from the audience here in Oslo.

Please state your name and the name of your company.

Remember to push the button on the microphone in front of you down whilst asking your question and then release the button when you have finished.

We will now have the first question from the floor.

No?

I think we can just progress to the telephone.

First question on the telephone, please.

Mehdi Ennebati, Societe Generale.

Hi, good afternoon all.

So I will ask two questions, the first one regarding your 2014 production growth target of 2%.

What European natural gas spot price level do you need in Q3, and particularly in Q4, to realize your 2% production growth target for full-year 2014?

Knowing that quarter to date we are at around $6.4 per mBtu, meaning a four years' low, and I don't think that in Q4 2014 we will go back to Q4 2013 levels of $11 per mBtu.

And my second question relates to the potential share buyback program.

You have announced that additional asset disposals might lead to share buyback from 2015.

I would like to know if European spot prices remain depressed next year as well you shouldn't give up the idea of returning cash from asset disposals to shareholders.

Or do you think, on the contrary, that your operating free cash flow generation next year, even if gas prices remain depressed, will permit you to return cash from asset disposal to shareholders?

Thank you.

Right, thank you very much.

So on the 2014 production growth, we had decided to reduce our gas production and that has happened in the second quarter.

And in our expectation we see that continuing also through third quarter.

So the total effect for the year is 30,000 per day.

And that is embedded in the guiding and it reflects the current market situation in Europe with gas prices during the full summer.

So we are not dependent on strengthening of gas prices to deliver on the production guiding.

We see improved regularity in our operated fields and that contributes positively to production.

So one percentage point better regularity is 10,000 barrels per day to 12,000 barrels per day on an annual basis.

When it comes to share buybacks we intend to use that more actively going forward.

It will be linked to divestments.

It will be linked to the free cash flow situation and financial situation of the Company.

At the capital markets day in the winter we said we want to have a strength of the balance sheet in the range 15% to 30% net debt, so it is in that -- in that framework that surrounds the share buyback program.

But you are absolutely right, we have a clear intention to use that more actively going forward.

Next question, please.

Michael Alsford, Citi.

Thank you.

I've got a couple of questions, please, a little bit related to the gas sales -- or gas demand question earlier.

I just wanted to pick up on your comments relating to the fact that you said that you are going to achieve stronger margins in European gas sales in second quarter.

It seems when looking at the numbers it's simply a reflection of what was a lot transfer price in the DP Norway division.

Could you maybe explain the effect of this and perhaps how you see the outlook for trading profitability into the second half of 2014?

The second question was just on your comments around potential cost efficiencies versus your guidance of targeted annual savings of $1.6b.

Could you maybe give a sense as to what the impact will be in 2015?

I know the $1.6b is from 2016, so what will be the impact in 2015?

And perhaps could you give some quantifying color percentage wise, perhaps, around where you see the additional savings that you mention in your prepared remarks?

Thank you.

Okay, thank you, Michael.

On your first question, the MPR result is good, fair.

Margin on the gas sales is -- you are right.

It is linked to the margin they get on the sales.

The transfer price is linked to market prices for gas in Europe and other places.

And what they can achieve on top of that remains in the MPR segment.

So they keep the exposure to renegotiations of gas contracts and all of that within their risk.

So it is of course an effect of the internal price as well.

But as long as they beat the market it's [performance] in the MPR segment.

From a quarterly basis I think it's very difficult to give indications.

A couple of things I can highlight.

In the second quarter we had five cargos from Snohvit.

Snohvit has been out in maintenance in the quarter.

And in the next quarter there will probably be more cargos that will generate profit in that segment.

But you should be prepared that it fluctuates from quarter to quarter.

And a normal quarter is between NOK2b and NOK4b as we see it.

Cost efficiency, the effect is estimated in 2016.

We already see some impact for 2014 and then it will grow towards 2016.

We have not given specifics in -- for 2015, but it is natural to expect that this is gradually building towards 2016.

Thanks, Torgrim.

Just on the incremental potential?

Related to the efficiency programs?

Exactly.

[I] mentioned that you say you've spotted additional opportunities to save costs.

I was wondering whether that was, [in terms of] quantum, how much more than the $1.6b that you've guided to currently could we see in later years?

Thanks.

The potential we have identified is larger than what we have communicated, as we said at the capital markets day.

And it's a significant potential.

So it will be linked to the six projects that we have estimated.

And also the -- if you look at staff cost, the manning, we have also identified additional potential.

You will typically see the effect of that into the SG&A costs as well.

Okay, thanks very much for your answers.

I think it's fair to say that even if we see a big potential this is fundamental changes that takes time to implement.

And we said the $1.3b in 2016 is what we are committed to deliver.

Next question on the telephone, please?

Haythem Rashed, Morgan Stanley.

Thank you.

Good afternoon, gentlemen.

Thanks for the presentation.

Two questions from my side, please.

Firstly, you've talked quite clearly about D&P Norway and the effects we've seen in 2Q, but also what we might expect in the second half of the year.

I wondered if you could just provide a bit of color on the international business and how you expect profitability to evolve in the second half there.

For example, what sort of effect CLOV is expected to have on DD&A in the segment?

And do you see any potential headwinds for the segment on DD&A side in 3Q as well?

My second question relates again to the cost and capital efficiency program.

And thanks for the update on that and the slide in the presentation.

Perhaps if you would be able to provide any color around more the CapEx moderation side of things?

You've talked about some of the opportunities you've identified on the OpEx and SG&A side.

I'm thinking particularly, aside from Johan [Castberg], are there any other examples of projects which you've delayed, or where you've made the decision not to go ahead with that are likely to impact the CapEx side of things in the last couple of months?

Anything that you can provide there would be very helpful.

Thank you.

Thank you very much.

On DPI over the next quarter there will be a maintenance.

New production from Angola CLOV will typically have a high DD&A per barrel, so it will impact the numbers.

[You can have] more specifics there, please, afterwards.

When it comes to the cost efficiency and CapEx moderations we have made significant changes to the CapEx program and projects.

And we are constantly working on prioritizing in the portfolio.

We come from a position with a lot of opportunities to choose from.

And the best one will be selected.

It is, however, important to make that decision as early as possible, before the project is matured too far, so the decisions we have made lately doesn't typically impact the 2016 CapEx but addresses the period beyond that.

However, we [are] constantly work across the whole portfolio to see what else can be taken out from CapEx, and that is progressing well.

Torgrim, as we said, CLOV has started up and with the fields which are in the start ups and ramp ups we typically have higher depreciations due to the fact that they're not booked at a high amount of proved reserves on the field.

So it is a strong cash flow from the fields that we are building up, but it's affected by then the higher depreciation in the early days.

Also towards the end we also then expect start ups in (inaudible) for some fields, but that is coming then also then towards the year end.

Thanks very much.

Next question on the telephone, please.

Guy Baber, Simmons & Company.

Thank you.

You guys mentioned a number of times the continued strong production regularity on the Norwegian continental shelf, so I wanted to dig a little bit deeper there.

But I was just hoping you could discuss maybe in a little bit more detail the recent underlying trends in CS with respect to uptime and reliability.

And can you quantify the scale of improvement you've seen?

I'm just trying to get a better understanding and better appreciate that improvement just because it seems to be pretty significant.

And then, secondly, I was hoping to get an update on the exploration program in the Gulf of Mexico.

Is there anything new to communicate with respect to Martin, or any updates on timing of when you may have results there?

And then after Martin can you just remind us what the plan is going forward; what specific prospects you'll be drilling and over what timeframe?

Thanks.

Thank you very much.

On the regularity we have worked systematically on this for two or three years.

We saw that the trend was negative.

And we have analyzed this into the very detail and have had specific projects, that being rotating equipment, that being all sorts of drivers of unplanned losses.

And now we see that the trend has turned and the results are improving.

So it's good to see that systematic work pays off.

The scale of the improvement, I can give you some hints.

We are moving away 30,000 barrels a day out of 2014.

That is being replaced by higher regularity on the NCS.

And one percentage point higher regularity means 10,000 barrels per day to 12,000 barrels per day per year, so that should be possible to work out.

So it's a significant -- significant numbers.

When it comes to Martin, that well is spud, and we are -- it is in operations and we are drilling.

And it's too early to say when we are ready to come with any announcement with it.

Next question off the telephone, please.

Oswald Clint, Sanford Bernstein.

Thank you, yes, Torgrim.

Yes, I just want to go back to the North American onshore portfolio; still seeing quite strong double-digit volume growth there; was expecting, aligned with some of your comments before about a value- over-volume strategy there, slower for longer growth across that asset base.

So just wondering is that still the strategy?

Is that something we should expect to see going into next year; much lower levels of production growth?

And then the second question maybe if you could just talk around the recent Angolan block that you got out of.

Is there any significant CapEx commitment that you're actually being released from?

And is that cash you'll just put into say something like Johan Sverdrup?

Thank you.

All right, yes, and thank you very much.

On DPNA on volume growth you know we have taken down the number of rigs over the last year, so [we are] running with six rigs in Bakken, running with I think it's five rigs in Eagle Ford and 11 rigs in Marcellus.

It seems to be an appropriate run rate for the time being in the current environment.

So these are assets, as you know, for very long-term.

It's the number of rigs that is appropriate to run the necessary improvements on cost and efficiency and learning.

When it comes to Angola and the [west] of block of 15/06, there was some CapEx commitment in there that we don't carry any more, so is part of the total portfolio evolution.

And ultimately we can say that we will reinvest it into the rest of the portfolio.

Okay, good, thank you.

Next question off the telephone, please.

Gordon Gray, HSBC.

Thanks.

Good afternoon, gentlemen, a question quickly on cash flow.

The performance in the first half was obviously very strong, but your cash tax rate has been well below the 50% odd of the last couple of years.

Can you just tell us how we should think about effective cash tax rates for the rest of the year and for 2015?

And secondly, just on this gas price issue, whether you can give us any thoughts at the wider level on the reasons behind the extreme fall in European gas prices and how you think the trends will evolve.

Thank you.

Thank you very much.

So on the cash taxes, if you can prepare an answer to that Svein, as we are building deferred taxes as we invest.

On European gas I think the current price environment in Europe a result of a mild winter.

So we entered the season with quite full storages.

So currently we see a price in Europe of 35p per tonne to 40p per tonne.

We see that next summer it's priced around 55p, so it's a significantly higher price as such, so that is the reason why we have decided to not produce -- to produce less into this market.

We share -- our view on the market is pretty much aligned with how the gas market is priced currently.

We see stronger fundamentals, we see declining indigenous production, and we see also a slight increase in demand, so all of this means actually significant gas to Europe over the year.

So we see a healthy and good picture, but of course exposed to seasonal swings, and you will from time to time have summers like we have currently.

So I don't see any shift or dramatics in the prices.

It is just a function of a mild winter.

And on back of that it's good to have a flexible portfolio to produce from so you can actually create value on changes in the price curve.

Thank you.

Thanks.

On cash taxes, as you said, Torgrim, we -- in the quarter we are building deferred taxes with approximately NOK2b.

Then they are impacted by the investment level of the Norwegian continental shelves with the [test] operations as well as the uplift that we get on those.

Also the ramp ups on the international part of it we also see that we have low tax rates on the fields coming on stream there, so that is affecting it.

I also would like to remind you that the taxes that we have paid then in first half on the Norwegian continental shelf that is the remaining part of the 2013 taxes.

And for the second half of 2014 we will then start to pay taxes based on the 2014 results.

So that is how the cash taxes are impacted.

Sure, thanks.

Next question on the telephone, please.

Theepan Jothilingam, Nomura.

Yes, thank you.

Afternoon, gentlemen.

Two questions, please.

Torgrim, could you just talk a little bit about the impairment in the US?

I think you've referred to the sustained local price differential.

So if you could just talk a little bit about what you wrote down in terms of goodwill [on] the assets and what's remaining.

And then, secondly, just moving forward over the next six, nine months could you remind us in terms of the pipeline of projects to be where sanctions are going to be taking place FID, so if you could just give us an update there that would be great.

Okay, thank you, Theepan.

The impairment in the US is mainly related to goodwill, so the assets are working well for us operationally, resource-wise and progressing well.

What we see is that the US and conventional universe will be impacted by bottlenecks in transportation for many years.

Ultimately they will be solved, but we see that some of these projects now takes longer time than we expected earlier.

And to be even more specific, it's related to Keystone XL, where we now expect it to come later than what we have assumed earlier.

And also related to [Sodom] Marcellus area, where we see that infrastructure development are not able to catch fully up with the production growth in the area.

So that is the drivers behind this.

And these are judgments that we do regularly to test the goodwill.

Then on the second question over the next six months, it was related to -- can you repeat that question?

Yes, sorry.

Just what final investment decisions you might take in upstream projects, please.

Over the next six months?

Six to nine months, yes, what's in the pipeline.

So you have that in top of your mind, Svein?

Another one to mention, we are evaluating the Peregrino salt and Peregrino also some, what we call, extended reach for us.

Those are issues that probably will then come within the next year.

Also we have some -- on the Norwegian continental shelf evaluating some fast tracks.

Of course, the big one is Johan Sverdrup, where we expect to make that decision in next year.

Next question on the telephone, please.

Michele Della Vigna, Goldman Sachs.

Torgrim, thank you for the presentation.

I had two quick questions.

The first one relates to the gas deferrals.

You've quantified 30,000 barrels per day for DC.

I was wondering if you could quantify what the impact was in Q2 and how much that impacted your EBIT.

And then, secondly, on the fast-track projects I was wondering how much they produced in Q2 and where you expect them to peak in terms of production.

Thank you.

Could you repeat the second question, please, Michele?

Yes.

So for -- for your fast-tracked projects I was wondering if you could tell us how much they produced in Q2 and where you expect peak production to go?

Okay, thank you.

So on the gas defers 30,000 barrels per day total effect for the year, which typically happens in second quarter and third quarter.

I will not go into the quarterly effects as such, but it is natural to assume that it's spread over those six months that is deferral is taking place.

So it will impact production, earnings and the DD&A per barrel.

And remember that these barrels come from assets that are largely depreciated, so a very low DD&A effect on those, and also with very low unit-of-production cost as such.

So it definitely will have a decent effect on both earnings and cash flow.

On the production on the fast-track in the second quarter, Svein.

We are not giving exact numbers on the fast-track projects.

We have said that they are in the ramp-up phase.

We put two more fast-track projects into production in the second quarter, so we are now producing from eight fast-track projects.

And we expect some more then to come, and we are building gradually up.

Of course, when [Jord] has been closed down [Ina] is connected to the Jord field so that, as you see in the production data, has not produced during the quarter.

But we have now started Jord, so then Ina will also start production.

Thank you.

Next question on the telephone, please.

Peter Hutton, RBC.

Hi, thanks a lot.

Two questions, one is a quick one.

I thought I heard you say, but may not have done, that the production in the third quarter was expected to be flat on the second quarter.

Was that correct?

Yes, hi, Peter.

So from the Norwegian continental shelf we expect production from the NCS to be on approximately the same level as in the second quarter, so that's right.

Even though the maintenance -- actually there was more maintenance in the second quarter?

I think the impact was 110,000.

And in the third quarter it's expected to be 50,000 barrels a day.

And we expect to defer gas out of the third quarter.

Right, okay, so we might expect a little bit more gas deferrals in the third quarter than the second quarter, although you won't provide a direct split.

Peter, I very much appreciate the question, but I am not ready to go into the details.

Okay.

And then the second question is on CapEx.

And, you're right, in the first half it's around NOK10b.

And if we multiply that by two then we get to the $20b guidance.

But only -- in only one year of the last five you've spent anything like half the total year in the first half.

The average has been -- over the last five years is about $45m in the first half and $55m in the second half.

Do you expect much more flat or less seasonality this year, which is behind the $20b?

And also you've specifically referred to maintaining guidance on $20b in 2014, but in February, just to check, you also said NOK20b in 2015 and 2016.

Is that guidance also being maintained at this stage?

Okay.

So, thank you, Peter.

So when it comes to the seasonality in the numbers it's -- there is no magic about project goals are not calendar driven, so there must be other things that have driven the statistics here.

I see no reason for putting too much weight on that.

We expect around $20b in the investments.

And the guiding is maintained for the period 2014 to 2016 and the guiding is an average over those three years.

Perfect, thank you.

Next question, please.

Nitin Sharma, JPMorgan.

Afternoon, gents.

A couple of questions from me, first one on dividend.

Given that this is the first year of quarterly dividend for you guys and we've had two quarters in 2013 already, is it now fair to assume that quarterly EPS run rate will next be reviewed in Q1 2015?

And second one on European gas prices; apologize for coming back here.

You've explained the reasons for weakened gas prices, your views on outlook.

Maybe some color around what proportion of your NCS gas production now has spot linkage following the various rounds of renegotiations.

Thank you.

Okay, Nitin, thank you.

I'm not sure I've got the first question right, but it was related to quarterly dividends.

Could you repeat that?

When do you intend to next review the quarterly payout?

Okay.

All right, thank you.

Thank you.

Okay, so on our dividend, the way we intend to run this is to have a stable quarterly dividend in four quarters.

And the charge -- any change to the dividend will happen in relation to the fourth-quarter result and the fourth-quarter dividend.

So NOK1.08 per share for the first, second and third quarter of 2014 and then we will make a review in relation to the fourth quarter of 2014.

When it comes to the European gas prices and the share of spot indexation that is -- have been growing over the years and it is now stabilizing as such.

So it is -- we are not prepared to give the exact split, but 70% of our total gas sales in Europe and US is spot indexed.

Thank you.

Next question, please.

Anish Kapadia, TPH.

Good afternoon.

A couple of questions from me, please.

Looking at the back [and] you've seen a number of independent E&Ps that are looking to accelerate development, given where oil prices are and better completion techniques, some service cost savings.

You seem to be a bit more conservative in your approach over there.

I was just wondering is that due to the quality of your acreage, or there are -- are there other reasons around that?

And then my second question relates to the Barents Sea.

We've seen, I suppose over the last year or so, a number of disappointing exploration wells in numerous areas, such as the Norvag well, around some of the wells you've drilled around, Johan Castberg, and after the initial positive success on Wisting I think the follow-on wells have been a little bit disappointing.

So I was just wondering, that, combined with slightly higher taxes, higher development cost, how does that make you think about the Barents Sea and potential profitability of future exploration?

Thank you very much.

First, on Bakken, so we take a very long-term approach to the Bakken asset.

We are not in a hurry to maximize short-term production.

Our intention is to get across all rigs the learning that we do all the time on completion and drilling and making it very efficient, and also reducing well spacing and all of that.

And we find six rigs to be a decent run rate to capture all of that learning.

On the Barents Sea we have spudded a Mercury well in the [hoop area.

I think it's fair to say that the three wells we are drilling in the hoop area are three different models supporting it, so it's three separate decisions and so.

So we are still enthusiastic about this area.

This is the part of exploration we can't hit every time, but we are committed to Barents and we do see large potential.

Yes.

Next question, please.

Joshua Stone, Barclays.

Hi, good afternoon and thanks for the presentation.

Two questions from me, please, the first on operating costs.

I see that in Q2 the operating costs reported about NOK19.3b and about 40% of this is non-upstream.

I just want to understand what are the main cost items in this non-upstream part.

And then whether of your cost efficiency program is this focused at the corporate employees, or the corporate operating expenses, or more the upstream?

Where is the focus there?

And then the second question just on production and projects going forward.

You mention the fast-track projects, but also Valemon this year.

Can you give any idea of the timing this year when we can expect these projects to start up?

Thank you.

Okay, thank you.

Well, if you look at the operating cost and SG&A it's a growth of NOK1.4b from second quarter last year.

So the increase here, the largest part, is related to transportation cost and royalty, which is linked to increased production.

We also see that we have the high turnaround activity has added some cost compared to last year.

We have some more pension costs that is related to update of the mortality table, so it is now expected that we will live longer and that has a cost.

And then there are costs related to preparing for operations.

Valemon is of course one of those cost elements that goes into this.

So when it comes to timing of start ups the whole project portfolio develops as expected, so the earlier communication on this is the same.

Okay, thank you.

Next question, please.

Jon Rigby, UBS.

Thank you, yes.

Can I ask two questions?

The first is as you now are progressing into this capital efficiency model are you starting to see tensions emerge between delivering volumes as you expected to do, or progressing projects through the pre-feed feed process and into FID, and the need to improve the overall economics of those projects as, indeed, you've laid out in a lot of detail?

Thank you.

It's welcome.

And then the second question, just to go back to the point about deferring gas into next year for value, are you saying that you expect to take value because you expect the price to be higher?

Or was your reference to the future curve an acknowledgement that you are actually taking gas out and selling it forward into next year.

Thanks.

Thank you, Jon.

First of all, you know we have deferred a significant amount of projects already and those in no way built to take into the effect of the step program.

But we also see that like on Johan Sverdrup, for instance, we are actually implementing quite a bit of that methodology and thinking already into that project both when it comes to drilling a well, when it comes to working with suppliers and also when it comes to concept and concept selection.

So Johan Sverdrup, which has progressed quite far, will also benefit from all the things we are doing.

So I think it's absolutely possible to also take in quite a bit of the improvements in projects that we are currently working very actively with.

When it comes to the deferring of gas, so this summer prices is between 35p per turn and 40p per turn, next year it's 55p and also future summers are higher.

So the way we do it when we make decisions like this we tend to put it on the forward curve to lock in that margin.

And a 20p per turn margin on the gas volume is quite nice.

We have time for one more question, please.

John Olaisen, ABG.

Yes, good afternoon, gentlemen, a quick question on the cost side.

There seems to be some cost deflation from some rig rates and seismic rates and so on.

I wonder if you could comment on whether such cost deflation measures are including in your cost -- included in your cost reduction estimates.

And also if you could comment a little bit more on any particular segments where you see lower costs from your side [and] general cost deflation.

Thank you, John.

So in the -- we see, of course, that the costs are changing and that there is a dynamic in the market.

When it comes to the way we work with the improvements here, it is not related to an expectation of changing in rate and so on.

It's related to assumptions on efficiency and costs related to do the operation.

So it's not an integral part of the guiding.

So any cost inflation due to lower rig rates and so on will come on top of those numbers?

We haven't taken into account any changes in rig rates in the estimates we have provided here.

It was based on the forecast that we have and [then improving] towards those.

But are you seeing the same as many of us do, that the rig rates are coming down -- well, costs from all sub-suppliers and prices from all sub- suppliers coming down?

Is that something you see that's starting to have a positive effect for you guys?

The way we work with our contractors is long-term relationships and we have on quite a bit of capacity that we are using and so on.

So of course when we renegotiate and go into new contracts we are exposed to changes in rates and so on.

And it's very important for us to have a close dialogue with our suppliers and working closely with them.

And of course negotiation of price is an important part of those discussions with [those] suppliers.

Okay, thanks a lot.

Thank you.

That will have to conclude our Q&A session.

Today's presentation and Q&A session can be replayed from our website in a few days and transcripts will be made available.

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Thank you all for participating and have a good afternoon.