Morten Sven Johannessen – VP, IR Torgrim Reitan – CFO Svein Skeie – SVP, Performance Management and Risk.

Mehdi Ennebati – Societe Generale Michael Alsford – Citigroup Haythem Rashed – Morgan Stanley Guy Baber – Simmons & Co. Oswald Clint – Sanford C.

Bernstein & Co Gordon Gray – HSBC Securities Theepan Jothilingam – Nomura Securities Michele Della Vigna – Goldman Sachs Peter Hutton – RBC Capital Markets Nitin Sharma – JP Morgan Anish Kapadia – Tudor, Pickering, Holt & Co. Joshua Stone – Barclays Jon Rigby – UBS John Olaisen – ABG Sundal Collier Morten Sven Johannessen.

Here in Oslo and to our audio and webcast participants. My name is Morten Sven Johannessen, Vice President, Statoil, Investor Relations. This morning at 7:00 AM 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 also 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 2:30 PM Central European Time. Please note that the 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 all projects on cost and schedule and our extensive turnaround program is running as planned.

In the first quarter, we delivered adjusted earnings of NOK32 billion. The result is impacted by divestments we have made, seasonal effects and lower gas prices. After-tax earnings were NOK9.9 billion. Earnings per share were NOK3.75, up from NOK1.38 last year.

Cash flow from operations before tax is NOK118 billion year-to-date and we maintained good cost control and strong capital discipline. Our organic CapEx so far this year is $10 billion and our guidance for the period 2014 to ‘16 is around $20 billion per year.

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

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 Insari [ph] well which was a minor technique industry discovery. And now the rig has been moved to the Giligiliyani [ph] prospects.

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 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 NOK12 billion, up from NOK4.3 billion in the second quarter last year. The increase is mainly due to changes in net financial items.

Net operating income was NOK32 billion in the second quarter but as always, we make adjustments to reflect the underlying business. This quarter, the divestments of our share in Shah Deniz in Azerbaijan results in a gain of NOK3.6 billion. And we have also taken an impairment of NOK4.3 billion primarily linked to goodwill in the U.S. onshore.

As you know, unconventional resources had quickly taken an important role in the world’s energy markets. We entered early into positions. We now have operatorships in three [ph] U.S. fields. We are positioned in good assets in the most attractive place. Our production is going well and the operational improvements are coming as planned or better.

Our onshore business is profitable today and we expect profitability to increase. We are making the operations more efficient, 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 the infrastructure developments 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 NOK32.3 billion. The result was impacted by lower production.

This is as expected and due to divestments, redetermination on Ormen Lange, higher turnaround effects and gas optimization. Decline was as expected, around 5%. This effect is more than offsets – more than truly offset by ramp-ups and new production. Gas prices in Europe have dropped and we continue to see low U.S. gas prices.

The increase in cost is mainly due to activity-driven elements like transportation and royalty. And in addition, we see an impact from higher turnaround activity, some in 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 overtime.

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 have very low unit DD&A. So when they use the flexibility to take down production at these fields, the DD&A per barrel will increase.

This will also impact the 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 – 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 remain stable.

After-tax, we delivered adjusted earnings of NOK9.9 billion. 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 tax rate is expected to stabilize below 70% in the coming years as we increase our production in the U.S. and Canada. In the second quarter, we produced 1.8 million barrels per day. In Norway, we continue to see strong regularity.

The reduced production is due to divestments, increased turnaround effects, redetermination 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 effects is, as you understand, much larger than ‘13. 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 NOK24.1 billion. 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 remain stable.

From our operations outside Norway, adjusted earnings were NOK6.3 billion which is at 0.4. We increased our equity production by 1% as we ramped up Angola fields and continued ramping up in the U.S. 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 gross. The results from MPR were NOK2.4 billion. 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 NOK68 billion or $11 billion.

We paid the full year 2013 dividend of around NOK23 billion [ph] and we received proceeds from SOCAR and BP for the sale of 10% of our stake in Shah Deniz. Cash flow to investments was NOK62 billion year-to-date, leading to an organic investment of around $10 billion. Our net debt to capital was 16%.

The first quarter dividends will be paid end of August with around NOK5.7 billion. And we expect gearing at yearend 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 on the way and start to see the effects.

Our staffs 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 staffs 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 technique and 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 a plan of 146 days. We did this by avoiding time consuming side tracks, a breakthrough in planning and execution for this type of well. And if we look at the results 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 train 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 for 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 $1.3 billion from 2016. We have reduced our gas production, but we maintain our guiding for a production growth of 2% from a 2013 rebase 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 $20 billion 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 $3.5 billion. We expect to complete around 50 wells. We have spudded the Dilolo prospect in the Kwanza basin in Angola and the Martin prospect in Gulf of Mexico and the Mercury well in the Barents. Later this year, Bay du Nord in East Coast Canada will be drilled.

And in total, we will drill 20 high impact wells during 2014 through ‘16. 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 up, we deliver strong operations and cash generation. We are well on the 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, Ørjan 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. The first question on the telephone, please..

We will now take our first question from Mehdi Ennebati from Societe Generale. Please go ahead, your line is open..

Hi, good afternoon all. I will ask two questions. First one regarding your 2014 production growth budget [ph] is 2%.

What European natural gas portfolio [ph] did you need in Q3 and particularly in Q4 to realize your 2% production growth budget [ph] of full year 2014 knowing that quarter-to-date we are at around $6.4 per MMBtu, we mean for years [ph] low and I don’t think that in Q4 you know 2014 we will go back to Q4 with 13 wells of $11 per MMBtu.

And my second question relates to the potential share buyback program. You’ve announced that additional asset disposals might lead to share buyback on 2015. I would like to know if European spot prices remain depressed next year as well.

You shouldn’t give the idea of returning cash from asset disposals to shareholders, 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 disposals to shareholders? Thank you..

Right. Thank you very much. So on the 2014 production growth, I mean we have decided to reduced 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 barrels 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 1 percentage point better regularity is 10,000 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 the 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 with this 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..

Your next question is from Michael Alsford from Citi. Please go ahead, your line is open..

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 get to choose [ph] stronger margins in European gas sales in the second quarter.

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

Can you maybe explain the effectiveness and perhaps how you see the outlook for I guess 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 NOK1.6 billion.

Can you maybe give a sense as to what the impact will be in 2015? I know the NOK1.6 billion if from 2016. So what would be the impact in 2015? And perhaps could you give us some quantifying color percentage wise perhaps around where you see the additional savings that you mentioned 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, you’re right, it is linked to the margin that 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 segments.

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 all of performance in the MPR segment. On imported [ph] basis, I think it’s very difficult to give indications.

A couple of things I can highlight; in the second quarter, we have five cargos from Snøhvit. Snøhvit 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, it’s between NOK2 billion and NOK4 billion as we see it. Cost efficiency, the effect is estimated in 2016. We already see some impact for 2014. And then it will grow to more through 2016. We have not given specifics for 2015 but it is natural to expect that this is gradually building towards 2016..

Thanks, Torgrim.

And just on the incremental potential?.

Related to the efficiency programs?.

Exactly. You mentioned that you said you spotted additional opportunities to save costs. I was wondering whether that was, say, in terms of content, how much more than the NOK1.6 billion that you’ve guided to currently could we see in later years. Thanks..

I mean the potential we have identified is larger than what we have communicated as we said on 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 if you look at starpost [ph] de-manning, we have also identified additional potential.

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

Okay, thanks very much for your answers..

And 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 that NOK1.3 billion in 2016 is what we are committed to deliver..

Next question on the telephone, please..

And the next question is from Haythem Rashed from Morgan Stanley. Please go ahead, your line is open..

Thank you. Good afternoon, gentlemen. Thanks for the presentation. Two questions from my side, please. And firstly, you talked quite clearly about DNP [ph] in 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 little bit of color on the international business and how you expect profitability to evolve in the second half there.

For example, what sort of effects Klov [ph] is expected to have on sort of DD&A in the segments and do you see any sort of potential headwinds for the segments on DD&A side in 3Q as well? My second question relates again to the cost and capital efficiency program and thanks for the updates on that and the slide in the presentation.

Perhaps if you would be able to provide any color around more the CapEx sort of moderation side of things. You talked about some of the opportunities you’ve identified on Opex and SG&A side.

I’m thinking particularly aside from, say, Johan Castberg, are there any other examples of projects which you’ve delayed or where you’ve made a decision not to go ahead with that have sort of, like you said, impacted the CapEx side of things in the last sort of couple of months, anything that you can provide there would be very helpful, thank you..

Okay. Thank you very much. On DPI over the next quarter, there will be maintenance. New production from one olaklov [ph] we typically have a high DD&A per barrel. So it will impact the numbers. And if you have more specifics there, please talk to us.

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, they are constantly worked across the portfolio to see what else can be taken out from CapEx and that is progressing well..

As Torgrim has said and Klov [ph] has started up and with fields which are in the south [indiscernible] ramp so you could have higher depreciations due to the fact that not that high amount of improved results on the field.

So it is a strong cash flow from the fields as we are building up, but this is affected by done [ph] the higher depreciation in the early days. Also towards the end, we also don’t expect startups in the Gulf of Mexico for some fields, but that is coming down also towards the year end..

Thanks very much..

Next question on the telephone, please..

And the next question is from Guy Baber from Simmons & Company. Please go ahead, your line is open..

Thank you. You guys mentioned a number of times a continued strong production regularity on the Norwegian Continental Shelf. So I wanted to dig a little bit deeper there but we’re just hoping you could discuss maybe in a little bit more detail the recent underlying trends in the NCS 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 the timing of when we may have results there? And then after Martin, can you just remind us kind of 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 equipments, that being all sort of drivers of unplanned losses.

And that we see that the trend has turned and the results are improving. So it’s good to see the systematic work pays off. The scale of improvement, I can give you some hints. We are moving away 30,000 barrels per day out of 2014. That is being replaced by higher regularity on the NCS.

And one percentage point higher regularity means 10,000 to 12,000 bottles per day per year. So that should be possible to work out. So it’s a significant numbers. When it comes to Martin, that well is spent [ph] 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. Yes..

Thank you..

Okay. Next question on the telephone please..

And the next question is from Oswald Clint from Sanford Bernstein. Please go ahead. Your line is open..

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. I was expecting and aligned with some in your comments before, about the value of your volume strategy there kind of slower for longer growth cost on asset.

So I’m just wondering is that still a strategy? Is that something we should expect to see going into next year much lower levels of production growth? And then second question, maybe can you just talk around the recent Angolan block that you got.

I don’t know if there’s any significant CapEx commitment that you’re actually being released from? And is that cash you just put into say something like Johan Sverdrup? Thank you..

All right, yes, and thank you very much. On DPNA on non-volume growth, we have taken down the number of rigs over the last year. So we’ve been 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 assets as you know for very long-term. It’s number of rigs that is appropriate to run the necessary improvements on cost efficiency and the earning. When it comes to Angola and the divestments of Block 15/06. I mean there was come CapEx commitment in there that we don’t carry anymore.

So it’s sort of part of the total portfolio evolution and ultimately we can go and then we can say that it would be reinvested into the rest of the portfolio..

Okay, good. Thank you..

Next question on the telephone please..

And the next question is from Gordon Gray from HSBC. Please go ahead. Your line is open..

Thanks. Good afternoon, gentlemen. 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 kind of 50% over 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 for 2015? And secondly just on this cash price issue, whether you can give us any sorts of 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. We are building deferred taxes as we invest. On European gas, I think the current price environment in Europe is a result of a mild winter. So moving into the season, we have quite full storages.

So currently we see in that price in Europe of GBP0.35 to GBP0.40 per term. We see that next summer, it’s priced around GBP0.55. 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 – all of you on the market, this is pretty much aligned with how the gas market is priced currently. We see strong fundamentals. We see declining indigenous production. And we see also a slight increase in the month. So all of these needs actually significant gas to Europe over the years. So we see a healthy and good picture.

But of course exposed to seasonal swings. And then 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 traditional from 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 growth..

Thank you, thanks..

On the cash taxes as you said, Torgrim, in the quarter, we are building different taxes approximately NOK2 billion than the impacted by the investment level of the Norwegian Continental Shelves with the tax 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 lower tax rates on the fields coming on stream there. So that is effecting. I also would like to remind you that the taxes that we have paid down in the 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 result. So that this is the whole – the cash taxes are impacted..

Sure, thanks..

Next question on the telephone, please..

Next question is from Theepan Jothilingam from Nomura. Please go ahead, your line is open..

Yes, thank you, operator and gentlemen. Three question please. Torgrim, could you just talk a little bit about the impairment in the U.S. I think you referred to this [indiscernible] if you could just talk a little bit about what you have done to the goodwill of the asset and what’s remaining.

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

Okay, thank you, Theepan. The impairment in the U.S. is mainly to goodwill. So the assets are working well for us, operationally, resource wise and progressing well. What we see is that the U.S. unconventional universe [ph] will be impacted by bottlenecks in transportation for many years. Ultimately, they will be sold.

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 the Keystone XL, where we now expect it to come later than what we have assumed earlier.

And also related to Southern Marcellus area where we see that infrastructure development on what they’re able to catch earlier with the production growth in the area. So that sort of, 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 project, please?.

Over the six months –.

Six to nine months, yes.

What’s in the pipeline?.

So do you have that in [indiscernible], Svein?.

And another one to mention, we are evaluating the Peregrino salt. And Peregrino also some what we call extended rituals [ph]. Those are issues that probably we then come within the next year. And also we some on the Norwegian Continental Shelf, evaluating some prospects..

But of course the big one is the John Sverdrup, where we expect to make that decision in next year..

Next question on the telephone, please..

And the next question is from Michele Della Vigna of Goldman Sachs. Please go ahead, your line is open..

Torgrim, thank you for the presentation. I had two quick questions. The first one relates to gas deferrals. So you’ve quantified 30,000 barrels per day for [indiscernible]. 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 your fast attack project 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 deferrals, 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’s [indiscernible] to assume that it’s sort of spread over those six months that this deferral is taking place.

So between impact production earnings and the D&A per barrel. And remember that these barrels comes from assets that are largely depreciated. So very low D&A effect on those. And also with very low unit of production cost as such. So it definitively have 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 said that they are in the ramp up phase. We put two more fast track projects into production in the second quarter. And so we are now producing eight fast track projects. And we expect some more to come and we are building readily [ph].

Of course when Njord has been closed, he may stay [ph] connected into the Njord field, so that as you see in the production letter has not produced during the quarter. But we have now started Njord, so then we’ll also start production..

Thank you..

Next question on the telephone, please..

Our next question is from Peter Hutton from RBC. Please go ahead, your line is open..

Hi, thanks a lot. Two questions. One is a quick one. I thought I had you say, but may not have done that 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 maintenance actually, there was more maintenance in the second quarter, I think the impact was one, ten [ph]. And then the third quarter is expected to be 60,000 barrels a day..

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

Right, okay.

So 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’m not ready to go over into that details..

Okay, and then the second question is on CapEx. And you’re right, in the first half, it’s around NOK10 billion and if we multiply that by two, we get to NOK20 billion guidance. But in only one year of the last five, you spent and it’s like half the total year in the first half.

The average is being of the last five years, it’s about 45 in the third half and 55 in the second half. Do you expect much more a flat or less seasonality this year which is behind that NOK20 billion? And also you specifically referred to maintaining guidance on NOK20 billion in 2014.

But in February just to check you also said NOK20 billion in ‘15 and ‘16, is that guidance also being maintained at this stage?.

Okay, so thank you, Peter. So when it comes to the seasonality and the numbers, so it’s a – and there’s no magic about project goes almost calendar driven so it must be other thing that sort of I believe in the statistics there. I see no reason for putting too much weight on that. We expect our own $20 billion in the investments.

And again the guiding is maintained for the period through 2014 to 2016. And I think earning is on average over those three years..

Okay, thank you..

Next question, please..

And the next question is from Nitin Sharma from JP Morgan. Please go ahead, your line is open..

Afternoon, gents. Couple of questions from me. First one on dividends. Given that this is the first year of quarterly dividends for you guys and we’ve had two quarters in [indiscernible] is it not fair to assume that quarterly DPS run rate will next be reviewed in Q1 2015? And second one on European gas rates, I apologize for coming back here.

You’ve explained the reason for weakened gas prices, your views and outlook. Maybe some color around what portion of NCS gas production now has port [ph] linkage following the [indiscernible] renegotiations. Thank you..

Okay, Nitin, thank you. I’m not sure I 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, so on the dividend. The way we intend to run this is to have a stable quarterly dividend in four quarters. And the change – any change to the dividend will happen in relation to the fourth quarter result and the fourth quarter dividend. So NOK1 and EUR8 [ph] per share for the first, second and third quarter of 2014.

And then we will make a review in relation to the fourth quarter of2014. When it comes to the European gas prices and the share of [indiscernible] that is – have been growing over the years. And it is now stabilizing as such. So it is – we’re not prepare to give the exact split. But 70% of our total gas I think Europe and U.S.

is [indiscernible] indexed..

Thank you..

Next question, please..

And the next question is from Anish Kapadia from TPH. Please go ahead, your line is open..

Good afternoon. A couple of questions from me, please. Looking at the Bakken, you’ve seen number of the independent AMP [ph] start looking to accelerate development given oil price [indiscernible] and better completion techniques for service and cost savings. You seem to be a bit more conservative in your approach over there.

I’m just wondering, is that due to the quality of your acreage or are there other reasons around that? And my second question relates to the Barents sea, we’ve seen over the last year or so a number of disappointing exploration wells in numerous areas such as the Novak [ph] well around some of the wells you drilled around Johan Castberg and after the initial positive successful listing, I think the following wells have been a little bit disappointing.

So I’m just wondering if that combined with a slightly higher taxes, high development cost, how does that make you think about the Barents sea and potential profitability of the future exploration?.

Thank you very much. First on Bakken, so we take a very long-term approach to the Bakken assets. We are not in a hurry to maximize the 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.

Then we find six rigs to at least in run rate to capture all of that learning. On the Barents sea, we have spudded the Mercury well in the Hoop area. I think it’s fair to say that the three once we are drilling in the Hoop area are three different models supporting it. So it’s three separate decisions and so on. So we still enthusiastic about this area.

And this is the mark of exploration. We can’t hit every time. But we are committed to Barents and we do see a large potential. Yeah..

Next question, please..

And the next question is from Joshua Stone from Barclays. Please go ahead, your line is open..

Hi, good afternoon, and thanks for the presentation. Two questions for me, please. The first is on operation costs. So I see that in Q2, the operation cost reports about NOK19.3 million. About 40% of this is non-upstream.

What are the main cause [indiscernible] in this non-upstream part and then whether of your cost-efficiency program, is this still the corporate and employees of corporate operating expenses or more of the upstream? And where is the focus there? And then second question just on production and projects going forward, could you just – you mentioned the fast track projects, but also Valemon this year.

Can you give any either the timing this year or when should we expect these projects to start up? Thank you..

Thank you. Well, if you look at operating cost and then SG&A, it’s a growth of NOK1.4 billion from second quarter last year. So they increased here, the largest part is related to transportation costs and royalty which is linked to increased production. We also see that we have the high turnaround activity has added some costs compared to last year.

We have some more pension costs that is related to an update of the mortality tables. 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 element that goes into this.

So when it comes to timing of startups, I mean the whole project portfolio develops as expected. So the earlier communication on this is the same..

Okay. Next question, please..

Our next question is from Jon Rigby from UBS. Please go ahead, your line is open..

Thank you, yes.

Can I ask two questions? First is, as you now are progressing into through 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 process and into FID [ph] and the need to improve the overall economics of those projects as indeed you laid out in lots of detail I think is welcomed.

And then the second question just to go back to the point about the deferring gas into next year for value, are you saying that you expect to take value because you expect the price to be higher? Well, what’s your reference to the future curve acknowledgment that you’re actually taking gas assets and selling it forward into next year? Thanks..

Thank you, Jon. First of all, we have deferred significant amount of projects already. And those are – and we’re able to take in the effect of the step program.

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

So [indiscernible] which has progressed quite far. We’ll 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 GBP0.35 and GBP0.40 per term.

Next year, it’s GBP0.55. And also future summers are higher. So the way we do when we make decisions like this, we tend to put it on the forward curve to lock in that margin. And that GBP0.20 per term margin on the gas volume is quite nice..

All right..

We have time for one more question, please..

And the last question is from John Olaisen from ABG. Please go ahead, your line is open..

Yes, good afternoon, gentlemen. A question on the cost side. There seems to be some cost that deflation from rig rates and seismic rates and so on.

But I wanted you to comment on whether such deflation measures are 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 cost deflation..

Thank you, thank you, John. So in the – we see of course that costs are changing and that there is a dynamic in the markets. 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 operations.

So it’s an integral part of the guidance..

So any contemplation due to lower rig rates and so on would come on top of those numbers?.

We haven’t taken into account any changes in sort of rig rates in the estimates we have provided. It was based on the core customers we had and then improving toward those..

But are you seeing the same thing as many always at [indiscernible] that rig rates coming down – cost for more all sub supplies and projects from all sub supplies coming down.

Is that something you see that starting to have a positive effect to you guys?.

Either the way we work with our contractors is a 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 dialog with the suppliers and working closely with them.

And of course negotiation on supplies is of course an important part of the discussions with the suppliers..

Okay, thanks for that..

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 available. Any further questions can be directed to the investor relations department and you’ll find the contact numbers and email addresses at the back of the presentation or on the web page.

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