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 A.M. CET, Statoil announced the results 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 2:30 P.M. 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. 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 NOK 32 billion. The result is impacted by divestment we have made, seasonal effects, and lower gas prices. After-tax earnings were NOK 9.9 billion. Earnings per share were NOK 3.75 , up from NOK 1.38 last year. Cash flow from operations before tax is NOK 118 billion year-to-date, and we maintain good cost control and strong capital discipline.
Our organic CapEx so far this year is $10 billion, and our guidance for the period 2014 through 2016 is around $20 billion a 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 rebase level. For exploration, the highlight this quarter is the Piri gas discovery in Tanzania. This brings estimated gas in place in Block 2 - 20 TCF. After Piri, we drilled the Binsari well, which was a minor technical gas discovery, and now the rig has been moved to the Giligiliani-1 prospect.
Finally, the dividend for the second quarter will be NOK 1.80 per share as we have moved from annual to quarterly dividend payment. 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 NOK 12 billion from NOK 4.3 billion in the second quarter last year. The increase is mainly due to changes in net financial items. Net operating income was NOK 32 billion in the second quarter, but as always, we make adjustments to reflect the underlying business.
This quarter, the divestment of our share in Shah Deniz in Azerbaijan resulted in a gain of NOK 3.6 billion, and we have also taken an impairment of NOK 4.3 billion primarily linked to goodwill in the U.S. onshore. As you know, unconventional resources have quickly taken an important role in the world's energy market. We entered early into position. We now have operatorship in three 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. It 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 adjustment, earnings were NOK 32.3 billion. The result was impacted by lower production.
This is as expected and due to divestments, redetermination on Ormen Lange, higher turnaround effect, and gas optimization. Decline was as expected by around 5%. This effect is more than offset, 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. In addition, we see an impact from higher turnaround activity from increased pension costs and costs related to gas injections. 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 ramping up, but also by the composition of production.
Troll and Oseberg both have very low unit DD&A. 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 than the second quarter's numbers. Our field costs remain stable. After tax, we delivered adjusted earnings of NOK 9.9 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%. The 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. 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.
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. Next quarter, NCS production is expected to be around the same level as this quarter due to low gas production and high planned maintenance. Let us take a look at the segments. From our Norwegian upstream business, we delivered adjusted earnings of NOK 24.1 billion. The decrease was mainly caused by the lower production as explained. Costs were impacted by turnaround activities, new field startups, as well as higher pensions and injection gas. The field costs remained stable. From our operations outside Norway, adjusted earnings were NOK 6.3 billion, which is up NOK 0.4 billion.
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 costs related to transportation and to royalties as production grows. The results from MPR were NOK 2.4 billion. We saw good results from our European gas business. We continue to see good contribution from our LNG business. 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. To the cash flow year-to-date. The cash generation continues to be strong. Cash flow from operations after tax is NOK 58 billion or $11 billion.
We paid the full year 2013 dividend of around NOK 22 billion, and we received proceeds from SOCAR and BP for the sale of 10% of our stake in Shah Deniz . Cash flow to investment was NOK 62 billion year-to-date, leading to an organic investment of around $10 billion. On net debt to capital was 16%. The first quarter dividends will be paid end of August with around NOK 5.7 billion, and we expect gearing at year-end to be around 20% in line with earlier guiding. We continue with a firm financial framework and a solid balance sheet. Our efficiency programs are progressing. We are well on the way and start to see the effect. Our staff and services functions have been reduced by a headcount of around 1,000 people.
We have identified further potential for manpower reduction in the range of 1,100-1,400 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 technical efficiency program consists of six specific projects. First, end-to-end well delivery, reducing drilling costs by standardization and planning. 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 pipe trips, a breakthrough in planning, and execution for this type of well. If you look at the results so far this year, we see an impact of 15% within drilling and wells. Secondly, strengthening the early phase, ensuring the right solutions and developing lean concepts.
Another example, we have placed frame contracts early with Kværner for the Johan Sverdrup development to standardize the delivery of steel jackets and reducing engineering costs. Third point, standardization and industrialization, reusing concepts and taking advantage of synergies and scale. Our fast-track projects demonstrate that this works. 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. 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. I will revert with an update on progress at our Capital Markets Day in 2015.
We expect to deliver annual savings of $1.3 billion from 2015. We have reduced our gas production. First, 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 field will also contribute to this growth, Gudrun, the fast-track, 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 the partner-operated project. 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 studied 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 de Verde in East Coast Canada will be drilled. In total, we will build 20 high-impact wells during 2014 through 2016. We are in the middle of an extensive maintenance period. For the full year, we expect a maintenance effect around 50,000 barrels per day. For the third quarter, around 60,000 barrels per day. Out of this, 50% will be liquid and 60% will be on the NCS. To round up, we deliver strong operations and cash generation. We are well on the way with our improvement program, and we maintain our guidance. Thank you very much for your attention.
I 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.
If you would like to ask a question, please press star one. Thank you.
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 while asking your question, and then release the button when you have finished. We will now have the first question from the floor. I think we can just progress to the telephone. First question on the telephone, please.
We will now take our first question from Mehdi Ennebati, Société Générale. Please go ahead, your line is open.
Hi. Good afternoon, all. 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 four-year low. I don't think that in Q4, you know, 2014, we will go back to Q4 2013 levels of $11 per MBtu. My second question relates to the potential share buyback program. You've 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. On the 2014 production growth, we have decided to reduce our gas production, and that has happened in the second quarter. In our expectation, we see that continuing also through third quarter. The total effect for the year is 30,000 barrels per day. That is embedded in the guidance, and it reflects the current market situation in Europe with gas prices during the full summer. We are not dependent on strengthening of gas prices to deliver on the production guidance. We see improved regularity in our operated fields, and that contributes positively to production. One percentage point better regularity is 10,000-12,000 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%-30% net debt. It is in that framework that's around the share buyback program. You are absolutely right. We have a clear intention to use that more actively going forward.
Next question, please.
The 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. Just wanted to pick up on your comments relating to the fact that you said that you, I guess, achieved stronger margins in European gas sales in second quarter. It seems when looking at the numbers, it's simply a reflection of what it was a low transfer price in the DP Norway division. Could you maybe explain the effect of this 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 sort of targeted annual savings of $ 1.6 billion.
Could you maybe give a sense as to what the impact will be in 2015? I know the $1.6 billion is from 2016, so what would the impact in 2015? Perhaps could you give some quantifying color percentage-wise perhaps around where you see the additional savings that you mentioned in your prepared remarks? Thank you.
Okay. On your first question. The MPR result is, you know, good, fair . The 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. They keep the exposure to renegotiations of gas contracts and all of that within their risk. It is of course an effect of the internal price as well.
You know, as long as they beat the market, it's all a performance in the MPR segment. On 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 Snøhvit. Snøhvit has been out in maintenance in the quarter. In the next quarter, there will probably be more cargos that will generate profit in that segment. You should be prepared that it fluctuates from quarter to quarter, and a normal quarter is, you know, between NOK 2 billion and NOK 4 billion, as we see it. Cost efficiency. The effect is estimated in 2015.
We already see some impact for 2014, and then it will grow towards 2016. We have not given, you know, specifics in for 2015, but it is natural to expect that it is gradually building towards 2016.
Thanks, Torgrim. Just on the incremental potential.
Related to the efficiency program?
Exactly. You sort of 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 $1.6 billion that you've guided to currently could we see in later years? Thanks.
Yes. Thanks. I mean, the potential we have identified is larger than what we have communicated, as we said on the Capital Markets Day. It's a significant potential. It will be linked to the six projects that we have estimated. If you look at staff costs, the manning, we have also identified additional potential. We typically see the effect of that into the SG&A costs, asset.
Okay, thanks very much for your answers. Thanks.
I think it's fair to say that even if we see a big potential, this is, you know, fundamental changes that takes time to implement. We said that $1.3 billion in 2016 is what we are committed to deliver.
Next question on the telephone, please.
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. Firstly, you've talked quite clearly about DP 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 effect CLOV is expected to have on sort of DD&A in the segment? And do you see any sort of 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. Thanks for the update on that and the slide in the presentation. Perhaps if you would be able to provide any color around more on the CapEx sort of 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, 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 are sort of likely to impact 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.
Thank you very much. On the DPI, over the next quarter, there will be maintenance, new production from Angola CLOV will typically have a high DD&A per barrel. It will impact the numbers. If you have more specific , Svein, please afterwards. When it comes to the cost efficiency and CapEx moderations, you know, we have made significant changes to the CapEx program and project. 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.
The decisions we have made lately but some typically impacted 2016 CapEx, but address the period beyond that. However, they are constantly working, you know, across the whole portfolio to see what else can be taken out from CapEx, and that is progressing well.
As Torgrim has said, CLOV started up and with the fields which are in the startup and ramp-ups, we typically have higher depreciation due to the fact that high amount of proved reserves from the field. It is a strong cash flow from the fields that we are building up. It's affected by the higher depreciation in the early days. Also towards the end, we also expect startup in the Gulf of Mexico for some fields. That will come also towards the year end.
Thanks very much.
Next question on the telephone, please.
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 the continued strong production regularity on the Norwegian continental shelf. I wanted to dig a little bit deeper there, but was 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. 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. 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? 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, time frame? 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, you know, analyzed this into the very detail and have had specific folders, you know, that being rotating equipment, that being, you know, all sort of drivers of unplanned losses. Now we see that the trend has turned and the results are improving. It's good to see that systematic work pays off. The scale of the improvements, 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. One percentage point higher regularity means 10,000-12,000 barrels per day per year.
That should be possible to work out. It's a significant numbers. When it comes to Martin, that well is done, and it is in operations, and we are drilling, and it's too early to say when we are ready to come with any announcements with it. Yeah.
Thank you.
Next question on the telephone, please.
The next question is from Oswald Clint from Sanford Bernstein. Please go ahead. Your line is open.
Thank you. Yes, Torgrim. Yeah, just wanna 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 for volume strategy there, kind of slower for longer growth across that asset base. Just wondering, is that still a strategy? Is that something we should expect to see, you know, going into next year, much lower levels of production growth? Then the second question, maybe if you just talk about 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 would just put into, say something like Johan Sverdrup? Thank you.
All right. Yeah. Thank you very much. On DPNA, on volume growth, you know, we have taken down the number of rigs over the last year. We're running with six rigs in Bakken, running with, I think it's five rigs in Eagle Ford and 11 rigs in Marcellus. Seems to be an appropriate run rate for the time being in the current environment. These are assets that we know for very long term. It's number of rigs that is appropriate to run the necessary improvements on cost and efficiency, and learning.
When it comes to Angola and the divestments of Block 15/06, I mean there was some CapEx commitments in there that we don't, you know, carry anymore. It's sort of part of the total portfolio evaluation. You know, ultimately we can say that it will be reinvested into the rest of the portfolio.
Okay, good. Thank you.
Telephone, please.
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% or so 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? 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. On the cash taxes, you can prepare an answer to that, Svein, that 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. We enter the season with quite full storages. Currently we see the price in Europe of, you know, [GBP 0.35-0.40] per therm. We see that next summer it's priced around [GBP 55] with a significantly higher price as such. That is the reason why we have decided we will produce less into this market. We share, you know, 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. All of this needs actually significant gas to Europe over the year. We see a healthy and good picture, but of course exposed to seasonal swings and you will from time to time have summers like you have currently. I don't see any shifts or dramatics in the prices. It is just a function of a mild winter. On back of that, it's good to have a flexible portfolio to produce from. We can actually create value on changes in the prices.
Thank you. Thanks.
Cash taxes, as you said, Torgrim, in the quarter we are building deferred taxes with approximately NOK 2 billion, and then impacted by the investment level at the Norwegian Continental Shelf 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 low tax rates on the fields coming on stream there. That is affecting. 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.
For the second half of 2014, we will then start to pay taxes based on the 2014 results. That is, you know, how the cash taxes are impacted.
Sure. Thanks.
Next person on the telephone, please.
Next question is from Theepan Jothilingam from Nomura. Please go ahead. Your line is open.
Yeah, thank you. Afternoon, gentlemen. Two questions, please. Torgrim, could you just talk a little bit about the impairment in the U.S.? I think you referred to the sustained sort of local price differentials. So if you could just talk a little bit about what you wrote down in terms of goodwill of the assets and what's remaining. Secondly, just moving forward over the next six, nine months, could you remind us in terms of the pipeline of projects where sanctions are gonna be taking place FID? Just give us an update there, that'd be great.
Okay. Thank you, Theepan. The impairment in the U.S. mainly related to goodwill. The assets are working well for us operationally, resource-wise, and, you know, progressing well. What we see is that, you know, the U.S. unconventional universe will be, you know, impacted by bottlenecks in transportation for many years. We estimated they will be solved, but we see that some of these projects we know takes longer time than we expected earlier. 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. Also related to, you know, Southern Marcellus area where, we see that, infrastructure development are not able to catch fully up with the production growth in the area.
That sort of is the drivers behind this. These are, you know, judgments that we do regularly. To test the [audio distortion]. On the second question, over the next six months, it was related to, could you repeat that question?
Yes. Sorry. Just what final investment decisions you might take in upstream projects, please?
Over the next six months.
six-nine months. Yeah. What's in the pipeline?
You have that in your mind, Svein?
One of the ones to mention, we are evaluating the Peregrino [south]. Peregrino also from, I think, what we call, extended reach for us . Issues that probably will then come within the next year. Also we have some on the Norwegian Continental Shelf evaluating from fast-track.
Of course, the big one is Johan Sverdrup, where we expect to make that decision in next year.
Next question on the telephone, please.
The next question is from Michele Della Vigna from Goldman Sachs. Please go ahead. Your line is open.
Torgrim Reitan, thank you for the presentation. I had two quick questions. The first one relates to the gas deferral. You've quantified 30,000 barrels per day for this year. I was wondering if you could quantify what the impact was in Q2 and how much that impacted your EBIT. Secondly, on the fast-track project, I was wondering how much they've produced in Q2 and where you expect them to peak in terms of production. Thank you.
Could you repeat the second question?
Yes. For your fast-track project, I was wondering if you could tell us how much they produced in Q2 and where you expect peak production to go?
Yeah. Thank you. On the gas deferral, 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, you know, quarterly effects as such, but it's natural to assume that it sort of spreads over those six months, that is the deferral is taking place. It will impact, you know, production, earnings, and EBITDA per barrel. Remember that these barrels comes from assets that are largely depreciated, so very low EBITDA effect on those, and also with very low unit of production cost as well. It definitively have decent effect on both earnings and cash flow.
The production on the fast-track in the second quarter, Svein.
We are not giving exact numbers on the fast-track project. We've said that they are in the ramp-up phase. We put two more fast-track projects into production in the second quarter. We are now producing from eight fast-track projects, and we expect some more to come. We are building gradually up. Of course, when Njord has been closed down, Hyme is connected to the Njord field. That, as you see in the production data, has not been produced during the quarter. We are now started Njord, so then maybe more will also come from there.
Thank you.
Next question on the telephone, please.
The next question is from Peter Hutton from RBC. Please go ahead. Your line is open.
Oh, hi. Thanks a lot. Two questions. One's 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?
Yeah. Hi, Peter. From the Norwegian Continental Shelf, we expect production from the NCS to be on approximately the same level as in the second quarter. 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. 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'm not ready to go into that detail.
The second question is on CapEx. You're right, in the first half it's around $10 billion, and if we multiply that by two, we get to the $20 billion guidance. But only in one year of the last five, you spent anything like half the total year in the first half. The average has been over the last five years is about 45% in the first half and 55% in the second half. Do you expect much more flat or less seasonality this year, which is behind the $20 billion? Also you've specifically referred to maintaining guidance on $20 billion in 2014. But in February, just to check, you also said $20 billion in 2015 and 2016. Is that guidance also being maintained at this stage?
Thank you, Peter. When it comes to the seasonality in the numbers, there's no magic about, you know, project costs are not calendar driven. That must be all the things that sort of have driven the statistics there. I see no reason for putting too much weight on that. We expect, you know, around $20 billion in the investment. Again, the guidance is maintained for the period between 2014-2016, and the guidance is an average over those three years.
Perfect. Thank you.
Next question, please.
The next question is from Nitin Sharma from JP Morgan. Please go ahead. Your line is open.
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 DPS run rate will next be reviewed in Q1 2015? 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.
Hey, 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. On the dividend. The way we intend to run this is to have a stable quarterly dividend in four quarters. The change, any change to the dividend will happen in relation to the fourth quarter result and the fourth quarter dividend. NOK 1.08 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 indication, that is, you know, have been growing over the years, and it is now, you know, stabilizing as such. It is, we're not prepared to give exactly, but 70% of our total gas sales in Europe and U.S. is spot index.
Thank you.
Next question, please.
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 a number of the independent E&Ps 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 are there other reasons around that? 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 drilled around Johan Castberg. After the initial positive success on Wisting, I think the follow-on wells have been a little bit disappointing.
I was just wondering, you know, that combined with slightly higher taxes, higher development costs, how does that make you think about the Barents Sea and potential profitability of future exploration?
Thank you very much. First on Bakken, 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 the learning that we do all the time on completion and drilling, and then making it very efficient and also, you know, reducing well spacing and all of that. We find six rigs to be a decent runway to capture all of that learning. On the Barents Sea, we have started the 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, you know, different, you know, models supporting it, so it's three separate decisions and so on. We are still, you know, enthusiastic about this area. You know, this is the art of exploration. We can't hit every time. But we are, you know, committed to Barents, and we do see a large potential. Yeah.
Next question, please.
The next question is from Joshua Stone from Barclays. Please go ahead. Your line is open.
Hi. Good afternoon. Thanks for the presentation. Two questions from me, please. The first is on operating costs. I see that in Q2, your operating costs reported about NOK 19.3 billion, 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 corporate operating expenses or more the upstream? Where is the focus there? And then second question just on production and projects going forward. Can you just give us. You mentioned 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.
Thank you. If you look at the operating cost and SG&A, it's a growth of NOK 1.4 billion from second quarter last year. The increase here, the largest part is related to transportation costs and royalty, which is linked to increased production. We also see that we have, you know, 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 mortality tables, so it is now expected that we will live longer and that has a cost. There are costs related to preparing for operations. You know, Valemon is, of course, one of those cost elements that goes into this.
When it comes to timing of starters, I mean, the whole project portfolio developed as expected. Earlier communication on this is the same.
Okay, thank you.
Next question, please.
The next question is from Jon Rigby from UBS. Please go ahead. Your line is open.
Thank you. Yeah. Can I ask two questions? The first is, as you now are progressing into this sort of 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, I think is welcome. 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?
Was your reference to the forward curve an acknowledgment that you're actually taking gas out and selling it forward into next year? Thanks.
Thank you, Jon. First of all, you know, we have deferred significant amount of projects already, and those are now able to take into the effect of the set program. You also see that, you know, 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 and wells, when it comes to working with suppliers, and also when it comes to concept and concept selection. Johan Sverdrup, which has progressed quite far, will also benefit from all the things we are doing. I think it's absolutely possible to also take in quite a bit of improvements in projects that we are currently working very actively with.
When it comes to the deferring of gas, this summer prices is, you know, between [GBP 0.35 and GBP 0.40] per therm . Next year, it's [GBP 0.55], and also, you know, future summers are higher. The way we do it, when we make decisions like this, we tend to put it, you know, on the forward curve to lock in that margin. A [GBP 0.20] per therm margin on the gas volume is quite nice.
Right. Thank you.
We have time for one more question, please.
The last question is from John Olaisen from ABG. Please go ahead. Your line is open.
Yeah. Good afternoon, gentlemen. A question on the cost side. There seems to be some cost deflation from rig rates and seismic rates and so on. I wonder if you could comment on whether such cost deflation measures are included in your cost reduction estimates. 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. We see, of course, that costs are changing and that there is a dynamic in the market. When it comes to the way we work with the improvement here, it is not related to an expectation of change in rates and so on. It's related to assumptions on efficiency and cost related to the operation. It's not an integral part of the guidance.
Any cost deflation 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, you know, in the estimates we have provided. Based on the case that we have and then improving towards those.
Are you seeing the same thing as many others do, that the rig rates are coming down? Well, cost 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, you know, long-term relationships, and you know, we have owned quite a bit of capacity that we are using and so on. Of course, when we renegotiate and go into new contracts, we are exposed to changes in rates and so on. It's very important for us to have a close dialogue with our suppliers and working closely with them. Of course, negotiation of price is of course an important part of the discussions with our 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. 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 webpage. Thank you all for participating and have a good afternoon.