Good afternoon, everybody, and welcome to the Statoil First Quarter 2017 Analyst Call. This is Peter Hutton, Head of Investor Relations. And today, I'm joined by Hans Jakob Hegge, Chief Financial Officer; Svein Skeie, Head of Performance Management; and Ørjan Kvelvane, Head of Accounting. Hans Jakob will present the results for around 12 to 15 minutes, and then we will open for questions as normal. We expect the call to last around an hour, so we should be closing around 1:30 U.K. time. So with no further ado, let me pass the word over to Hans Jakob.

Thank you, Peter, and welcome to everyone attending this conference call. It is a busy day of results for all, so let me get straight to business. We have a strong quarter with good results in all business segments. The net operating income in the quarter was $4.3 billion; and adjusted earnings $3.3 billion. My key takeaways are the continued strong operational performance with high regularity, record entitlement production and we are on track on delivery of the projects and the CMU targets. Secondly, the strong improved results in all segments; and thirdly, the strong cash flow in the quarter, with net debt ratio reduced to 30%. We saw relatively stable commodity prices through the quarter, but continued volatility in the oil and gas markets must be expected, driven by the uncertainty related to OpEx development and the increase in U.S. shale production. Gas prices continued to show seasonal strength through the quarter on the back of strong demand for pipe gas in Europe and strong LNG demand, especially in Asia. However, I would like to remind you that we are entering the summer gas season, which traditionally are periods with weaker gas offtake and normally lower spot prices. Moving on to the dividends. The board has decided to maintain the first quarter dividend at $0.2201 per share and intend to offer a scrip dividend option with a 5% discount subject to AGM authorization. The scrip program was announced for a 2-year period ending third quarter 2017. Then, let me comment on the numbers in more details. We report net income of $1.1 billion in the quarter compared to $0.6 billion in the same quarter last year. The adjusted earnings before tax were $3.3 billion, up from $0.9 billion in the same quarter last year. This quarter, the adjustment of $0.9 billion reduced the results, mainly as a result of fair market value of derivatives [indiscernible] and reversal of impairment. This is compared to an adjustment of $0.2 billion, reducing the result in the first quarter last year. The adjusted earnings after tax ended at $1.1 billion, significantly up from the $0.1 billion in the first quarter 2016. Adjusted earnings were up 4x compared to the same quarter 2016, and adjusted earnings after tax were up 9x. These results both reflect the improvement in the prices and the improvements we have made. And the group average realized liquids price was $49 in the first quarter compared to $29 for the same period last year. We have improved the results through our own actions with sustained high regularity and visible cost reductions. Adjusted OpEx and SG&A was reduced by 5%, year-on-year. Tax rates were more in line with expectations, reflecting earnings and their composition. The adjusted tax rate in the quarter was 66.4% compared to 85.8% in the same quarter last year. Then taking you through our segments, let me start with Development and Production, Norway. [ DPN ] doubled adjusted earnings from $1.3 billion to $2.6 billion year-on-year and the cash flow was even stronger and I will come back to that. Our realized liquids prices were 64% higher than the first quarter 2016, and the gas transfer price was up 5% in the same period. DPN liquids production was up 2%; and gas production, 8%. We further reduced underlying costs and continued capturing efficiency gains. This was partly offset by costs associated with deals yet to come onstream. I would also like to mention that we have made a reclassification of the gas transportation costs to include this in OpEx. This increase reported OpEx by around $70 million, but has no effect on profit and loss. DD&A was 11% lower in the quarter, mainly as a result of increased proved reserves. In the coming quarter, you should expect the DD&A rate to trend upwards. This is due to the new fields ramping up and a lower gas offtake. Still, we expect to remain lower than last year. Exploration expenses. We are at the same level as the first quarter 2016. And let me remind you that the second and third quarters are typically busy maintenance periods. You should normally expect higher unit production costs as volumes are lower and costs are higher, although significantly less than we had last year. From our Development and Production International, adjusted earnings were $272 million compared to negative $800 million in the same period last year. As with DPN, the result was positively affected by improved commodity prices. Realized liquids prices was up 83% year-on-year and the underlying production increase was up 6% year-on-year. I am pleased to see that our positive cost trend continues also in this part of our business with an 11% reduction in adjusted OpEx SG&A in U.S. dollar per barrel. The main drivers for this reduction was the production mix because of portfolio adjustments such as the divestment of Leismer oil sands and reduced future provision for abandonment costs. This was partly offset by higher royalties and transportation costs. DD&A per barrel is up 6% and this is mainly due to new fields ramping up and production mix. Exploration expenses are 37% lower than last year, mainly driven by lower activity. And finally, results from our MMP segment. MMP continued to deliver results at the high end of our guidance. The adjusted result in the quarter was $500 million compared to $431 million in the same quarter last year. This was mainly a result of the higher gas sales and trading activities and the good refinery margin. But I'm also pleased to see the record high production at Mongstad. We had record entitlement production in the quarter of just over 2 million barrels, up 5% year-on-year. In Norway, the production was at its highest since the first quarter 2012, and we achieved a strong production regularity, in line with what we have seen over the last quarters. We had high seasonal gas offtake, with more gas coming from our flexible Oseberg field. We also saw the effect of ramp-up of [indiscernible], Ivar Aasen and higher share from our Lundin position. And the high regularity on contribution from new wells at lower costs more than offset this decline. The entitlement production in our International business was 4% higher than last year. This was driven by ramp-up of new production from Corrib, In Salah and In Amenas as well as continued growth in production from the Gulf of Mexico field. This was offset by a natural decline, lower U.S. onshore production, divestments of our heavy oil field, Leismer, in Canada and lower PSA effect also impacted production in the quarter. Then to the cash flow. The cash flow from operations was strong in the quarter. This was driven by higher commodity prices, higher production from Norway and International, lower costs and good results from our midstream business. We received proceeds in the quarter, primarily from the sale of Leismer of around USD 300 million. We paid one NCS tax installment in the quarter based on 2016 earnings, and we will pay 2 further tax installments of around $500 million each and 2 dividend payments in the second quarter. The tax payments for the second half of 2017 is expected to be higher, due to higher expected earnings. Cash flow to investments was $2.4 billion in the quarter, and we continued to see a positive trend from improving capital efficiency and strict prioritization. We generated more than $3.5 billion in free cash flow in the quarter. And our net debt is 30% at end of the quarter, down from 35.6% at the end of last quarter. Then to our outlook, which remains unchanged. CapEx is expected at around $11 billion, and we anticipate an organic production growth of around 4% to 5% in 2017 and around 3% CAGR from 2016 to 2020. Maintenance is expected to be 30,000 barrels per day for 2017 and 75,000 barrels per day in the second quarter. Our exploration spending is expected at around $1.5 billion this year. And we are on track on the additional USD 1 billion in efficiency effect for 2017. Let me also give some comments to dividends and the scrip program. The board has decided a first quarter 2017 dividend at $0.2201 per share and offer a scrip option for the first quarter of 2017 pending AGM approval. And with that, I hand the word over to Peter to take us through the Q&A.

Thank you, Hans Jakob. And with that, I'll ask Suzanne to open up the lines. She'll just explain the process how to register. [Operator Instructions] So Suzanne, would you like to open the call to -- the line to callers please?

[Operator Instructions] We'll now take our first question from Biraj Borkhataria from RBC.

I had a couple. The first one was on the scrip dividend. Later this year, you'll have to decide whether to recommend to cancel the discounted scrip or extend it, and I was wondering if you could talk about what you would need to see to remove that discounted scrip option, whether it's a certain oil price or a gearing level that you want to get to. Second question is just a short one, hopefully. Within the DPI result, could you clarify what the contribution is from the U.S. onshore segment?

So thank you, Biraj, for asking those questions. First, on the scrip. When we announced the scrip, it was announced for a 2-year period, ending third quarter this year, and this is subject to the AGM approval. We offered a 5% discount rate and we also announced a 2-year program with predictability. So we do what we say we will do. And we also see that there's a good take-up rate increasing from last quarter, so we have no plans to extend it. So we plan to stick to the 2-year program. On the DPI result, it was a good result, with adjusted earnings of USD 272 million. And you asked for the U.S. onshore contribution. As you know, we are on a [ $90 to $50 ] path in the U.S. business, and in this quarter, we see increased Gulf of Mexico production, somewhat lower in the Bakken area due to winter condition, and the higher realized prices, both on the liquid and gas in the DPN segment, also account for some contribution. I'm talking about the local Marcellus. And that's as far as I will go into the detail on the U.S.

The next question comes from Lydia Rainforth of Barclays.

It's Lydia from Barclays here. Just 2 quick questions [indiscernible]. The first one, just coming back to the cash flow number. It obviously was an impressive number for the quarter. Is that better than what your expectations were at the start of the year in terms of that balancing at $50 point? And apologies, I just missed the end of the [indiscernible] the question earlier. In terms of that International business, is that return to profitability, do you think, sustainable for the rest of the year at the current price?

So thank you, Lydia. To the first question about the cash flow, is it better than I expected? I would say it's in line, given some tailwinds. It is a strong cash flow. It is positive by $3.6 billion net, and we see that, in addition, we also have a $0.3 billion in the working capital reduction. The cash flow from the operations was about $6 billion, so that's also, I would say, is quite strong, but still in line with what we expected. And the main reason is the stronger underlying performance. To your second question about the International business and the sustainability, I think adjusted earnings in the International business was significantly better and the higher realized prices, both on the liquid and the gas, is part of the explanation, but also the high production of 753,000 barrels, which is up 3%. On the cost side, the OpEx SG&A is down by 10% in absolute terms; 11% per barrel. And we have been working, as you know, hard to attack the costs and efficiency orders on time. So I think [ see some times ] that this is paying off and many elements contribute to this. Going forward, as prices move up and royalty and production fees increase in line, but still this will partly be offset by positive operational and production cost improvements. So I would say that this is encouraging and we will continue to work hard. Just a last comment to that, you know that we are on the $90 to $50 journey in the U.S. and we are not fully there yet.

The next question comes from Oswald Clint of Bernstein.

Maybe some questions just on the results. The first one, just looking at some of your fields production, which is always very useful, some of your Angolan fields declining quite materially in the quarter in terms of -- versus last year. Could you just talk about those fields? Are those declines in line with your expectations, and we should continue -- we should expect that to continue through 2017? And then maybe just another specific one on the impairment reversal in Norway. It's a bit chunky this quarter, $0.5 billion, I think it's related to a field development. Could you maybe talk about that field development and what happened to cause that reversal, please?

Well, thank you, Oswald. I'll do the field -- the work reversal and I'll leave the Angolan field decline to Svein Skeie. On the improvement, the impairment reversal, it's an NCS development project and this is due to the change of tariffs to the transportation of this field also linked to that, so that's part of it. It's also CapEx and OpEx improvements, so that's the main explanation. So Svein, on the Angolan field decline.

Yes. As you said, our -- some of the fields in Angola that is coming up with the lower production there. You will see, for example, in the block 15, a reduction of approximately 8,000 barrels on the [indiscernible] with [ fixed entry ] going down. But these are fields that are mature, some of them in the block 15, so it is then declining according to expectations. Of course, it's being worked with those, looking into possibilities for wells and those things, but [ seesaw ] levels that have been seen over the last year. So it's according to expectations.

The next question comes from Jon Rigby of UBS.

Sorry, 2 questions. The first, if I could ask, relates to your U.S. gas trading business -- trading and supply business. It looks -- the first quarter has generally always been a good quarter for that business. Looks less so now when I compare it against your historic levels of performance. I just wondered whether you can discuss around that, maybe characterize whether that is driven by temporary conditions like weather? Or whether there are some structural changes taking place where you operate that has reduced the opportunity for margin generation there? And the second question relates to your International upstream. What was evident through the last 6 to 8 quarters as oil prices fell was the very strange effects it had on your tax rates, which, as I understand, it was really 2 elements. One was when exploration charges roll through and whether they were offsettable or not, and also where you were getting profits in some countries, losses in others, and you had some asymmetry in your tax charges. And it's notable now that, that tax rate is starting to look more normal. And I know you referenced the attempts to bring down the sort of cost-based profitability levels, bring up the profitability levels in the U.S. So short question to that is, are we seeing at around about the mid-50s level, the kind of conditions that we should expect to see more normal levels of tax rate in your International upstream business moving forward?

Okay, thank you, Jon, for those questions. To the U.S. gas trading, you're right, it's normally the first quarter is a good one and we play on premium markets like the Toronto and the New York. This quarter, we realized USD 3.3 per million BTU in the first quarter, despite the warm weather, reflecting a reduction on the discount. The local prices in the production area increased due to higher demand following new pipeline access and capacity out of the area. Going forward, midterm, I think we starts on a downward note with decline in demand. But in the first quarter, you are right, it was a good one. To the second quarter about DPN tax upstream, we have guided on the [ $50 to $55 ] range and I think you should expect that going forward, so no change to that. But you're absolutely right, in the past we have seen this thing very exposed to price changes, to lower prices. We expect still volatility going forward, but somewhat less as we have guided on the USD 75 in 2070 -- 2020 as our oil planning assumptions. So no change to the tax guidance on International.

The next question comes from Rob West of Redburn.

I'd like to ask about your OpEx in Norway. That's a metric, when I look at it, say, per barrel, that has been coming down nicely. But if I look at in the first quarter, I can see it has ticked up both quarter-on-quarter and year-over-year. And I know you have more visibility than I do on what goes into that line, so my question is, is there anything we should be aware of causing that number to increase that's a one-off sort of thing or a more sustained end of the [ deflection ] we've seen so far, maybe because of high levels of asset integrity spending going through that line? So if you could talk a bit about that. And then, secondly, I was just hoping to ask you about Peregrino in Brazil. I think your partner is preparing a data room. I was wondering if you have any desire to increase your footprint in that asset. Or would further Brazilian growth be [ pre-salt ] for you?

So thank you, Rob, for your questions. To the last one, no change in plans for Peregrino. To the OpEx in Norway, the OpEx SG&A is at NOK 46 per barrel, USD 5.5 approximately, confirming the downward trend seen in last year. But in this quarter, we had the reclassification of the gas transportation cost, which is now included in the OpEx of around $70 million. So we adjusted for this. If we do that, we actually have the second lowest OpEx since 2007. Still, you are right, it's 6% above the fourth quarter '16, which had some special items helping that result. So going forward, OpEx is expected to stay relatively low, but might see some increase over the next quarter due to production mix and the startup of Gina Krog, where we actually don't have a change in our mix.

We'll now take our next question, which comes from Halvor Nygård of SEB.

You state that the cash flow per barrel after tax in DPI is on par with DPN. Can you say something about the level of this cash flow and if it is including any one-off sale proceeds or if it's more of an organic character? And then, secondly, we saw that you had organic CapEx of $2.2 billion this quarter. If you annualize this, is this $8.8 billion compared to your full year guidance of $11 billion? Is the CapEx very back-end loaded this year, or do you feel you have headroom to the current $11 billion guidance?

So thank you, Halvor, for asking that question. To the organic CapEx, we have no change in the guiding. We said this year will be around USD 11 billion. So we stick to that. To the first one on the DPI, the cash flow per barrel about the level at par with DPN of around USD 25 per barrel. So that's at par with the DPN.

And that's not including any one-offs or something?

No.

The next question comes from Hamish Clegg of Bank of America.

It's Hamish Clegg calling from Bank of America Merrill Lynch. A few quick questions for you. The main -- one of the main deltas, obviously, to your strong earnings struck me as International. Going through the numbers in detail, the costs are somewhat lower in exploration OpEx and depreciation as well as much, much better realizations in that division. I wondered if you could maybe talk about how sustainable these cost savings are and how sustainable the realizations are. And the second sort of part to that same question is, what geography drove that? Was this as a previous [ kitchen sinking ] in the U.S. and things are now normalizing? Or was it something else? And the second question I had is, maybe I missed this at the beginning of the call, hopping off to another, is on Carcará, BMS-8. Can you update on how the conversations are going with the Brazilian government?

So thank you, Hamish, for those questions. I stick to the practice of answering the second one first, in Brazil, we are progressing [ as we want ]. There is a lawsuit and there was a temporary injunction, which has now been lifted. So we are able to progress as we would expect. We have a strong relationship with Petrobras and a good dialogue with both the partners and the authorities; operations are going well and the reliability of Peregrino is good as well. So Brazil is now on track. When it comes to the first question about sustainability in the International business and cost reductions, as I said earlier in the call, I think we are definitely on a positive trend. We have seen that over some time. Improvement work pays off at the OpEx and SG&A, it's down by 10% in the quarter. Still a significant share of the total OpEx SG&A is related to one-offs, both Leismer and West Virginia, the acreage and the downward trend adjustment in asset [ retirement ] obligations in the U.S. of around -- those being of around $70 million in total is related to the results. And also quarterly specific, there were some lower Bakken production due to the weather, but wells are now back on track.

Okay. I just -- I know Peter might not like this, but a little follow-up, tweaky follow-up, in fact. Your free cash flow was obviously so strong, what -- it's somewhat higher than the consensus numbers. Is this a sustainable -- is this sustainable for the rest of the year?

Well, what I didn't mention is, of course, the higher realized prices both on the liquids and the gas. I think I mentioned the local Marcellus, and I also mentioned the higher share of the Gulf of Mexico production in the DPI results. But higher realized prices is also dependent on your views going forward, of course.

Next question comes from Christyan Malek of JPMorgan.

Just circling back on your CapEx outlook. There was some confusion in Q4 around what your medium-term CapEx view was and that there would be some upside risk to higher than $12 billion to $14 billion. Can you come -- can you sort of come back and sort of walk us through the moving parts in terms of where you expect CapEx to trend over the next 2, 3 years, particularly if we are in a sort of lower oil price range [ very climate ].

Well, thanks, Christyan. The organic CapEx for 2017 is expected to be around USD 11 billion. And for the first quarter, there are no changes in the guiding provided at the Capital Markets Update in February. We are on track on the cost reductions of $1 billion communicated at the CMU. And going forward, we expect the CapEx to increase slightly from the 2017 level in the period to 2020.

Right. And then, just sort of a follow-on in terms of your OpEx run rate, so the 5% decrease this quarter. What other [ sort of issues ] are you embanking on. So I've noticed there wasn't much discussion around incremental changes in terms how you think about your cost base. Is there anything new that you're looking to introduce? Or would you consider you've reached steady state?

Well, I think we, no doubt, continue to deliver on the further improvements. On the Capital Markets, we announced a $3.2 billion in annual savings for 2016 moving onwards, adding another $ 1 billion on top of that. This quarter, we realized a 5% reduction. So we are according to plan with our CMU guiding, and I already mentioned the DPI and the DPN specifics. So I think we are on track and no change to the guiding.

The next question comes from Ilkin Karimli from Credit Suisse.

Two, if I may. Firstly, in regards to the CapEx flex, so as you progress with your [indiscernible] [ schedule ], just wanted to find out how much contingency still remains in CapEx guidance for Phase 1 and how much is contingency in the CapEx guidance for Phase 2? And then the second question is in regards to Lundin. And so is there any room for further asset swaps with them, similar to what you guys did last year with Edvard Grieg? Or is 20% stake a kind of a soft ceiling for you guys?

So thank you, Ilkin, for those questions. On the CapEx, like for the group overall, we said on the Capital Markets we -- the flexibility has been important in the past and is still going forward in times of volatility. And we have the flexibility on group level in place. It's a $4 billion to $6 billion towards the end of the period. [indiscernible] in specific, we don't give details on field contingency. And on Lundin, we are definitely happy where we are. No change in plans.

The next question comes from Anish Kapadia of TPH Asset Management.

A couple questions from me, please. First of all, looking at your Norway liquids production, if I'm -- if I look at production from your legacy fields, so kind of the fields that have been onstream for a number of years, the decline rates on those oilfields have been less than 3% for each of the last 3 years. That's kind of declined -- that decline rate has come down quite a bit from, I think, closer to 7% back in 2012, 2013. So I just wanted to really get a sense of, is that kind of lower decline rate of around 3% sustainable? Or would you expect that to accelerate back up again now that you'll start to see production efficiency stabilizing at this kind of higher level that you've got to? And then my second question was looking at the balance sheet, it's improved pretty significantly in the first quarter given the strong cash flow. I was wondering if you feel that you have the balance sheet capacity now to do acquisitions. Or would you need to see higher oil prices or will have to do disposals in order to fund for further acquisitions in this market?

Okay. Thank you, Anish, for those questions. On the NCS liquid production, I think the decline rates have been around 5%. There's no change to that. But in this quarter, we have more than offset that due to well productivity, high regularity; one of the highest quarters on the regularity. So we have not changed our view on overall decline rates of around 5%. On the capacity to do M&A, we definitely have capacity. We have done in the past. I remind you of the Carcará transaction; that swap with Repsol, getting the full operatorship of Eagle Ford; divestment prior to the downturn on the NCS high grading our portfolio. We have an opportunistic view on M&A and we will comment further when announcements are made, if made. So that concludes my M&A part.

The next question comes from Anders Holte of Danske Bank.

Anders Holte from Danske Bank here. Just a quick question on CapEx. Now we've seen obviously very strong cash flow for this quarter. And if we continue to see same strong cash flow numbers in the quarters to come, is there enough project in your portfolio to spike activity further, i.e. will there be a potential CapEx spike? Or are you happy with the projects that are now coming and you don't really think that the portfolio will change in a meaningful way, even if cash flow remains healthy throughout the year?

So thank you, Anders. I think I'm proud of the world-class project portfolio that we presented on the Capital Markets Update at an average breakeven well below the current oil price level. So CapEx 2017 is according to our expectations. We will be around $11 billion in CapEx this year. We have 7 projects scheduled to be sanctioned in 2017, '18, as said at the CMU. And we have sanctioned Njord and Bauge, and we will decide later this year on [ cost base -- view on cost base ].

We'll now take the next question from Iain Reid of Macquarie.

Just a quick question on your cash tax payments. I think you said earlier there's going to be 2 installments in the second quarter of $500 million each and they'll rise in the second half. Given the visibility you've got on earnings and cash flow, which those payments depend on, can you give a bit more detail about where you see the cash tax payments in the second half going. And second question is on your efficiency improvements of $1 billion this year. Can you say what proportion of that $1 billion you've captured in the first quarter? Obviously, we're seeing year-on-year improvements, but that, to some extent, depends on the improvements you've made in the past. Just interested in how much of that $1 billion you've captured so far in 2017?

So thank you for those questions. I'll take efficiency improvement and I'll hand over the cash tax payment to Ørjan. We are on track on realizing the $1 billion in savings in 2017, but no further detail provided at this point in time. So Ørjan, on the cash tax payments, we have installments due in the second quarter? Ørjan Kvelvane: Yes. So cash taxes for first quarter is $2.2 billion, and you see that from the balance sheet it increases by $1.5 billion, and we pay $0.6 billion. We increased deferred taxes by USD 4.7 billion this quarter. And for the next quarter, we have [ set up ] 2 tax installments on the level of this first quarter, but we had only one tax installment this quarter.

Yes, I understand that. But you also talked about the second half payments, so third and fourth quarter. Can you give us some outlook for those, please?

So Svein...

If [indiscernible] earlier I alluded to, I said if you look at the taxes payable for this quarter, $2.2 billion, versus then the paid taxes of $0.6 billion and then remember that the taxes on NCS, we are still paying taxes based on the 2016 earnings. But in the second half, then we will start then to pay taxes on the 2017 earnings. So of course, it will also then depend on the oil price and gas price that we realized in the second quarter and also the [indiscernible] for the remaining of the year, because then when we come towards end of June, we are then deciding on the level of OpEx that we are paying on NCS and that will be for August, October and December at another level.

So it's a bit too early to comment, but definitely expect higher taxes in second half.

We'll now take the next question from Alwyn Thomas of Exane BNP Paribas.

Just a couple of quick questions from me. Firstly on exploration, the statement mentioned you made 7 discoveries from 9 wells, which also helped keep the exploration costs low. Could you give us some overview of those discoveries, whether there's anything material or perhaps whether further evaluation might lead us to see bigger write-offs later in the year? And secondly, just going back to Sverdrup. Could you update us on the drilling and development progress, given some of the development wells you've been doing so far, and key upcoming milestones over the summer?

So thank you, Alwyn, for those questions. On the exploration, the success rate is quite high. We have completed, as you said, 9 wells, 8 on the NCS and 1 in the U.S. and 7 out of these were discoveries. Examples like [indiscernible], the Valemon West, [indiscernible], [indiscernible] 2 and 3 and [ Calpurnia 1 ] in the U.S. are examples. These are good examples of additional volumes that could be turned into production. So they are economically viable and producible and add volumes to the business, so we can turn them into profit. We have 2 wells ongoing in the quarter and we have the Barents campaign coming up. So 5 to 7 wells there and 3 potential high-impact wells included in that campaign. So in the second quarter, we would know more as we are planning to start in relative short period of time. So that will be exciting. On the Sverdrup, the drilling and well progress. I think you all heard the story of the perfect well and the improvements work that they've done in the drilling in well with 69% more meters today, more than 40% less per -- time per well and the 30% less cost per well. This is the overall drilling and well improvements that we made and told extensively about at the Capital Markets Update. I'm pleased to say that on the Sverdrup, the first 8 wells went very well and we were actually 8 months ahead of schedule. So very quick and efficient, I would say, world-class drilling and that project is according to plan.

Is there any likelihood that the resource range might get pushed up a bit later this year as a result of some of the results from these wells?

I have no further update to that based on this quarter.

[Operator Instructions] The next question comes from Anne Gjøen of Handelsbanken. Anne Gjøen: I have a question related to Norway. The tax rate in Norway, the adjusted tax rate in first quarter was 73%. If we assume on the oil price level close to the level of today, $50, since the investment is pretty low, is it likely that, that tax rate is going to increase onwards? And secondly, when it comes to the International production level, could you give some comments there in relation to production? As I assume it will be also some maintenance there and some seasonality in gas production.

Yes. So thank you, Anne, for those questions. The guiding range for tax in Norway, 70% to 72%, and we are fairly much in line with that in this quarter. The lower prices increased the tax rate, and over time, you should expect a falling tax rate, particularly if prices further recover. So that's the main comment in Norway on tax. On DPI production, we will -- well, first of all, it was a very strong production in the first quarter, over 753,000 barrels per day, is 3% up, and that was mainly the startup and ramp-up of Corrib [indiscernible] In Salah, the Southern fields and this was partly offset by the divestment of West Virginia and Leismer. Going forward, the impact of turnarounds will be higher as we, in this quarter, only had the Peregrino, the 10,000 barrels per day. For the second quarter, on group level, it's 75,000 barrels per day. And overall on the group level, the impact of turnaround this year will be 30,000 barrels per day. Svein, you might provide some additional details on DPI production going forward?

Yes. There will be a, on the turnaround, some minor impact on both fields. That was going in the second quarter, but the main thing in second quarter on the turnarounds will come from Algeria and then some smaller things then from Angola. But the main thing in second quarter in DPI would be in Algeria.

Yes. And on the PSA effect, we might comment specifically on that. That, our guiding there is [ 150,000 at $40 and 165,000 barrels at $70 for this year.

The next question comes from Brendan Warn of BMO Capital.

It's Brendan Warn from BMO. Just look, I was trying to circle back around on the free cash flow, the cash flows the remainder of the year, just to clarify. Obviously, you've had a strong quarter, but can I just -- can you just talk through in terms of what you expect your net debt ratio or net debt you're targeting for the end of year, considering that you're going to have turnarounds that'll impact cash flow from operations? Obviously, you've got some higher taxes to pay over the next 3 quarters and dividend payments. And obviously, you're running lighter on organic CapEx. Just let's say, at $50 a barrel, what you're seeing and you can do in terms of your gearing or your net debt, please?

So thank you, Brandon, for asking that question. Yes, it was a strong cash flow and it reduced the net debt ratio to 30%. So we are just within the range, the ambition range of the 15% to 30% this quarter, still with some quarterly specific this quarter and the tax installments and things that will come up in the second quarter and the maintenance that you say. But at the current prices, you could see a further reduction in the gearing. What we tell at to CMU is that the guidance we have provided for '17 and '18, there are some phasing issues which might benefit this year and this does include the level of planned maintenance and lower cash tax reflecting the lower earnings in '16 in Norway. We are not increasing our guidance provided on 2 months only. So it's still [ at it]. It's a good development in the first quarter. Taxes will increase, so will the dividend payment. And the CapEx run rate will be -- still within the guiding that we have provided. So that's my main comment to the development in the gearing.

The next question comes from Marc Kofler of Jefferies.

I just wanted to come back with a few follow-ups around the production guidance and outlook for the rest of this year. In Q1, Hans Jakob, you talked about the high production regularity on the NCS. Are you able to give a bit more color around that, and [ specifically ], that time perhaps relative to Q4 '16 or even year-on-year, that would be very helpful. And then could you also just elaborate or give us some color around the volume growth trajectory in North America?

So thank you, Marc, for those questions. On the production guidance, overall it's not changed. It's 4% to 5% for 2017 and there's 3% CAGR for '16 to '20, as we said a couple of months back. But the main drivers behind the strong production this quarter is ramp-up of fields like Ivar Aasen, the Corrib, the In Salah and In Amenas and the increase in Gulf of Mexico portfolio up to 70,000 barrels per day. We have new production wells on the NCS and this is more than offsetting the decline. And we also had more than 30,000 barrels increased flex gas production from Oseberg. And, if I'm not wrong, I think this is on top 3 on regularity if you look a few years back in time. So it's well above 90% regularity. And if you adjust for that on the Peregrino, the planned maintenance, also the Peregrino regularity in our Brazilian operation, is at par. So it is definitely higher production regularity and up timing. So no further change to our volume guide.

Okay. And then just on the market?

And then on the U.S., yes, you also mentioned the U.S. I almost forgot that one, so sorry for that. But as I said earlier, we had a lower Bakken production onshore due to weather, but the wells are now back. And there's also some effect on the Eagle Ford operations due to the, in a way, unusual harsh winter conditions. Going forward, at the moment, we have 5 drilling rigs in operations in the U.S. onshore, and you might expect to see somewhat higher U.S. onshore production in the second half. So to put this year in perspective, we have a low turnaround [indiscernible] compared to last year. And going forward, we will also increase completions in the rest of 2017.

Okay. With that, I'll take the opportunity to close the call. Thanks, everybody, for joining today. Thanks to my colleagues. Appreciate your time. And if there's, as always, any further questions, please don't hesitate to contact us in Investor Relations. Thanks a lot. Good afternoon.