Good afternoon, everybody, and welcome to the Statoil first quarter 2017 analyst call. This is Peter Hutton, Head of Investor Relations. 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 Hegge will present the results for around 12-15 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 P.M. U.K. time. With no further ado, let me pass the word over to Hans Jakob Hegge.
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.
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 OPEC developments and the increase in the 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 dividend, 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 two-year period ending third quarter 2017.
Let me comment on the numbers in more detail. We report net income of $1.1 billion in the quarter compared to $4.6 billion in the same quarter last year. The adjusted earnings before tax were $3.3 billion, up from $4.9 billion in the same quarter last year. This quarter, the adjustment of $4.9 billion reduced the result mainly as a result of fair market value of derivatives, overlift, and reversal of impairment. This is compared to an adjustment of $4.2 billion, reducing the result in the first quarter last year.
The adjusted earnings after tax ended at $1.1 billion, significantly up from the $4.1 billion in the first quarter 2016. Adjusted earnings were up 4x compared to the same quarter 2016, and adjusted earnings after tax were up 9 x. These results both reflect the improvements in the prices and the improvement we have made. 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 reduction.
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. Taking you through our segment, let me start with Development & Production Norway. DPN doubled adjusted earnings from $1.3 billion to $2.6 billion year-over-year, and the cash flow was even stronger, and I will come back to that.
Our realized liquids prices were at 64% higher than the first quarter of 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 on stream. I would also like to mention that we have made a reclassification of the gas transportation costs to include this in OpEx. This increased reported OpEx by around $70 million that has no effect on profit and loss.
G&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. 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 & Production International, adjusted earnings were $272 million compared to -$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 11% reduction in adjusted OpEx SG&A in US 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. 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 margins. 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 Goliat, Ivar Aasen, and higher share from our Lundin positions. The high regularity and contribution from new wells at low costs more than offset the 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 natural decline, lower U.S. onshore production, divestments, our heavy oil field Leismer in Canada, and lower PSA effects also impacted production in the quarter. To the cash flow. The cash flow from operations was strong in the quarter. This was driven by higher commodity prices, high 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 $300 million.
We paid one NPS tax installment in the quarter based on 2016 earnings, and we will pay two further tax installments of around $500 million each and two 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 investment was $2.4 billion in the quarter, and we continue to see a positive trend on 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 the end of the quarter, down from 35.6% at the end of last quarter.
To our outlook, which remains unchanged. CapEx is expected at around $11 billion, and we anticipate an organic production growth of around 4%-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. We are on track on the additional $1 billion in efficiency effect for 2017. Let me also give some comments to dividend 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. 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. We'll just explain the process to you, how to register. In fact, because of the interest of time, if I could ask callers to keep themselves to two questions of one part in any one question or one or two parts, but not two of two. We have a lot of questions to get through today. Suzanne, would you like to open the call to the line for callers, please?
Ladies and gentlemen, if you wish to ask a question over the telephone, please press star one on your telephone keypad. Please ensure that the mute function on your telephone is switched off to allow your signal to reach our equipment. If you're using a speakerphone, it may be necessary to lift the handset before making your selection. If you find your question has already been asked, you may remove yourself from the queue by pressing star two. Once again, press star one to ask a question. We'll now take our first question from Biraj Borkhataria from RBC. Please go ahead.
Hi. Thanks for taking my question. 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, you know, 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? Thank you.
Thank you, Biraj, for asking those questions. First, on the scrip, when we announced the scrip, it was announced for a two-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 two-year program with predictability. We do what we say we will do, and we also see that there is a good take-up rate increasing from last quarter. We have no plan to extend it, so we plan to stick to the two-year program. On the DPN results, it was a good result with adjusted earnings of $272 million, and you asked for the U.S. onshore contribution.
As you know, we are on a 90-50 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 conditions. The higher realized prices both on the liquid and gas in the DPN segment also accounts 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.
Okay. Thank you.
The next question comes from Lydia Rainforth of Barclays. Please go ahead.
Thanks. Good afternoon. It's Lydia from Barclays here. Just two quick questions, actually. The first one just comes back to the cash flow number. It obviously was an impressive number from the quarter. Is that better than what your expectations were at the start of the year in terms of that balancing at $50 point? Apologies, I just missed the end of the answer to 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? Thanks.
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 NOK 3.6 billion net. We see that in addition, we also have 0.3 in the working capital reduction. The cash flow from the operations was above NOK 6 billion, so that also I would say is quite strong but still in line with what we expected. 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. We have been working, as you know, hard to attack the cost on the efficiency over some time. I think see some signs that this is paying off and many elements contributes to this.
Going forward, as prices move up, royalty and production fees increase in line. Still, this will partly be offset by positive operational and production cost improvements. I would say that this is encouraging and we will continue to work hard. Just a last comment to that, you know that we're on the 90-50 journey in the U.S., and we are not fully there yet.
Perfect. Thank you very much.
The next question comes from Oswald Clint of Bernstein. Please go ahead.
Hi. Thank you. 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 expect that to continue through 2017. And then maybe just another specific one on the impairment reversal in Norway. Kind of it's a bit chunky this quarter, $500 million . 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? Thank you.
Thank you, Oswald. I will do the field reversal, and I'll leave the Angolan field decline to Svein Skeie. On the improvement, the impairment reversal, it's Snøhvit development project. This is due to the change of tariff to the transportation of this field also linked to that. That's part of it. It's also CapEx and OpEx improvements, so that's the main explanations. Svein, on the Angolan field decline.
Yes. As you said, there are some of the fields in Angola that is coming up with lower production there. You see, for example, in the Block 15, so the reduction of approximately 8,000 barrels and on the Pazflor and Dalia with 6,000 and 3,000 going down. But these are fields that are mature, some of them in the Block 15. It is then declining according to expectations. Of course, it's being worked with those looking into possibilities for wells and those things. But these are levels that have been seen over the last year or so. It's according to expectations.
Okay. Very good. Thank you.
The next question comes from Jon Rigby of UBS. Please go ahead.
Hi. Yes, thank you for taking the question. Two questions. The first, if I could ask, relates to your U.S. gas trading and supply business. It looks like 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 and maybe characterize whether that is driven by temporary conditions like weather or whether there's some structural changes taking place where you operate that has reduced the opportunity for margin generation there.
The second question relates to your international up stream. What was evident through the last six to eight quarters as oil prices fell was the very strange effects it had on your tax rates, which as I understand it was really two elements. One was when exploration charges rolled through and whether they were offsetable or not, and also where you were getting profits in some countries, losses in others and you had some asymmetry on your tax charges. It's notable now that that tax rate is starting to look more normal.
I know you referenced the attempt to bring down the sort of cost base, profitability levels, bring up the profitability levels in the U.S. 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? Thank you.
Okay. Thank you, John, 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 $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 it starts on a downward note with decline in demand. In the first quarter, you're right, it was a good one.
To the second quarter about DPN tax, upstream, we have guided on the 50-55 range, and I think you should expect that going forward, so no change to that. You're absolutely right. In the past, we have seen this being very exposed to price changes to lower prices. We expect still volatility going forward, but somewhat less, as we have guided on the $75 in 2020, as our planning assumption.
Okay.
No change to the tax guidance on international.
Perfect. Thank you.
The next question comes from Rob West of Redburn.
Hello. Thanks for taking a couple from me. 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. If I look at it in the first quarter, I can see it's ticked up both quarter-on-quarter and year-over-year. I know you have more visibility than I do on what goes into that line. My question 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 deflation we've seen so far, maybe because of higher levels of asset integrity spending going through that line? If you talk a bit about that.
I'm 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-sold for you? Thanks.
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, $5-$5.5 approximately, confirming the downward trend seen in the last year. In this quarter, the other reclassification of the Gassled transportation cost, which is now included in the OpEx of around $70 million. We adjusted for this. If you do that, we actually have the second lowest OpEx since 2007. Still you're right, it's 6% above the fourth quarter 2016, which had some special items helping that result.
Going forward, OpEx is expected to stay relatively low, but might see some increase over the next quarter due to production mix and the start-up of Gina Krog, where we actually then have a change in our mix.
That's really clear. Thank you very much.
We'll now take our next question, which comes from Halvor Nygaard of SEB. Please go ahead.
Hi, guys. 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 analyze this is $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 dollar guidance? Thank you.
Thank you, Halvor, for asking that question. To the organic CapEx, we have no change in the guidance. We said this year will be around $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 $25 per barrel. That's at par with DPN.
That's not including any one-offs or something?
No.
Okay, thank you.
The next question comes from Hamish Clegg of Bank of America. Please go ahead.
Hi. Thanks for the call. It's Hamish Clegg calling from Bank of America Merrill Lynch. A few quick questions for you. 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 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. The second sort of part to that same question is what geography drove that?
Was this a previous kitchen sinking in the U.S. and things are now normalizing, or was it something else? The second question I had is, maybe I missed this at the beginning of the call hopping off one other, is on Carcará BM-S-8. Can you know, update on how the conversations are going with the Brazilian government?
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's 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 the strong relationship with Petrobras and a good dialogue with both the partners and the authorities. Operations are going well. The reliability of Peregrino is good as well. 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. You have seen that over some time. Improvement work pays off as the OpEx and SG&A is 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 US of around, those being of around $70 million in total is related to the results. Also quarterly specific, there are some lower Bakken production due to weather, but wells are now back on track.
Okay, brilliant. Thanks. Can I? I just know Peter might not like this, but a little follow-up, tricky follow-up, in fact. Your free cash flow was obviously so strong. What, you know, it's somewhat higher than the consensus numbers. 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 DPN result. Higher realized prices is also dependent on your views going forward, of course.
Thanks very much.
Next question comes from Christyan Malek of JP Morgan. Please go ahead.
Hi, thank you for taking my question. Good afternoon. 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 12-14. 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 two, three years, particularly if we are in a sort of lower oil price range? Would be very kind.
Well, thanks, Christyan. The organic CapEx for 2017 is expected to be around $11 billion. 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. Going forward, we expect the CapEx to increase slightly from the 2017 level in the period to 2020.
Right. Just as a follow-on in terms of your OpEx run rate, you sort of had a 5% decrease this quarter. What are the sort of initiatives that you are embarking on? I sort of noticed there wasn't much discussion around incremental changes in terms of how you think about your cost base. Is there anything new that you're looking to introduce, or would you consider you've reached a new 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. We are according to plan with our CMU guidance, and I already mentioned the DPI and the DPN specifics. I think we are on track and no change to the guidance.
Thank you. Thank you very much.
The next question comes from Ilkin Karimli from Credit Suisse. Please go ahead.
Hi, thank you for taking my questions too, if I may. Firstly, in regards to the CapEx flex, so as you progress with Johan Sverdrup, just wanted to find out how much contingency still remains in CapEx guidance for phase I and how much is contingency in the CapEx guidance for phase II. The second question is in regards to Lundin. 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 kind of a soft ceiling for you guys? Thank you.
Thank you, Ilkin, for those questions. On the CapEx flex for the group overall, we said on the capital markets. The flexibility has been important in the past, it is still going forward in times of volatility, and we have the flexibility on group level in place. It's the $4 billion-$6 billion towards the end of the period. On Sverdrup specifically, we don't give details on field contingency. On Lundin, we are definitely happy where we are. No change in plans.
Okay, good. Thank you.
The next question comes from Anish Kapadia of TPH Asset Management. Anish, please go ahead. Your line is open.
Hi. A couple of questions from me, please. First of all, looking at your Norway liquids production, if I, as I look at the production from your legacy fields, so kind of the fields that have been onstream for a number of years, the decline rates on those oil fields has been less than 3% for each of the last three years. That's kind of declined. Now that decline rate has come down quite a bit from, I think, closer to 7% back in 2012, 2013.
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? 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 have to do disposals in order to fund further acquisitions in this market? Thank you.
Okay. Thank you, Anish, for those questions. On the NCS liquid production, I think the decline rate has been around 5%, there's no change to that. In this quarter, we more than offset that due to well productivity, high regularity, one of the highest quarters on the regularity. We have not changed our view on the 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 Karachaganak transaction, the swap with Repsol, getting the full operatorship of Eagle Ford, divestments 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. That concludes my M&A part.
Thank you.
The next question comes from Anders Holte of Danske Bank. Please go ahead.
Yeah. Good afternoon, guys. Anders Holte from Danske Bank here. Just a quick question on CapEx. Now we've seen obviously very strong cash flow for this quarter. If we continue to see same strong cash flow numbers in the quarters to come, is there enough projects in your portfolio to hike activity further, i.e., will there be a potential CapEx hike, 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?
Thank you, Anders. I think I'm proud of the world-class project portfolio that we presented on the capital markets update with an average break-even well below the current oil price level. CapEx 2017, it's according to our expectations. We will be around NOK 11 billion in CapEx this year. We have 7 projects scheduled to be sanctioned in 2017, 2018, as said at the CMU. We have sanctioned Njord and Bauge, and we will decide later this year on Johan Castberg.
Okay. Thank you.
We'll now take the next question from Iain Reid of Macquarie. Please go ahead.
Yeah. Hi, guys. Thanks. Thanks for the call. Just a quick question on your cash tax payments. I think you said earlier, there's gonna be two installments in the second quarter of NOK 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?
Second question is on your efficiency improvements of $1 billion this year. Can you say what proportion of that billion you've captured in the first quarter? Obviously we're seeing year-on-year improvements, but that, as I said, 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. Thanks a lot.
Thank you for those questions. I'll take the efficiency improvement, and I'll hand over the cash tax payments to Ørjan. We are on track on realizing the NOK 1 billion in savings in 2017, but no further detail provided at this point in time. Ørjan, on the cash tax payments, we have installments due in the second quarter?
Yeah. Cash taxes for first quarter is $2.2 billion. You see that from the balance sheet, it increases by $1.5 billion, and we paid on $ 6 billion. We increase the taxes by $4.7 billion this quarter. For the next quarter, we have sort of two tax installments on the level of this first quarter. But we had only one tax installment this quarter.
Yeah, no, I understand that. You also talked about the second half payment, so third and fourth quarter. Can you give some outlook for those please?
Svein, If you look at that, and I alluded to earlier, that is, if you look at the taxes payable for this quarter, $2.2 versus the paid taxes of $0.6. Remember that the taxes on the NCS, we are still paying taxes based on the 2016 earnings. In the second half, we will start to pay taxes on the 2017 earnings.
Of course it will also then depend on the oil price and gas price that we realize in the second quarter, and also the outlook for the remainder of the year. Because then when we come towards end of June, we are then deciding on the level of taxes that we are paying in on NCS. That will be for August, October, and December at another level.
It's a bit too early to comment, but definitely expect higher taxes in second half.
Okay, guys. Thanks a lot.
We'll now take the next question from Alwyn Thomas of Exane BNP Paribas.
Morning, all. 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? 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? Thanks.
Thank you, Alwyn, for those questions. On the exploration, the success rate is quite high. We have completed, as you said, nine wells, eight on the NCS and 1 in the U.S., and 7 out of these were discoveries. Examples like Cape Vulture, the Valemon West, Osprey, Alvheim two and three, and Copernicus 1 in the U.S. are examples. These are good examples of additional volumes that could be turned into production. They are economically viable and producible, and add volumes to business, so we can turn them into profit. We have two wells ongoing in the quarter. We have the Barents campaign coming up. 5-7 wells there.
Three potential high-impact wells included in that campaign. In the second quarter, we would know more as we are planning to start in relatively short periods of time. That would be exciting. On the Sverdrup, the drilling and well progress, I think, you all heard the story of the perfect well and the improvement work that we have done in the drilling and well, with 69% more meters today, more than 40% less 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 eight months ahead of schedule. Very, very quick and efficient, I would say world-class drilling. 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, you know, the results from these wells?
No further update today.
Worth a try.
based on this quarter.
Okay. Thank you.
As a reminder, ladies and gentlemen, if you wish to ask a question, please press star one on your telephone keypad. The next question comes from Ann e Gjøen of Handelsbanken. Please go ahead.
Yeah, thank you. I have a question related to Norway. The tax rate in Norway, the adjusted tax rate in first quarter was 73%. If we assume oil price level close to the level of today, $50, since the investment is pretty low, is it likely that the tax rate is going to increase onwards? 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? Thank you.
Yeah. Thank you, Anne, for those questions. The guiding range for tax in Norway is 70%-72%. We are fairly much in line with that in this quarter. The lower prices increase the tax rate, and over time, you should expect a falling tax rate, particularly if prices further recover. That's the main comment to Norway on tax. On DPN production, well, first of all, it was a very strong production in the first quarter over 753,000 barrels per day, so 3% up. That was mainly the startup and ramp of Corrib, the In Salah, and the southern fields, and just partly offset by the divestment of West Virginia and Leismer.
Going forward, the impact of turnaround 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. Overall on the group level, the impact of turnaround this year will be 30,000 barrels per day. Svein Skeie, you might provide some additional details on DPN production going forward.
Yeah. There will be on the turnaround some minor impact on Brazil also in the second quarter. The main thing in second quarter on the turnarounds will come from Algeria and then some smaller things from Angola. The main thing in second quarter in DPI would be in Algeria.
On the PSA effect, we might comment specifically on that. Our guidance there is 150 at 40 and 165,000 barrels at $70 for this year.
Thank you.
The next question comes from Brendan Warn of BMO Capital.
Yeah. Thanks, guys. It's Brendan Warn from BMO. Just, I just want to circle back around on the free cash flow or the cash flows for the remainder of the year. Just to clarify, obviously you've had a strong quarter, but 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 gonna have turnarounds that'll impact cash flow from operations. You've obviously got some higher taxes to pay over the next three 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.
Thank you, Brendan, for asking that question. It was a strong cash flow and it reduced the net debt ratio to 30%. We are just within the range, the ambition range of the 15%-30% this quarter. Still with some quarter-specific this quarter and the tax installments and things that will come up in the second quarter and the maintenance, as you say. At the current prices, you could see a further reduction in the gearing.
What we said at the CMU is that the guidance we have provided for 2017 and 2018, there are some phasing issues which might benefit this year, and that include the level of planned maintenance and lower cash tax reflecting the lower earnings in 2016 in Norway. We are not increasing our guidance provided on two months only. It's still valid. It's a good development in the first quarter. Taxes will increase, so will the dividend payments. The CapEx run rate will be still within the guidance that we have provided. That's my main comments to the development in the gearing.
Okay. Thanks for the hand.
The next question comes from Marc Kofler of Jefferies. Please go ahead. Marc Kofler , your line is open. Please go ahead.
Oh, hi, everyone. Thanks for taking my question. I just wanted to come back with a few follow-ups around the production guidance and outlook the rest of this year. In Q1, Hans Jakob Hegge talked about the high production regularity on the NCS. Are you able to give a bit more color around that and facilities uptime, perhaps relative to Q4 2016 or even year-on-year? That would be very helpful. Could you also just elaborate or give us some color around the volume growth trajectory in North America? Thanks very much.
Thank you, Marc , for those questions. On the production guidance, overall, it's not changed. It's 4%-5% for 2017 and under 3% CAGR for 2016-2020, as you said a couple of months back. The main drivers behind the strong production this quarter is rampable fields like Ivar Aasen, the Corrib, the In Salah and In Amenas, and the increasing 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. We also had more than 30,000 barrels increased flex gas production from Oseberg.
If I'm not wrong, I think this is in the top three on regularity if you look a few years back in time. It's well above 90% regularity. If you just pull up on the Peregrino, the plant maintenance, also the Peregrino regularity, you know, in our Brazilian operation is at par. It is definitely high production regularity and uptime. No further change to our volume guidance.
Okay. Just on North America-
You also mentioned the U.S. I almost forgot that one, so sorry for that. As I said earlier, we had a lower Bakken production onshore due to weather, but the wells are now back. There is also some effects on the Eagle Ford operations due to the, in a way unusual, harsh winter conditions going forward. At the moment, we have five drilling rigs in operations in the U.S. onshore. You might expect to see somewhat higher U.S. onshore production in the second half. To put this year in perspective, we have a low turnaround activity compared to last year. Going forward, we will also increase completions in the rest of 2017.
That's great. Thanks very much.
Thank you.
Okay. With that, I'll take the opportunity to close the call. Thanks to everybody for joining us today. Thanks to my colleagues. Appreciate your time. If there's, as always, any further questions, please don't hesitate to contact us in investor relations. Thanks a lot. Good afternoon.