Peter Hutton - IR Hans Jakob Hegge - EVP & CFO Svein Skeie - Head of Performance Management and Risk Ørjan Kvelvane - Head of Accounting

Brendan Warn - BMO Capital Markets Martijn Rats - Morgan Stanley John Olaisen - ABG Jon Rigby - UBS Ilkin Karimli - Credit Suisse Oswald Clint - Bernstein Teodor Nilsen - Swedbank Biraj Borkhataria - RBC Michael Alsford - Citigroup Lydia Rainforth - Barclays Rob West - Redburn Tom Robinson - Deutsche Bank Kim Fustier - HSBC Hamish Clegg - Bank of America Halvor Strand Nygård - SEB Enskilda Anish Kapadia - Tudor, Pickering, Holt & Company

Good afternoon, ladies and gentlemen, and welcome to the Statoil First Quarter 2016 Analyst Call. My name is Peter Hutton. I’m Head of IR. And with me I have Hans Jakob Hegge, CFO, who will be leading the call; as well as Svein Skeie, Head of Performance Management and Risk; and Ørjan Kvelvane, Head of Accounting. Hans Jakob will run through a presentation for around 12 or 15 minutes on the results and the drivers, and then as normal, we will open up for questions. And it will be explained how you can poll for those questions. We expect to end the call by around 1:30 U.K. Time. And with that, let me give the word to Hans Jakob.

Thank you, Peter, and welcome to everyone attending this conference call. Despite the challenging surroundings and the uncertainties in our industry, I am happy to present the result with continued strong underlying performance and visible progress on our improvement agenda. I’ll give a brief introduction to our numbers, and then open up for questions in a few minutes. My main messages to you today are that we are on track on delivering on our CMU priorities. Costs are continuing to come down and we are capturing sustainable efficiencies, and production efficiency continued to improve for the third year in a row and is now at record-high levels. This quarter is characterized by the low commodity prices that impact not only our results, but also affects our focus and actions, and we continued to deliver strong operational performance with sustained high regularity. And this is reflected in an underlying organic production growth on the NCS of 2%. We have converted to U.S. dollar reporting. This is a natural development for reporting as Statoil is a U.S. dollar company. It will also simplify our communication with investors. And finally, the Board has approved a first quarter dividend at $0.2201 per share, and we intend to offer a scrip dividend with a 5% discount. This is subject to approval of the scrip program by the AGM on May 11. Looking at the financial results, we report a net income for the quarter of $611 million compared to a net loss of $4.6 billion in the first quarter last year. As always, we make adjustments to reflect the underlying business, and this quarter we adjusted result downwards by $203 million, mainly as a result of reversal of impairments, compared to a positive adjustment of $6.2 billion in the first quarter last year. The reversals reflect lower operating costs and are not related to higher price assumptions. The adjusted earnings after-tax ended at $122 million compared to $902 million in the first three months last year. These results reflect the steep reduction in the price achieved in the first quarter. Brent averaged at $34 in the first quarter compared to $54 in the same period last year. On the positive side, our results also reflect a sustained high production regularity and strong production. We also see visible cost reductions and efficiencies coming through. Adjusted OpEx, SG&A was reduced by 20% year-on-year. The adjusted tax rate in the quarter was 85.8%. This is a result of three factors. First, with lower prices, the effect of the uplift tax credits takes down the effective tax rate on NCS. Second, the MMP segment with a low tax rate - had a low tax rate in the quarter due to higher production of income in countries with low effective rates. And finally, it is a result of the international tax rate caused by earnings composition, with losses in jurisdictions without a tax shift. Moving to adjusted earnings by segment. So let me take you through our segments and let me start with Development and Production Norway. We report an adjusted earnings of $1.3 billion compared to $2.4 billion in the same period last year. Although the result is affected by the oil price development, the quarter also shows good results from production efficiency, well above 90%, as well as continued good progress on cost reduction. We can report a 25% reduction in OpEx and SG&A per barrel in NOK. Let me remind you that the second and third quarters are typically busy maintenance periods and you should typically expect higher unit production costs as volumes are lower and costs are higher. Depreciation was down by 7% in NOK in the quarter. Reported in dollar, the DD&A was down by 17%, reflecting the high deduction from fields with relatively lower DD&A per barrel, as well as a reduction in asset retirement obligations. In the coming quarters, you should expect the DD&A rate to trend upwards. This is due to new fields ramping up and a lower gas off-take. From our upstream operations outside Norway, adjusted earnings was negative $800 million, compared to a negative $282 million in the same period last year. The results were significantly affected by the low commodity environment. Having said that, we are pleased to see that the positive cost trends continues in the part of our business, with a 14% reduction in adjusted OpEx and SG&A per barrel. The main drivers for this reduction was lower operating and maintenance costs, in addition to positive contribution from lower dividend expenses and reduced royalties following the price reduction. DD&A per barrel was reduced by 13%, mainly as a result of revised reserve bookings and impairments, partly offset by ramp up of new fields. And finally, our results from our MMP segment, which continued to deliver good results in demanding markets. The adjusted result in the quarter was $431 million compared to $890 million in the same quarter last year. The reduction was driven by warmer weather and volatility in the gas price. We saw strong contributions from the refineries and from our liquids trading business. Looking at our production. The daily production in the first quarter was just over two million barrels. This reflects the high regularity and the seasonal gas off-take. In Norway, we continued to produce at high regularity, and the production efficiency this quarter is the best we have seen since we started reporting. New fields on-stream and ramp ups of fields contributed positively to maintaining production at the same level as last year. And among these were the Heidelberg in Gulf of Mexico, Kizomba Satellites in Angola, Corrib in Ireland, as well as Valemon and Edvard Grieg on the Norwegian Shelf. In addition, our production increased as a result of our increased share in Eagle Ford. This was offset by divestment of Shah Deniz and a stake in Gudrun, as well as a decision to produce less from Oseberg, as a part of our flex gas value over volume strategy. Then on cash flow. The cash flow from operation is clearly affected by the low price environment that we’re in, and we paid one tax installment on the NCS in the quarter. Remember that this payment is based on the oil price for 2015. We continued to see a positive trend on reducing CapEx through efficiency and strict capital prioritization. Note that the CapEx figure includes our financial investments in Lundin, representing 0.7 percentage points on our gearing. Our net debt to capital employed was 28.1% at the end of the first quarter. This is up from 26.8% at the end of last year. If you look at our outlook, we continued to focus on our improvement program, as we discussed at the Capital Markets update in London in February. Our outlook remains unchanged. CapEx is expected to be around $13 billion, and we anticipate an organic production growth of around 1% for the period 2014 to 2017. Maintenance is expected to be around 60,000 barrels per day for 2016, with a quarterly impact of 55,000 barrels per day expected in the second quarter. And we do expect to spend around $2 billion on exploration this year. Let me also give a comment to the scrip program. The Board of Directors has approved a scrip program for the first quarter, in line with the program for the fourth quarter, assuming approval of the program at the AGM. We will distribute formal information about the practicalities for the fourth quarter scrip process around a month from now, and subsequently, shareholders can elect whether to opt for shares in early June. And with that, I hand the word over to Peter to lead us through the Q&A.

Thank you, Hans Jakob. So, yes, we will now move to questions. So I’ll ask the operator to open up the lines and we’ll take that through. We’ll go through - try to keep this fairly short and swift, one or one question with a follow-up if we can, please. Thank you very much.

We will now take our first question from Brendan Warn from BMO Capital Markets. Please go ahead.

Yes, thanks, guys. Thanks, Peter, Hans for the opportunity to ask questions. It’s Brendan Warn from Bank of Montreal. I guess just one question and it relates to your international business. Hans, if you could just talk through and if you break it down by the components that go into that division, if we’re still in a sort of $40 to $50 oil price environment this time next year considering the new fields that have started up, a number of them are in that international segment. Just where will we be both on earnings in terms of if we’re back into positive earnings, but then also in terms of cash flows, and just if we can tie it back to the Capital Markets Day statement and if we can keep it related to this international business, just in terms of cash neutrality at $60 a barrel, please.

Okay. Thank you, Brendan, for asking that questions. First, let me just say that it’s obviously challenging at current prices and prices realized in the first quarter, given that with the Brent at $34 and our realized price is bit just below $26. As you’re aware of the adjusted earnings for the international was minus $800 million. And as you also know, we are structurally more exposed to the oil price than the Epn due to the historic costs and the lower margin, as well as differences in quality of the products. So do we have a discount on some heavy-oil fields? Also, elements taking into account like a bit of an over lift in the beginning of the quarter when prices were low. So this explains the result that we are presenting. Having said that, we also have a positive development on the control elements like the adjusted OpEx and SG&A per barrel, which is down 14%. So we see a positive trend on the earnings. And we have presented a plan force to 2018. Remember Torgrim talked at CMU about the plan from $90 to $50. And we’re talking about cash neutrality and it will also depend on the CapEx level, and - which again will depend on factors such as activity level, not only the oil price, but also future exploration success. So overall, to be very specific on int for next year is hard, but we are doing activity adjustments like the onshore business in the U.S., where we only have on rig crew in each area and no fracking crews in the first quarter.

Can I just ask a follow-up question? Just in terms of your growth then certainly into 2017, what I assume at this sort of price and certainly gas price because a lot of it’s coming from U.S. onshore that would actually begin to decline rather than a 1% CAGR growth?

If I understand your question correctly, Brendan, you’re talking about the production guiding forward, and as I said, it’s a 1% overall for the period ‘14 to ‘17. Depending on prioritization, we could adjust the activity level up and down on the onshore business, whereas the - so that’s the main component in the flexibility short-term.

Okay. Thanks, Hans. I will leave it there.

We will now take our next question from Martijn Rats from Morgan Stanley. Please go ahead.

Hello. Good afternoon, gentlemen. Thank you for the presentation. Just shoot a question from my side and perhaps a quick follow-up, if that’s okay. First thing is just on depreciation. Hans Jakob, you talked about that that’s been obviously coming down and that it might start to go up again as fields ramp up and you get less gas contribution. Can you perhaps just give us a sense of how you’re quantifying that, just because we’ve seen such a big decline in DD&A per barrel, things like DPN, DD&A per barrel now down to sort of just over $10 a barrel from sort of $12, $13. Does that revert back to the sort of $12, $13 level that we saw about a year ago, or actually is it not going to be quite as severe as that? The second question or a follow-up perhaps is just on the gas business. And you’ve sort of highlighted the weak result that you had in the trading side in the quarter. I just wondered if you could just talk a little bit more about this, and just perhaps more broadly, just your thoughts - latest thoughts on the European gas market? We’ve obviously seen quite a big recent move in the NBP. I don’t know well positioned you would be able to take advantage of that, but is that something that you can benefit from, or is that sort of volatility actually not very helpful in your trading business? Thank you.

Okay. Thank you, Martin, for asking that question. First, the DD&A development. And it’s three main components. It’s currency around half. It’s the asset retirement obligations, and it’s the new fields. So, if you look at the depreciation, in the first quarter, it was down by 13% and a significant component is currency. So in the international part, it’s higher production from startup and ramp ups of the various fields, plus the effect of previous year’s impairments. Whereas on the Norwegian Shelf, it is also decreased production from fields with a high DD&A rate, like the Gudrun field, and we also have increased production from fields with relatively low DD&A rate, like Snøhvit and Ormen Lange, but also the effects of the ARO obligations. To your second question about the gas business and the trading results and the gas market going forward. That’s obviously a huge and important question. And if we look at the MMP segment overall, we were good on the refineries with high production efficiency, quite healthy margins, and liquids trading okay, gas somewhat lower. Why? 31% lower average sales price due to abundant gas supply and a relatively mild winter, and we are also more exposed to shorter term contracts in this quarter. But overall, MMP good in the upper end or guiding of $250 million to $500 million. Looking at the gas market moving forward, it is obviously a lot of elements into this, but the starting point is that the EU gas market is well supplied short-term, both with gas from Russia and from Norway, and potential some new LNG volumes coming in. So far this year, we see limited U.S. LNG volumes reaching the EU. And we also see upside going forward linked to switching of coal in to - from coal to gas in the U.K. Groningen is capped at 27 bcm for ‘16. And due to the shipping distance, it is expected that the Australian LNG will end up in Asia. So the U.S. LNG will more flow according to the price signals in the market. So long-term, we have a positive view on the European gas, and Norwegian gas is competitive in this market with our trading position.

Thanks, Hans Jakob.

Our next question comes from John Olaisen from ABG. Please go ahead.

Hey, good afternoon, gentlemen. A question on exploration and CapEx spending. If I take the numbers for Q1 and multiply them by four, I get quite below your analyzed guidance. I just wonder, is this due to timing within the year, or have you started off slowly to give us [Technical Difficulty].

Sorry, John, I can’t hear you. But it was a question around the CapEx and the low run rate. First of all, as you’ve seen, we maintained a strong capital discipline and quite strict prioritization. We maintain our guiding on CapEx. And I think we should be cautious not base the full year on a quarter. We expect higher activity during the year. Sverdrup execution is a key part, so also starting execution on Peregrino phase two, and the potential U.S. onshore. So the organic CapEx of $2.4 billion is in line with our guiding on the $13 billion.

Okay. And for exploration?

Exploration, I give that to Svein Skeie.

Yes. On exploration, as we guided at the Capital Markets Day, we expected them to have a spending of around $2 billion for the year. We have spent a little bit more than $300 million this quarter. So we are then - but we are remaining or guiding of around $2 billion. So we also expect that this will come up somewhat later, so we remaining with the guiding of around $2 billion for the year.

Yes, and…

Okay. I will have one - sorry, Hans.

No, it’s just to add, John, that as Svein said, while maintaining the guiding we’re working hard on replenishing the portfolio. And this guiding that we have given is down from the $2.9 billion that we had previous year. So we are taking it down while replenishing the portfolio.

And my follow-up will be on exploration. If you could comment on the Gavea A1 well in Brazil, which you said to be a big success, but I haven’t seen any comments from you guys on that well. If you could comment on the outcome of that well, please.

Yes. The starting point is that the partners just completed Gavea A1, which is the fourth operation well in the license, and it was a positive well encountering 175 million hydrocarbon column, a good reservoir quality and a positive well test. So then you might add, what’s the next step? Well, that’s to evaluate the subsurface data from the appraisal program, as well as assessing the potential development solutions. So we expect to complete the operatorship transfer in the third quarter. So quite positive news from Brazil on that one.

Okay. Thanks a lot.

Our next question comes from Jon Rigby from UBS. Please go ahead.

Yes, thank you. Can I just ask a question on tax, both Norway and international actually? Could you just go back through the comments you made about the uplift and just sort of contextualize that about how that will play out through, let’s say, an oil price scenario kind of where we are now, sort of 40-ish up through 60-ish and how that will then sort of translate into your headline tax rates on the NCS? And then on the international side, for almost the entire period that you’ve been making losses in the international arena while oil prices have been low, you’ve been actually taking a tax charge. I guess that’s on mixed effects, and then this quarter with the lowest oil prices that you get some credit back. So I just wanted to understand as we move forward, what we should be expecting all things equal, in terms of tax debit or tax credit in relation to the international business? Thanks.

Okay. Thank you, John, for asking that question. Overall as I said, the tax was 86%, which is relatively high. And the tax rate was negatively impacted by the loss in int and the limited tax protection we have there. If you look at the DPN, the low tax rate on adjusted earnings is a result that we have a higher effect of the uplift deduction due to low adjusted earnings, with a 64% tax on the adjusted earnings for the NCS. We also have relatively low tax rate on the adjusted earnings from the MMP segment, caused by earnings composition. And lower prices increases the tax rate. And we expect fluctuations in the tax rate in the current volatile environment. Regarding the taxes installment, it’s quite limited effect on this quarter. We’re talking about $40 million due to an overpayment on taxes in the three - in the first three installments paid in 2015. So that actually led to a lower installments payable in 2016. Going forward, around 70%, 72% in periods with high oil prices and we shouldn’t expect material changes to short-term if you’re assuming flat prices. But if the prices go up you should also expect a higher tax rate. But within the int segment, it will be very much driven by results.

Just on the international business, you’ve - so I understand it’s been unable to shelter losses in certain countries with profits you’ve made in others, but it would appear that in terms of either the composition of your production or potentially the costs reduction that you’ve been able to achieve in different countries, you’re now into a situation where that’s not the case and you’re able to sort of have a tax rate that is at least directionally consistent with the losses you’re making, i.e., credit. Is that a reasonable assumption that - or is it a reasonable assumption that that will be the case while you are loss making in the international business going forward?

Okay. Ørjan Kvelvane, the Head of Accounting would you like to answer that one. Ørjan Kvelvane: Yes. So as a starting point, it is more difficult to determine in recognizing taxes when we’re making losses because we need to defend that we are having convincing evidence that will be utilized in the short-term. So as you see from the 20-F that we have published, we have unrecognized deferred tax assets in U.S., in part of Angola, so that’s a split, and Canada and Ireland and also part of Brazil. So that - in a low price environment, that is more challenging but that is an assessment that we do period for period.

Right, okay. So there is some recognition of a change of that view in the first quarter. Is that fair to say? Ørjan Kvelvane: So there is not much changes to the position by year-end.

Okay. All right. Thank you.

Our next question comes from Ilkin Karimli from Credit Suisse. Please go ahead.

Good afternoon, gentlemen. Thanks for taking my question. I have one general one. You have done an impressive job in terms of cost cutting and have significantly reduced breakevens for your projects. So given your peers are not taking FIDs at the moment either, isn’t now a good time to do that i.e., to take FIDs, given you would have better access to teams, infrastructure, et cetera? So I’m trying to understand what is the holding factor here? Is it further cost efficiency that you are planning, or is it more certainty on the oil price side that you’re waiting for? Thank you.

Okay. Thank you, Ilkin, for asking that question. Remember first of all, we invest a lot in Johan Sverdrup, which is a capital intensive and a world-class project. We also sanctioned the Oseberg Vestflanken on the NCS in December and [indiscernible] is expected later this year. What determines the point of FID-ing a project? If you think the project could be optimized further, I think we should carry on the improvement work and really work on it, and we also make an assessment of the capacity in the supplier market and the timing of the sanctioning related to the market prices.

Understood. Thank you.

Our next question comes from Oswald Clint from Bernstein. Please go ahead.

Yes. Hi, good afternoon. Thank you. Maybe just some questions on information within the release today. I’m curious again on the European gas business with your invoice gas price. It tended to come in much, much higher than hub prices in the quarter. Was there anything specific in the quarter that made that invoice gas price be so high relative to hub or anything we have to consider? And then secondly just on the impairments and specifically the counter reversal of impairments which I know is something you do every quarter, but I think it’s referring to some unconventional shale assets, I’m curious which asset that is, and what’s really triggering that impairment reversal? Thank you.

Okay. Thank you, Oswald, for asking that question. Let me start with the last question on impairment and reversals. Overall in the quarter, we - first of all, let me say that we are clearly exposed to the impairments and the reversals given the volatility in the prices. In note 6, you would see that the net impairment charges is $308 million before tax. We had a $600 million overall reversals and $300 million in impairments, which gives a net of around $300 million. We do the assessment of the impairment triggers, and this has resulted in some impairments as I said, but even more reversals, and these are according to the IFRS standards, but it’s mainly onshore assets in North America and conventional outside US. Looking at the EU gas market and the invoiced gas price, we will give that question to Svein Skeie to start with.

Yes. As you referred to, it was probably the invoice price above, for example, the NBP price, where we have seen that we are selling the prices or on the invoices prices is quite a bit higher than the NBP. That comes from a situation where we are then selling gas at - not everything at the spot or the day head prices, but we have a structured sale with partly coming from day head, partly coming from monthly head or season head, and that has then given a higher price on the invoice price this quarter compared then to the NBP, which is then more the spot prices.

Okay. Good. Thank you.

Next question comes from Teodor Nilsen from Swedbank. Please go ahead.

Good afternoon, and thanks for taking my question. I have two questions on OpEx, particularly in Norway. I notice that the IFRS OpEx that you reported in the past few quarters is substantially higher than the adjusted OpEx you have reported. I think it’s $1.3 billion on the past five quarters. I just wondered what’s this difference related to, is it like only cost-cutting initiatives, which is these $1.3 billion?

Okay. Thank you, Teodor. First of all, cost savings is going to according to the plan, but as I said, we also see some currency effect. And adjusted OpEx and SG&A decreased by $590 million overall, which is 20% as I said, and on the NCS, 25% per barrel, but also impacted by some quarterly specifics. We see mainly efficiency gains now and we also expect some market effects to come. When it comes to more specific examples, we have lower O&M costs on the NCS. We have lower well interventions on the NCS. And we also see that we have some quarterly specific, like the pension costs, and we will have more maintenance going forward, as I said in the second and third quarter. So that’s the main points on the NCS OpEx SG&A.

My question was more referring to the difference between the adjusted OpEx, which I think is the numbers you referred to and the IFRS OpEx, which is $1.3 billion higher in sum from first quarter 2015 until first quarter 2016. Is it possible to explain that difference?

Yes. Ørjan? Ørjan Kvelvane: So I do not have the exact figure that you’re referring to, Teodor. But in general, so we have the over under-lift adjustment in the adjusted earnings. That will impact that amount. And then we have in some quarters some provisions that is clearly not part of the underlying in that quarter, that also explains part of this. But I do not have the exact five quarters in front of me. But that is it in general.

Okay, thank you. And then just one follow-up when it comes to OpEx on next few years, assuming somewhat higher oil prices. Do you think the current OpEx level should represent a proxy for what we should expect over the next few years?

Well, as we’ve said, this is mainly efficiency gains. Some currency effect, but mainly efficiency gains. We do more work ourselves. We have become more efficient. So that’s what we are aiming for to actually maintain the efficiency that we have, and that’s our main guiding that we are working structurally through the improvement program. We see a good progress and we are trying to stick to the new improved efforts.

Okay. Thank you.

Our next question comes from Biraj Borkhataria from RBC. Please go ahead.

Hi guys. Thanks for taking my question. Just going back potential project sanctions. You mentioned at your Strategy Day that you had a group of projects that the average breakeven was close to $40 and we’re kind of around there now. So in the scenario that you may want to sanction these projects and you feel like they’re at the optimum position to sanction, what impact would that have on your CapEx guidance, i.e., are you committed to spending $13 billion, or could there be upside to that number, as and when you sanction these projects? Many thanks.

Thank you for asking that question. That was one of the main key messages on the Capital Markets Update that we, as you said, have brought down the breakeven on our portfolio by $30, and we are maturing these projects. And we have $4 billion to $6 billion in flexibility in our CapEx in ‘18 and ‘19. And we can choose to sanction some of these if we want to, if we think the timing is right and we have the right concept. But we do not have to do it, and it has little impact this year. And any sanctions will impact - will mainly impact CapEx in the next coming years.

Okay. Thanks.

Next question comes from Michael Alsford from Citigroup.

Thanks for taking my questions. I’ve just got a couple actually on some of the transactions that you’ve done through the quarter. Just firstly on the wind deal. Could you maybe just talk a bit about whether this is a sign that you’re seeing an increasing capital allocation towards renewables, or is this very much within your plan and guidance on spend? And perhaps just could you contextualize the return that you’re looking to target in these renewable projects relative to your typical oil and gas business? And then just secondly, just following up on the potential sale or the planned sale of some non-core properties in the U.S. in your non-conventional business? Could you perhaps just give us some indication on - or if there is a volume impact associated with that sale, please, in terms of production loss? Thank you.

Okay. I think I’ll take the second one first because as of April 20, we entered a confidential agreement to divest a non-conventional non-core property in the U.S., and this is a $400 million in cash consideration, but we do not expect to either gain or realize any gain or loss on the transaction. But it’s confidential, and we will have more project - more information later related to that as a part of the agreement. Looking at the wind. If you take the last investment, it is a 50% of a wind park, Arkona-Becken, that we bought from E.ON as a part of the cooperation. It is 2019 which is the startup date supporting electricity households - 400,000 households in Germany. Looking at the size of the investment, it’s $100 million this year, compared to an overall investment program of $13 billion. It’s not a very big investment. And looking at the attractiveness of this, we think it’s a fair return for a different risk profile. We do not have the subsurface risk in this project and we have different risk profile. And it’s supplementing our core E&P business as a part overall strategy that we’ve communicated that to CMU.

Okay. Thank you.

Our next question comes from Lydia Rainforth from Barclays. Please go ahead. Madam, your line is open.

Thanks and good afternoon. A couple of questions, if I could. The first one was just looking at the record quarter for efficiency. Clearly there has been a lot of progress made there, but it does make it very difficult to understand what’s happening to the underlying decline rates, and I’m just wondering if you could comment on that? The second one - sorry to come back to the cost data, but on the per barrel numbers on the international business, it did look like it flattened off quarter-on-quarter in terms of per barrel costs. I’m just wondering whether that was just a seasonal factor, or just whether or not you’ve actually got most of the cost savings in the international business you might expect at this point? Thank you.

First, thank you, Lydia. There are no major changes on the decline rate. It’s around 5%. And the second question, if I heard you right, is about international business and any seasonal factors.

Yes, right.

Well, on the gas side, we had a relatively mild winter in the U.S. But that’s weather. Svein, you want to fill me in on this one?

If you look at the overall on the int, we have now seen per barrel measured in U.S. dollar approximately 14% this quarter when we compare with quarter last year. That is more or less in line with what we have seen over earlier quarters as well, as we have reported, special seasonalities. We have had some lower activities on the onshore in U.S. But on the total portfolio, it’s no major seasonality on the int part of it.

It’s helpful. Thank you.

Our next question comes from Anish Kapadia from Tudor, Pickering, Holt & Company. Please go ahead. Please go ahead, Anish. Your line is open. It seems they may have stepped away. We will now take the next question from Rob West from Redburn. Please go ahead sir.

Hi there. Thanks very much. My question’s really about Oseberg. I’m just going through your field by field data. What really surprises me is the magnitude of how much that field decreased year-over-year on the gas production? So it went from 67,000 barrels a day of gas in 1Q ‘15 to 12,000 barrels a day of gas in 1Q ‘16. That decline, so that’s about 2.5% of all of your production. So that’s clearly a really big moving part. Can you talk a bit about that decline? I’m guessing it’s intentional and part of your value over volume gas strategy. But can you talk about how much time or cost would you need to bring back that 50,000 barrels a day, and what would be the trigger for you to do that? Thank you.

Okay. Thank you, Rob, for asking that question. These are fields that I know fairly well. And Oseberg and Troll are the fields that provide the flexibility. So this is part of our flex gas strategy. And Oseberg can start up in relative short-term. Troll any minute; Oseberg a bit longer. But this is something that we have done - as you correctly said, it is value over volume.

So what would make you bring those volumes back? I mean, as we all look to - can you maintain this production rate and can you keep growing, what do you need to see to produce those volumes?

An increase in the prices.

Can you say on what level or prefer not to?

Well, we don’t go into details on that one. But if you look at the past performance of Oseberg, you have seen higher prices and higher production from Oseberg. So increase in prices.

Okay. Thank you.

Next question comes from Tom Robinson from Deutsche Bank. Please go ahead sir. Your line is open.

Yes. Afternoon, everybody. Just one question on the domestic business and rig contracts. Would you be able to provide an update on the Norwegian rig fleet in general, and how active you’ve been in renegotiating terms? And if so, is that something that is included in the current efficiency savings target, or would any progress here be incremental to that? Thank you.

Well, the overall message on the rig is that we have the rig capacity we need for now, and we have done cancellations to rigs within the existing frameworks in order to optimize this. Well, we come from a relatively high level of good commitment that we have taken down and we are fairly balanced at the moment.

And just to follow-up, I mean, are these predominantly dollar-denominated or NOK-denominated?

Floaters are in dollar.

Thank you.

We will now take the next question from Hamish Clegg from Bank of America. Apologies, we will now take the next question from Kim Fustier from HSBC. Please go ahead, Kim.

Hi, good afternoon. My first question might be related to a previous one on tax. But I noticed that you wrote off part of the DPI deferred tax assets because of uncertainty on future taxable income. I wondered if you could elaborate on this and maybe tell us which assets specifically you’ve become less confident in perhaps? And secondly I know it’s early days, but could you give any guidance at all on the level of the scrip dividend take-up that you expect? Thanks.

Thank you. Ørjan will take us through that question. Ørjan Kvelvane: Okay. So this is about an assessment, country-by-country, field-by-field. So in some countries, we go down to field level. We are not specific on which country we are talking about, but this is an assessment that we do every quarter and it’s about how we can defend keeping the tax asset in the balance sheet. And if the prices are going down in general, the uncertainty increases and we take a valuation allowance related to that.

And then to the scrip. Overall feedback has been good, but the take-up rates remain to be seen of course, and we do not have any forecast to share with you on this one. If it is approved by the AGM, there will be no issues that have been brought - there will be no issues that have been brought to our attention. It is in for one month from now from the company and the election in June. So we think we have an attractive offer with the 5% discount.

Okay. Thanks.

We will now take the next question from Hamish Clegg from Bank of America. Please go ahead.

Hi, thank you. Yes, just a question and a follow-up, please. I wondered if you could talk us through a little bit about progress on Johan Sverdrup and the possibility of debottlenecking leading to a higher plateau rate? I noted that some of your partners in the project suggested there could be some upside to this. And relating to it as part of a follow-up, I wondered if you could walk us through sort of the - your depreciation in Norway, and how it could affect cash flows going forward with a view to the impact on tax? Can we see depreciation, which is running currently half of total CapEx for the Group kind of catching up with CapEx, or was this a level we can - well, you mentioned it would go up. But what’s a sensible percentage of CapEx appreciation we can expect? Thanks.

Okay. Thank you, Hamish, for asking those questions. On the Johan Sverdrup, the debottlenecking is definitely a question that is being discussed in the license. We recognize that some partners having sharing their thoughts on this when it comes to the upside potential and we have a clause dialog in the license, but we are working on it. So we do not have any new information according to this issue today.

Yes.

On the DD&A in Norway, it’s both CapEx and DD&A have flattened out in the recent years. But DD&A in this quarter is close to the CapEx level. And if we’re going forward, I think we - as I said, we both have decreasing production from fields with a high DD&A rate, like the Gudrun field, but we also have increases from more mature fields and we should expect some increase in the DD&A as new fields are ramping up both Edvard Grieg and Goliat, and later in the period you would have fields like Aasta Hansteen and eventually also Johan Sverdrup.

Lovely. Thanks so much.

The next question comes from Halvor Strand Nygård from SEB Enskilda. Halvor Strand Nygård: Yes, hello. Your Bakken production came down some 10% sequentially in Q1, and you said that you’re currently running one rig crew in each area and no frac crews. Can you give us some color on what you expect from the onshore assets in terms of production going forward?

Okay. Thank you, Halvor. As you are right, absolutely right, there has been one rig crew in each of the three areas in the first quarter and no completions in 1Q in Bakken. Having said that, we are bringing in a frac crew to the Bakken area, so we expect the team to do some completions going forward. Halvor Strand Nygård: And can you say something about the production levels in the next few quarters?

Yes. The quarter-on-quarter decline consequently not representative for what we expect going forward. But the beauty of the onshore business is the flexibility. So I do not - still I do not think it’s representative what we have seen quarter-on-quarter, the decline that we actually have experienced. So going forward, with increasing prices, you should expect a higher activity level including in the Bakken area. Halvor Strand Nygård: Thank you.

We will now take our final question from Anish Kapadia from Tudor, Pickering, Holt & Company. Please go ahead.

Yes, a couple of questions please. On the - just going back to the tax position. So your total unrecognized deferred tax assets in U.S. increased by around 150%. So you’re at about $5 billion in the U.S. I’m just wondering, does this make you more inclined to look at acquisitions in the U.S. rather than elsewhere around the world, and especially given your existing position? And then secondly, I was just wondering if you could give an update on your Canadian exploration and development plans? I think you mentioned you were going to give an update in Q2. So you’ve drilled five wells. You now have exploration appraisal wells over the last couple of years. Just wanted to get a sense of where you see yourselves with that Canadian offshore position? Thank you.

Okay. Thank you, Anish, for asking those questions. First to the tax and the deferred tax assets in the U.S. It’s definitely something that we can make substantial amount of money on when we can account on it. And does it make M&A more interesting in the U.S.? Well, unfortunately I won’t go into detail on this question as we have a policy of commenting on the M&A when we actually have a deal to announce, so that’s sort of the boring answer to that. But we follow the market closely. To exploration, it’s been quite - a relatively quiet quarter. We completed seven wells. We had two small discoveries on the NCS both the [indiscernible]. Under evaluation is [indiscernible] in the Gulf of Mexico. We have appraisal programs for Wisting Central in Norway and Gavea as I just talked about with positive results. Four wells ongoing. You mentioned Canada, Bay du Luth [ph]. An interesting one is Raya in Uruguay. Viti [ph] and Wisting Central on the Norwegian shelf. And we’re working on access. On the Flemish Pass, it is anticipated that Statoil will complete its 18-month drilling program focused on appraising the Bay du Nord discovery and exploring in larger Flemish Pass Basin in the summer this year, where to-date we have finalized drilling of seven wells, including sidetracks. So we intend to provide an update on the program and the data when they are fully evaluated and we have to come back on this issue.

Thank you.

As there are no further questions in the queue, I would like to pass the call back to our hosts for any additional or closing remarks.

Well, thank you, everybody. Appreciate the questions. As ever, if there are any follow-up questions, please don’t hesitate to contact the IR team and we’ll get back to you as we can. And we’ll let you get off to get ready for the next conference call that many of you will have in half an hour. Thank you very much for your attention and your participation. Thank you. Bye-bye.