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 Hegge 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 UK time. With that, let me give the word to Hans Jakob.
Thank you, Peter, and welcome to everyone attending this conference call. Quite the challenging surroundings and the uncertainties in our industry, I'm happy to present the results 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 CMD priorities. Costs are continuing to come down, and we are capturing sustainable efficiencies. Production efficiency continues 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 affect our focus and action.
We continue 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. 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 eleventh. 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 of last year.
As always, we make adjustments to reflect the underlying business, and this quarter we adjust the results downward by $203 million, mainly as a result of reversals of impairment compared to positive adjustments 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 of last year. These results reflect the steep reduction in the price achieved in the first quarter. Brent averaged $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 low prices, the effect of the uplift tax credit takes down the effective tax rate on NCS. Second, the MMP segment had a low tax rate in the quarter due to a higher proportion of income in countries with low effective rates. Finally, it is a result of the international tax rate caused by earnings composition with losses in jurisdictions without a tax shield. Moving to adjusted earnings by segment. 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 North. Let me remind you that 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 North in the quarter. Reported in dollars, 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 obligation.
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 offtake. From our upstream operations outside Norway, adjusted earnings was negative $800 million compared to a negative $282 million in the same period last year. Results were significantly affected by the low commodity environment. Having said that, we are pleased to see that the positive cost trend continues in the path 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 leasing expenses and reduced royalties following the price reduction. DD&A per barrel was reduced by 13%, mainly as a result of revised depreciation and impairment, partly offset by ramp-ups from new fields.
Our results for more MMP segments, which continued to deliver good results in demanding markets. The adjusted results 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 liquid trading business. Looking at our production, the daily production in the first quarter was just over 2 million barrels. This reflects the high regularity and the seasonal gas off-take. In Norway, we continue to produce with high regularity. 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.
Among these were the Heidelberg in Gulf of Mexico, Kizomba Sat. 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 Flexgas value over volume strategies. Our cash flow. The cash flow from operations is clearly affected by the low price environment that we're in, and we paid 1 tax installment on the NCS in the quarter. Remember that this payment is based on the oil price for 2015. We continue to see a positive trend on reducing CapEx through efficiency and strict capital prioritization.
Note that the CapEx figure includes our financial investment 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 continue 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. 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 expected in the second quarter. 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. Subsequently, shareholders can elect whether to opt for shares in early June. With that, I hand the word over to Peter to lead us through the Q&A.
Thank you, Hans Jakob. Yes, we will now move to questions. I'll ask the operator to open up the lines, and we'll take those through. We'll go through. Try to keep this fairly short and swift. One question with a follow-up if we can, please. Thank you very much.
Ladies and gentlemen, to ask your question, please press star one. We will now take our first question from Brendan Warn from BMO Capital Markets. Please go ahead.
Yeah. Thanks, guys. Thanks, Peter. Hans, for 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 a $40-$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 we'll be both on earnings in terms of if we're back into positive earnings, but then also in terms of cash flows, and that just if we can tie it back to your 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 question. 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 just below $26. As you're aware of the adjusted earnings for the international was -$800 million. As you also know, we are structurally more exposed to the oil price than DPN due to the historic cost and the lower margins, as well as difference between quality of the product. Do we have a discount on some heavy oil fields? Also, elements taking into account like a bit of an overlift in the beginning of the quarter when prices were low.
This explains the results that we are presenting. Having said that, we also have a positive development on the controllable elements like the adjusted OpEx and SG&A per barrel, which is down 14%. We see a positive trend on the earnings, and we have presented the plans towards 2018. Remember Torgrim talked at CMD about the plan from 90 to 50. We talk about cash neutrality, means will also depend on the CapEx level and which again will depend on factors such as activity levels, not only the oil price, but also future exploration success.
Overall, to be very specific on hints for next year is hard, but we are doing activity adjustments like the onshore business in the U.S., where we only have one 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, would I assume that this sort of price and certainly gas price, because a lot of it's coming from US onshore, that would actually be into decline rather than a 1% CAGR growth?
If I understand your question correctly, Brendan, you're talking about the production guidance forward. As I said, it's 1% overall for the period 2014 to 2017. Depending on price scenario, we could adjust the activity level up and down on the onshore business, whereas that's the main component in the flexibility short term.
Yeah. Thanks, Hans. I'll 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 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 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 to quantify that, just because we've seen such a big decline in DD&A per barrel, you know, things like DPN, DD&A per barrel now down to sort of just over $10 a barrel from sort of $12-$13. You know, does that revert back to the sort of $12-$13 level that we saw sort of about a year ago?
Actually, is it not going to be quite as severe as that? The second question or follow-up, perhaps is just,
On the gas business, and you 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 NBP. I don't know how well-positioned you would be able to sort of 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.
Hey, thank you, Martijn, for asking that question. First is 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 field. If you look at the depreciation in the first quarter, it was down by 13%, and a significant component is currency. In the international part, it's higher production from start up and ramp up of the various fields plus the effect of previous years' impairment. Whereas on the Norwegian shelf, it is also decreased production from fields with high DD&A rates like the Gudrun field. We also have increased production from fields with relatively low DD&A rates like Snøhvit and Ormen Lange. Also the effects of the ARO obligation.
To your second question about the gas business, and the trading results on the gas market going forward, that's obviously a huge and important question. If you 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. We're also more exposed to shorter-term contracts in this quarter. Overall, MMP good in the upper end or guiding of $250 million-$500 million. Looking at the gas market moving forward, it is obviously a lot of elements into this.
The starting point is that the EU gas market is well supplied short-term, both with gas from Russia and from Norway, and the potential of some new LNG volumes coming in. So far this year, we see limited US LNG volumes reaching the EU. We also see upside going forward linked to the switching from coal to gas in the UK. Groningen is capped at 27 BCM since 2016. Due to the shipping distance, it is expected that the Australian LNG will end up in Asia. The US LNG will more flow according to the price signals in the market. Long term, we have a positive view on the European gas. 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 4, I get quite below your analyst guidance. I just wonder, is this due to timing within the year? Or have you started off slowly to give yourself flexibility for potentially cutting CapEx and exploration spending if oil price gonna stay low?
John, I can't hear you. But it was a question around the CapEx and the low burn rate. First of all, as you've seen, we maintain the strong capital discipline and quite strict prioritization. We maintain our guiding on CapEx. I think we should be cautious not to base the full year on a quarter. We expect higher activity during the year. Sverdrup execution is the key part. So also starting the execution on Peregrino of 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. For exploration?
Exploration, I give that to Svein Skeie.
Yes, on exploration, as we guided at the Capital Markets Day, we expected to have a spending of around $2 billion for the year. We have spent a little bit more than $300 million this quarter. We are maintaining our guidance of around $2 billion. We also expect that this will pick up somewhat later in the year.
Mm-hmm.
We are maintaining the guidance of around NOK 2 billion for the year.
Okay. I only have one. Sorry Hans.
No, it's just to add, John, that you know, as Svein said, while maintaining the guidance, we are working hard on replenishing the portfolio. This guidance that we have given is down from the 2.9 that we had previous year.
Mm-hmm.
We are taking it down while replenishing the portfolio.
My follow-up would be on exploration, if you could comment on the Gavea A1 well in Brazil, which is said to be a big success. I haven't seen any comments from you guys on that well. If you could comment on the outcome of that well, please.
Yeah. The starting point is that the partners just completed Gavea A1, which is the fourth appraisal well in the license. It was a positive well, encountering 175 million hydrocarbon columns, a good reservoir quality and a positive well test. You might ask, 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. We expect to complete the operatorship transfer in the third quarter. Quite positive news from Brazil on that one.
Okay. Thanks a lot.
Our next question comes from Jon Rigby from UBS. Please go ahead.
Yeah, thank you. Can I just ask a question on tax, both Norway and international, actually? Can you just go back to 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 of 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 rate on the NCS. 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 mix effects. This quarter with the lowest oil prices that you get some credit back.
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.
Yeah, thank you, John, for asking that question. Overall, as I said, the tax was 86%, which is relatively high. The tax rate was negatively impacted by the loss in EPI and the limited tax protection we have there. If you look at the DPN, the low tax rate on the adjusted earnings is a result of 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 rates on the adjusted earnings from the MMP segment caused by earnings composition. Lower prices increases tax rates, 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 based on our payment on taxes in the first three installments paid in 2015. That's actually led to a lower installment payable in 2016. Going forward, around 72% in periods with high oil prices, and we shouldn't expect material changes to short-term assumptions if you're assuming flat prices. But if the prices go up, we should also expect a higher tax rate. But within the EPI segment, we'll be very much driven by results.
Just on the international business, you've, as I understand it, been unable to shelter losses in certain countries with profits you've made in others. It would appear that in terms of either the composition of your production or potentially the cost 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 that you're making on your EBIT. Is that a reasonable assumption? 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, Head of Accounting, would like to answer that one.
Yeah. As a starting point, it is more difficult to defend 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. As you see from the 20-F that we have published, we have unrecognized different tax assets in U.S., in part of Angola, so that is a split. And Canada and Ireland, and also part of Brazil. That, in a low price environment, is more challenging. That is an assessment that we do period to period.
Right. Okay. I heard sort of some recognition of a change of that view in the first quarter. Is that fair to say?
There is not much changes to the position by year-end.
Okay. All right, thank you.
Welcome.
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've done an impressive job in terms of cost-cutting and have significantly reduced breakevens for your project. Given your peers are not taking FIDs at the moment either, isn't it now a good time to do that? I mean to take FIDs. Given you would have better access to teams, infrastructure, et cetera. I'm trying to understand what is the holding factor here. Is it further cost efficiency that you're 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 Utgard plan head on the NCS in December, and Trestakk is expected later this year. What determines the point of FIDing 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. 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 invoiced gas price. It tended to come in much higher than hub prices in the quarter. Was there anything specific in the quarter that made that invoiced gas price be so high relative to hub, anything we have to consider? Secondly, just on the impairments and specifically the kind of reversal of impairments, which I know is something you do every quarter. 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 have $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. These are according to the IFRS standards, but it's mainly onshore assets in North America and conventional outside U.S.
Looking at the EU gas market and the inverse gas price, we hope we will give that question to Svein Skeie to start with.
Yes. As you referred to what probably the invoice price above, for example, the NBP price, where we have seen that we are selling the prices on the invoice 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-ahead prices, but we have a structured sale with partly coming from day-ahead, partly coming then from month-ahead or season-ahead. That has then given a higher price on the invoice price this quarter compared then to the NBP, which is more the spot price.
Okay. 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 noticed that the IFRS OpEx that you report over the past few quarters is substantially higher than the adjusted OpEx you have reported. I think it's $1.3 billion over the past five quarters. I just wonder what's this difference related to? Is it like only cost-cutting initiatives, which is this $1.3 billion dollars?
Yeah, thank you, Teodor . First of all, cost savings is going according to the plan. As I said, we also see some currency effect and adjusted OpEx and SG&A decreased by $590 million overall in US dollars which is 20%, as I said, and on the NCS, 25% per barrel. 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. We also see that we have some quarterly specific, like the pension cost, and we will have more maintenance going forward, as I said, in the second and third quarter.
That's the main points on the NCS OpEx.
SG &A.
My question was more referring to the difference between an 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, early on.
I do not have the exact figure that you are referring to, Teodor. In general, we have the over-under lift adjustment in the adjusted earnings that will impact that amount. Then we have in some quarters, some provisions that is clearly not part of the underlying in the quarter. That also explains part of this. I do not have the exact five quarters in front of me. That is in general.
Okay, thank you. Just one follow when it comes to OpEx over the next few years, assuming somewhat higher oil prices. Do you think the current OpEx level should represent like a proxy for what we should expect over the next few years?
As we said, this is mainly efficiency gains from currency effects, but mainly efficiency gains. We do more work ourselves. We have become more efficient. That's what we are aiming for, to actually maintain the efficiency that we have. That's our main guiding, that we are working structurally through the improvement program. We see good progress, and we are trying to stick to the new improved effort.
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 to 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. 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? Are you committed to spending $13 billion, or could there be upside to that number as in when you sanction these projects? Many thanks.
Thank you for asking that question. That was one of the main key messages from the capital markets update that we, as you said, have brought down the breakeven on our portfolio by $30. We are maturing these projects, and we have $4 billion-$6 billion in flexibility in our CapEx in 2018 and 2019. 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. It has little impact this year. Any sanctions 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 increase in capital allocation towards renewables, or this is very much within your kind of plan and guidance on spend? 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? Just secondly, just following up on the potential sale or planned sale of some non-core properties in the U.S. in your unconventional business.
Could you perhaps just give us some indication on if there's a volume impact associated with that sale, please, in terms of production loss? Thank you.
I think take the second one first, because as of the twentieth of April, we entered a confidential agreement to divest an unconventional non-core property in the U.S., and this is $400 million in cash consideration. We do not expect to realize either a gain or a loss on the transaction. It's confidential and we will have more projects and more information later related to that as a part of the agreement. Looking at the wind, if you take the large investment, it is the 50% of our wind park, Arkona Becken Südost, that we bought from E.ON as a part of the cooperation. It is 2019, which is the start-up date, supporting electricity for 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. 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 a different risk profile, and it's supplementing our core E&P business as a part overall strategy that we communicated at the CMD.
Okay, thank you.
Our next question comes from Lydia Rainforth from Barclays. Please go ahead, madam. Your line is open.
Thanks, good afternoon. A couple of questions if I could. The first one was just looking at the record quarter for efficiency. Clearly, there's been a lot of progress made there, but it does make it very difficult to understand what's happening to the underlying decline rates. I'm just wondering if you could comment on that. The second one, well, sorry to come back to the cost data, but on the per barrel numbers on the international business, it did look like it softened off, quarter-on-quarter, in terms of those 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%. The second question, if I heard you right, is about the international business and any seasonal factors.
Yes, that's right.
Well, on the gas side, we had a relatively mild winter in the U.S. That's weather. Svein, you wanna fill me in on this one?
If you look at the overall, we have down since per barrel measured in U.S. dollars approximately 14% this quarter when you compare the middle quarter last year. That is more or less in line with what we have seen, you know, over earlier quarters as well as we have reported. Especially seasonalities, we have had some lower activities on the onshore in U.S. On the total portfolio, it's no major seasonality on the overall of it.
Okay. That'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.
Oh, hi. Hi there. Thanks very much. My question is really about Oseberg. Just going through your field-by-field data, what really surprised me was just the magnitude of how much that field decreased year-over-year on the gas production. You went from 67,000 barrels a day of gas in 1Q2015 to 12,000 barrels a day of gas in 1Q2016. That decline. That's about 2.5% of all of your production. It'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. Can you talk about how much time or cost would you need to bring back that 50,000 barrels a day?
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. You know Oseberg and Troll are the fields that provide the flexibility. This is part of our Flexgas strategy. Oseberg can start up in relatively short time, Troll any minute, Oseberg a bit longer. This is something that we have done, as you correctly said. It is value over volume.
What would make you bring those volumes back? I mean, as we all look to, you know, 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. If you look at the past performance of Oseberg, you have seen higher prices and higher production from Oseberg. Increase in prices.
Okay. Thank you.
Next question comes from Tom Robinson from Deutsche Bank. Please go ahead, sir. Your line is open.
Yeah. 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? 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. We have done cancellations to rig within the existing frameworks in order to optimize this, where we come from a relatively high level of co-commitments that we have taken down, and we are fairly balanced at the moment.
Just to follow up, I mean, are these predominantly dollar denominated or NOK denominated?
Both are in dollars.
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.
Oh, hi, good afternoon. My first question might be related to a previous one on tax. 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. 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.
Okay. This is about an assessment, country by country, field by field. In some countries, we go down to field level. We're 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. If the prices are coming down in general, the uncertainty increases and we take an evaluation allowance related to that.
Then to the scrip. Overall feedback has been good, but the take-up rates remain to be seen, of course. 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 to our attention. It is in for one month from now from the company and the election in June. 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 follow-up, please. I wondered if you could talk us through a little bit about progress on the 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. Relating to it, as part of a follow-up, I wondered if you could walk us through the sort of 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 is this a level we can.
You mentioned it would go up, but what's a sensible percentage of CapEx depreciation 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 have been sharing their thoughts on this when it comes to the upside potential, and we have a close dialogue in the license, but we're working on it, so we do not have any new information according to this issue today.
Yeah.
On the DD&A in Norway, both CapEx and DD&A have flattened out in the recent years. DD&A and DPN this quarter is close to the CapEx level. If it's going forward, I think, as I said, we both have decreasing production from fields with a high DD&A rate, like the Gudrun field. 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 the Edvard Grieg and Goliat. Later in the period, you will have fields like Aasta Hansteen, and eventually also Johan Sverdrup.
Lovely. Thank you so much.
The next question comes from Halvor Strand Nygård from SEB Enskilda. Please go ahead.
Yes, hello. Your Bakken production came down some 10% sequentially in Q1. You said that you're currently running one rig crew in each area and no frac crews. Can you give 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's been one rig crew in each of the three one areas in the first quarter, and no completions in one crew 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.
Can you say something about the production level in the next two quarters?
Yeah. The quarter-on-quarter decline is consequently not representative of what to expect going forward. But you know, the beauty of the onshore business is flexibility. Still I do not think it's representative of what we have seen quarter on quarter, the decline that we actually have experienced.
Going forward.
Thank you.
With increasing prices, you should expect a higher activity level, including in the Bakken area.
Thank you.
We will now take our final question from Anish Kapadia from Tudor, Pickering, Holt & Company. Please go ahead.
Hi. Yeah. Couple of questions, please. On just going back to the tax position. So your total unrecognized deferred tax assets in the 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 gonna give an update in Q2. So, you know, you've drilled 5 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 could make substantial amount of money on when we can account on it. 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. That's sort of the boring answer to that. We follow the market closely. To exploration, it's been quite a relatively quiet quarter. We completed seven wells. We have two small discoveries on the NCS, both the Madam Felle and the B- West Anghor Thom.
Under evaluation is Power Nap in the Gulf of Mexico. We have appraisal programs for Wisting Central in Norway and Gavea I just talked about with positive results. Four wells ongoing, you mentioned Canada, Bay du Loup. An interesting one is Raya in Uruguay. Wisting Central on the Norwegian shelf. We're working on access. On the Flemish Pass, it is anticipated that Equinor 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 today we have finalized drilling of seven wells, including sidetracks. We intend to provide an update on the programs 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 host 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. I will 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.
Ladies and gentlemen, this concludes today's conference call. Thank you all for your participation. You may now disconnect.