Thank you, Peter, and, welcome to everyone, to this second quarter analyst conference. Statoil presented adjusted earnings before tax of $913 million for the second quarter of 2016. The second quarter was characterized by the following. First, the result this quarter continued to be impacted by the volatile oil prices, as well as weak NGL prices in North America, and the low European gas prices compared to a year ago. The fundamental market conditions are unchanged, but we do see signs that we may be heading towards a more balanced supply-demand picture for oil. Despite this, we must expect to see volatility for some time. In the short term, we expect continued pressure on European natural gas prices. Second, we keep on delivering strong operational performance.
Our high production regularity continues, especially from our Norwegian fields, and we are ramping up production from new fields. This contributed to a production growth of 5%. Third, we see continued gains from our improvement efforts. Adjusted OpEx and SG&A for the group were 18% lower compared to the same quarter last year. We are lowering our guidance for CapEx in 2016 from $13 billion to around $12 billion, reflecting further improvements in efficiency and prioritization. We are also lowering our guidance for the exploration spending by 10%, recognizing the differences, the efficiencies, especially in drilling and well, but at the same time capturing opportunities to increase activities in certain areas and to benefit from improved costs.
Finally, the board of directors has approved a second quarter dividend of $0.2201 per share, and there will be a scrip option with a 5% discount for the second quarter. The first scrip dividend offering yielded a 43% take-up by the shareholders, resulting in $290 million improved cash flow in the quarter. We report an IFRS net operating income in the quarter of $180 million. This is before adjustments of $733 million, mainly related to an impairment of our Gulf of Mexico asset and the mark-to-market valuation effect of derivatives in the MMP segment. Adjusted earnings before tax was $913 million compared to $2.9 billion in the second quarter of 2015.
The liquids prices that we realized was 28% lower, and natural gas prices in Europe were 32% lower compared to the same period last year. The adjusted result after tax was a loss of $28 million, reflecting a tax rate just above 100%. The high tax rate was a result of the earnings composition. I will now move from the group results to comment on the various segments. Development and Production Norway had a second quarter pre-tax result of $1.2 billion compared to $2.3 billion in the same quarter last year. The lower result was a consequence of the low liquids and gas prices in the quarter. Realized liquids prices fell 27% compared to the same quarter last year, and the gas transfer price dropped by 42%.
The gas transfer price is a function of the various price indices, and this quarter there was a sharp drop in the season ahead price compared to first quarter prices. Production grew 5% in the quarter. This together with cost reductions and further efficiency gains partly offset the effect of the low prices. Natural decline was more than offset by the ramp-up of new fields, including Valemon, Goliat, Edvard Grieg, and an increase in Statoil production from Ormen Lange after the make-up period post-redetermination. As we noted after the first quarter results, this quarter was impacted by higher costs from plant maintenance compared to first quarter of 2016 and second quarter of 2015. Nonetheless, adjusted OpEx and SG&A expenses year-on-year were reduced by 11% per barrel, and the adjusted DD&A was reduced by 10% per barrel, measured in the underlying currency NOK.
You should expect seasonal costs also in the third quarter, reflecting increased plant maintenance activity. Development and production international had an adjusted pretax loss of $506 million compared to a loss of $16 million in the same quarter last year. Realized liquid prices were 30% lower than in 2015, and this was partly offset by higher production, up 4% adjusted for divestments. We continue to see significant improvements in our cost base with OpEx SG&A costs down 23% per barrel. This was a result of effects of cost and efficiency measures, lower diluent expenses and royalties, partly offset by costs associated with new fields on stream and higher transportation costs. DD&A increased 1% per barrel due to new fields on stream and ramp ups.
The MMP adjusted result was $329 million compared with a very good result in the same quarter 2015 of $679 million. The lower result was largely due to lower refinery margins and availability due to plant maintenance at Kalundborg and Slagen. Mongstad will have a plant maintenance stop during the third quarter this year. Equity production was 1,959,000 barrels in the second quarter. This was an increase of 5% compared to same period last year. Underlying organic increase was 6%. The growth was largely a result of higher gas production from fields with associated gas, high production regularity, as well as resumption of equity volumes on Ormen Lange following the redetermination makeup period.
In addition, we see ramp up of production from new and existing fields, including Valemon and Goliat on the NCS, Corrib in Ireland, as well as Julia and Heidelberg in the Gulf of Mexico. Divestment of Shah Deniz and reduced ownership in Gudrun, as well as expected decline in mature fields offset part of the increase. Cash flow from operations pre-tax was $6.4 billion for the first six months of this year, compared to $11.2 billion in the same period last year. We paid two tax installments of NOK 6 billion each on the Norwegian Continental Shelf in the second quarter. From the second half, we will pay taxes based on 2016 results. The installments for the next three payments will each be NOK 5 billion based on expected lower prices for 2016.
Dividend paid reflects the dividend for third quarter 2015, which was paid fully in cash and the cash part of the fourth quarter dividend. With cash investments of $6.1 billion for the first six months, this results in a negative cash flow of $3.2 billion. Net debt to capital employed ended at 31.2%, impacted by negative cash flow offsetting for dividend and currency. A few comments on guiding before I leave the word to Peter to lead us through the Q&A session. We maintain the production guiding and we expect an organic production growth of 1% from 2014 to 2017. We reduced organic CapEx guiding for 2016 from $13 billion to around $12 billion , mainly due to the impact of the efficiency efforts and our continued strict prioritization.
We estimate the exploration spend to be around $1.8 billion, down from $2 billion previously guided. The reduction is a result of efficiency as we plan to drill the same amount of wells as originally planned. Thank you, and over to you, Peter.
Thanks, Hans Jakob. With that, we'll open for Q&A. I have some questions on the line already, and I pass it over to the operator to run you through those procedures again. Thank you.
Thank you, sir. If you would like to ask a question at this time, please press star one on your telephone keypad. Please ensure that the mute function on your phone is switched off to allow your signal to reach our equipment. If you find that your question has already been answered, you may remove yourself from the queue by pressing star two. Again, please press star one to ask a question. We will now take our first question from Haythem Rashed from Morgan Stanley. Please go ahead. Your line is open.
Thank you. Good afternoon, gentlemen. Thanks for the presentation. Hans Jakob Hegge, if I could just briefly cover two topics. Firstly, it seems for the quarter, price realizations were somewhat of an issue, particularly when you look at the gas side in Europe and then in the international business and the liquids side. I just wonder if you could just talk a little bit about how transitory you felt that was, or whether there is some a change in sort of the Equinor business that means that some of this might linger for a period of time going forward.
The second question is really regarding your CapEx and the $ 13 billion-$ 12 billion, you know, clearly demonstrating the flexibility you have in moving CapEx lower with the efforts you're putting in. I just wanted to get a sense of, you know, firstly, scope of that coming down further this year because we obviously had last year where you brought it down on more than one occasion, and whether you felt that was possible from what you are seeing at the moment in terms of the operations and the efforts that are going on to increase efficiency.
Just from a longer-term perspective, you highlight today that the CapEx is lower, but production guidance is unchanged. Is there anything you can say about what you think medium-term for Statoil, the right level of CapEx is? Do you think $12 billion is a number that you can continue to spend, continues to allow you to grow at a reasonable rate and deliver on, you know, sort of future projects? Or at some point, does that number need to go back up again to a more sustainable level? Thank you.
Okay. Thank you, Haythem. First on the gas price and realized prices. As you know, this is the way we sell our gas. If you look at the gas, the price markers used in internal price is reflecting Statoil's average sales structure over a period of time. That includes a mix of short and longer-term indices. The main reason for the internal price decline was a sharp drop of the season ahead compared to the day ahead. Still, the realized price in the second quarter was 10% higher than NBP. In the first quarter, we benefited even more of this. Then to CapEx. The CapEx rate and the guiding has been taken down to $12 billion.
We maintain the strong capital discipline with strict prioritization. We see efficiencies across all the portfolio. We see it in exploration, we see it in the projects, on the U.S. onshore, seeing a downward trend across the portfolio. We have slightly less capitalized exploration, with a year-to-date CapEx capitalization rate of 31%, lowering the total spend, and the project portfolio is continuously being evaluated, in this respect. When it comes to medium-term CapEx level, I think we highlight the fact that we will have capital discipline. We will invest when the projects are clear. We have the $4 billion-$6 billion in flexibility in 2018 and 2019, and that is of high value to us. Maintaining the flexibility going forward will be important.
Okay. Thank you.
Thank you. We'll now take our next question from Mehdi Ennebati from Société Générale. Please go ahead. Your line is open.
Good afternoon, all, and thanks for taking my question. Two questions, please, very quickly. First, I would like to come back, Hans, on what you said regarding the tax payments. You've paid roughly $2.3 billion in tax in H1 2016, mainly related to 2015. I wanted to know, or can you please confirm that we should consider a material decrease in H2 2016 tax payments, given it will be related to full year 2016 earnings, which are much lower than last year. If I understood well, you said that the payment should be around NOK 5 billion in Q3. Just wanted to know if you can confirm this. Maybe you know, the line was not that good.
Second question regarding the working capital. Your working capital increased materially in H1 2016, roughly $700 million. I wanted to know what should we expect in H2 2016, some reversal or let's say at least you know a kind of stabilized working capital which will not negatively impact your free cash flow. Thank you.
Okay. Thank you, Mehdi. On the tax payment, it is a high tax rate, actually the first time above 100%. We say that the tax rate is negatively impacted by the loss in the international business, in areas with limited tax protection. Going forward, we will benefit from this when we start earning money, for instance, in the U.S. where we do not pay taxes. We have a low tax rate on the adjusted earnings from DPN. That is mainly due to the higher effect of the uplift deduction due to the low adjusted earnings. We see a high tax rate on the adjusted earnings in the MMP segment, that is caused by earnings composition. In terms of guiding going forward, in general, lower prices increase the tax rate, over time.
A falling tax rate should be expected when prices recover. NOK 700 million lower than paid in the first half if we take the actual average. That was on tax. When it comes to working capital, I leave the question to Ørjan Kvelvane.
Yes. Okay, thank you. I'm not sure if I followed your numbers, but from a working capital perspective, we have kind of a significant reduction compared to kind of the same end of same period last year. That is of course due to prices. When it comes to the working capital compared to first quarter, we see that it's the inventory that increases and that is due to kind of higher volumes in transit, which increases that part of the working capital. It's over the past four quarters, we have a pretty stable working capital.
In terms of working capital variation impacting the cash from operation, what would we expect for H2?
Svein Skeie, I will.
Of course, it's very much depending on where the market is going. As also Ørjan Kvelvane is saying, we have seen that there are benefits for them doing transportation of the crudes longer. We have then sent, for example, some cargos then towards Asia, meaning that they are longer on ship. If those kind of market continues, then we will have more working capital. If those market changes and shorter distances, that could mean that we could go down. It would depend very much on the pricing structure as we are moving month by month going forward.
Yeah. You should expect also correlation to prices going forward.
Thank you.
Thank you. Our next question comes from Michael Alsford from Citi. Please go ahead. The line is open.
Thanks for taking my questions. I've just got a couple if I could. Hopefully, you could update us a little bit more on the guidance you provided at Capital Markets Day regarding cash flow breakeven. You've clearly reduced your CapEx for 2016, and I was just wondering whether we should still think about you breaking even in 2017 at $60 per barrel, or do you think that actually is now much lower given the cost trends and CapEx trends that you're seeing? More specifically on the international business, clearly loss-making and a drag on profitability still.
I was just wondering if you could provide an update as to where you're getting to in terms of your key objectives around, you know, onshore CapEx costs, OpEx costs to bring the breakeven of that business down more substantially and make that profitable at lower prices. Thank you.
Thank you, Michael. First on the guidance of cash flow and the break even. What we said on the capital market, we have no changes to the guidance. We are on track. What we talked about at the capital markets is that we could be neutral at $60 in 2017 and 2018, and that still is valid. No changes. When it comes to the international business, we are profitable in many of the key areas. It is obviously challenging on the current prices and prices realized in the second quarter. As you know this, we are structurally more exposed to the oil price than the Norwegian business due to the historic cost and the lower margin.
The adjusted earnings of -$506 million is mainly due to lower realized prices. At the same time, I think it's fair to say that 23% reduction in OpEx & SG&A is a good response to attacking the costs on the workable elements. We have a cash flow from the international operations of $12.4 per barrel, and that is also indicating that this is a cash-generating business. The total cash flow from the operations of the international business is $683 million, but still loss-making at current prices.
Okay. Thank you for the update.
Thank you. Our next question comes from Mr. Halvor Nygård from SEB. Please go ahead. Your line is open.
Yes, hello. So on CapEx, you cut your CapEx guidance by $1 billion from $13 billion to $12 billion this year. If we look at year-to-date CapEx, it is at $5.3 billion, which implies a run rate of $10.6 billion. Would you say that you still have headroom for further CapEx reductions, or will CapEx in second half of this year increase by more than 20% as you see it now?
Okay, thank you, Halvor. Year-to-date, we just spent, I think it's $5.4 billion. You should expect higher activity during the year with the Sverdrup execution, starting the execution of Peregrino phase II and a potential activity with fracking in Bakken and Eagle Ford, so the U.S. onshore operation.
As we've said today, we reduce our guidance on the CapEx to around $12 billion, and that's our best estimate for 2016.
All right. Thank you. Another question on production. Your Bakken production fell 11% sequentially in Q1 and then another 14% sequentially in Q2. While, if I remember correctly, you stated at Q1 that the drop in Q1 was not representative going forward. What are your plans for activity and production U.S. onshore going forward?
We still have one operated rig in each of the places, and in the second quarter, a frack crew in Bakken and Eagle Ford. Bakken production was reduced compared to the first quarter with no wells completed in the quarter. Since the first quarter, prices have improved. We are considering picking up some activity in the second half, but cost focus remains critical.
Okay. Thank you.
Thank you. We'll now take our next question from Tom Robinson from Deutsche Bank. Please go ahead.
Afternoon, everybody. Thanks for taking my questions. I've got two, if I may. The first one's on cash flow. Could you just help bridge the operating cash flow before tax and working capital from the first quarter of this year to the second quarter? I'm coming at this from the angle of, if I look at the face of the cash flow statement, we've moved from roughly $3.4 billion to $3 billion in a quarter where pricing's a bit better, volumes are down marginally, and the cost base is up slightly. So is there another factor I'm missing to explain the downward direction of cash flow quarter on quarter? That's the first one. Second one, just briefly, is on CapEx.
Would you be able to break out the $1 billion of savings in more detail? I appreciate $200 million or so is exploration, but how does the remaining $800 million split between the regions and the divisions? Thank you.
Let me start off on first of all, Tom, thank you for those questions. Let me start over on the cash flow and then Ørjan Kvelvane will fill in with more detail. In general, the cash flow will vary over time with the level of volatility that we see. The basis for looking at the cash flow, I think is a robust cash generation, given the realized prices in the second quarter, with the strong operating momentum and the high regularity that we see. A cash flow from operations of $6.4 billion year to date, given the significant reduction in the average liquids prices is sort of the basis. Then, into more detail, Ørjan.
The way I understood your question was the second quarter towards the first quarter. You are right that the adjusted earnings are up, and the cash flow quarterly is down pre-tax and working capital. As you know, this is about kind of non-cash elements. It will also be impacted by kind of accruals and provisions that is both cash and non-cash. This is a kind of a mixed bag of elements. One example is over underlift, where we in the adjusted earnings have a negative effect in first quarter, a positive effect in second quarter.
That will not impact kind of any of the adjustments in the cash flow that is based on the IFRS numbers. These are kind of the adjusted numbers. In addition, we have some financial elements that also is part of the cash flow from operation that is not part of the adjusted earnings. It's not easy to compare one to one, but this was some comments to enlighten you.
To the second question about CapEx and the $1 billion reduction. It is across the portfolio, and a material part of it is from producing fields, both operated and partner operated. It's difficult to say one or two specific reasons. If you're highlighting one, it probably should be the continuous improvement in the drilling and well. With example from the Norwegian shelf that exploration wells in 2013 was drilling 46 days on an average, now down to 22 days. Overall, I think it's fair to say strict prioritization, capital discipline across the group.
Thank you. Thanks for the detail.
We will now take our next question from Ann Gjøen from Handelsbanken. Please go ahead. Your line is open.
Thank you. When it comes to the second quarter, you have commented on higher gas volumes despite lower gas flexibility. When it comes to gas flexibility, the way the market is developing, do you consider the gas flexibility as less than before going forward? Is it possible that you also could give, a nyway, you see the development in the EU gas market into 2012, 2017. Thank you.
Thank you, Ann. As you know, most of the increase is from associated gas production in the quarter. The flex gas come from Oseberg, which was a bit lower than last year. Year-over-year, the flex gas is lower. Going into your second question about the EU gas markets, obviously a very interesting one and the way we look at it is that the market is fairly well supplied in Europe at the moment. We see potential upside linked to the capping of the Groningen field. We see a political willingness in relation to the climate agenda to be more in favor of gas as opposed to coal. Also be aware of the indigenous decline that we have seen.
There are many factors, but at the moment it's well supplied. As I said, we probably expect to see some continued pressure on the prices, short-term. Longer-term, we have a optimistic view on the European gas market.
Thank you.
Thank you. Our next question comes from Brendan Warn from BMO Capital Markets. Please go ahead. Your line is open.
Yeah. Thank you. Thank you for taking my question. It's Brendan Warn from BMO Capital Markets. Just first question of three, I guess first one relates to the international business. You talked about impairments. Can you just talk through your future impairments and what we expect in the current forward curve or your current sort of impairment tests? Notice that your DD&A has increased and the international business is still loss-making. Second question, just in terms of the MMP business, any guidance update you can give us just in regards to the change of conditions for the back end of this year, particularly with refining margins off and gas and oil pricing?
Last question, just in terms of your debt maturity profile, can you give us a, c an you just talk about what you're looking at in terms of refinancing or payment down of your maturities certainly in the next couple of years, please?
Okay. Thank you for those questions, Brendan Warn. When it comes to the impairment, we only had one impairment in the quarter. That was a Gulf of Mexico asset not operated by ourselves. That was linked to a revision of the reserves. We use the forward prices, as you say, but after some quarters where we have done quite a few of these impairments, we are only down to one this quarter. Last quarter, you probably remember we had a reversal as well. Going forward, this will be based on not only the forward prices and price assumptions, but also reserves revisions and the updating of business plans. To the second question, about the MMP business. On the guidance, there are no changes.
We expect to see volatility, and we are in this quarter within the range of $250 million-$500 million, and you should expect us to be within that range going forward. When it comes to the debt profile and we have an average of nine years and no current plans for refinancing for 2016. We have $16 billion in cash, and the profile is so that we have $1 billion for this year, increasing to $2.5 billion next year and just about $3.5 billion in 2018. The maturity of the profile is something we are comfortable with.
Okay. Appreciate it. Thank you.
Thank you. Our next question comes from Anish Kapadia from TPH. Please go ahead.
Good afternoon. A couple of questions. Firstly, want to get an update on some of your projects and timing on potential FIDs on the Canadian offshore, given your recent update, the BMC 33 project in Brazil, key takeover operatorship, and also Johan Castberg and Bressay. Secondly, on your U.S. assets, you've made a few disposals in terms of your Northeast gas position, and it's now largely non-operated. I was wondering if it's right to see this as a non-core position that could continue to be monetized. Finally on the midstream assets you've got in the U.S., I think you revealed about $1.5 billion of book value associated with those assets.
What's the EBITDA that those assets generate and also the potential to monetize these? Thank you.
Okay, thank you, Anish. On the projects first overall, we are on track both on cost and schedule. Let me just mention Sverdrup phase one, which is into the execution phase. Gina Krog topside just has sailed from Korea. We have Mariner and we had a heavy lift today on Aasta. Mariner and Aasta has a planned sail away scheduled for 2017. You mentioned the Canadian offshore still being evaluated. We have done exploration campaign. We just finished a 19-month exploration campaign, and we had two discoveries, confirming the value range of volume range of 300 million-600 million barrels. BMC-33, we hope to get the consent on being the operator of BMC, so that's the next milestone.
We have agreed on cost bank with the partners on an FPSO concept. That's the most efficient one as we see it. We discussed the FPSO involving shuttle tankers and the concept selection. The DG2 is planned for autumn this year and a potential FID in 2017. When it comes to Bressay, it's been postponed, so we'll have to revert to that on a later stage. On the U.S. assets, talking about, I think we have a strong position when it comes to the U.S. We are placed in the good basins. It's a good acreage. We see costs coming down, and the main focus is on efficiencies. When it comes to an M&A activity, we comment more specifically on that when the deals actually have taken place.
On the midstream, the EBITDA from the midstream in the U.S.?
We do not go very specifically into that part. It's seen as a part of the MMP business and the guiding that I just commented on, the 250 million-500 million, it is a part of that, and we do not go into further detail at this point.
Just before we go into the next question, in the interest of time, can I ask all questions to keep it to a maximum of two questions each, and I'll impose my normal rigorous discipline. Thank you. If we move over to the next question, please.
Thank you. Our next question comes from Oswald Clint from Bernstein. Please go ahead. The line is open.
Yes, thank you. Maybe a question on Johan Sverdrup. I don't think I've heard you comment on the volume increase that there was talked about from Lundin. Maybe you could just talk about that 100,000 barrel a day increase that they're talking about. Is that something you will confirm or agree? Is that a press release type thing, or is there still work being done on that initial plateau production level, please? Maybe secondly, on the drilling efficiency comments today, is that just drilling faster. Can you talk about the days, you know, how many days to drill a well you've brought that down to or is that actually the rate that's being paid per day? Maybe a little bit more color around that, please, would be quite interesting. Thank you.
Thank you, Oswald. When it comes to Johan Sverdrup, as I said, we are well into the execution phase. The study is done on the processing equipment. Can confirm there is upside, but this is one of several factors impacting the production. When it comes to where we are with the milestones, the construction start of the living quarter platform at Ågotstøl was end March. Steel cut on the riser platform topside at Samsung in Korea in June, and three production wells drilled to target depth finalized by end June. We are working closely with the partners on the phase II . There is a concept select plans around year-end, potentially early 2017.
When it comes to adding volumes, we have nothing more to add today. To the drilling efficiencies, more color to that. We have a more standardized approach. Some of you might have heard about the perfect well concept that actually was developed on the U.S. onshore business, where we went through the best performance of the various parts of not only planning, but execution of various wells. We combined it into a quite rigorous assessment of the well. It's an upfront loading of the operations before it takes place. You have to go through a practical checklist of at least 12 points that you have to check out that you are according to the best practice. By doing that in a rigorous way, the execution runs not only faster but cheaper.
On the exploration wells on the Norwegian shelf, we have been able to reduce the number of days on average from 46 to 22. It's rigorous planning and discipline when it comes to the execution.
Great. Thank you.
Thank you.
Thank you. We'll now take our next question from Teodor Nilsen from Swedbank. Please go ahead.
Good afternoon, and thanks for taking my question. First question is on dividend. Hans Jakob, you mentioned that 43% elected shares for the first quarter dividend. Assuming that oil prices stays below $50 per barrel, will you then consider to increase the discount on the shares to encourage a higher portion taking shares as dividend? My second question is on CapEx. Assuming that in 2017 you invest in all your sanctioned projects and also that prices stay flat from current level, should we expect 2017 CapEx to be below or above your updated 2016 guiding? Thank you.
Thank you, Teodor. When it comes to dividend, we had a 43% take-up on the fourth quarter 2015. We think that's. We are happy with that. We continue with 5% discount for the first quarter this year. If the take-up continues at this level, it will contribute with a 3%-4% on the gearing as program end. That's where we are at the moment. No change to the discount. We keep the discount for the first quarter this year. On the CapEx, I leave the word to Svein Skeie.
Thank you, Hans Jakob. When we look at where we are now, it's the $12 billion I said. As we also say is that, for the second half of this year, we expect then to have some more CapEx compared with the first half due to the fact that we are then into more execution phase on the Peregrino phase II as well as the Johan Sverdrup. Also we see that some projects are then put into production. To us, as we said, we have the flexibility and we try then to on the CMU then we gave a guidance and then how or where we expect then to spend the CapEx then going forward.
Flexibility of $2 billion-$3 billion in 2016 and 2017 and increasing further. For next year, we are continuously evaluating where we are and the projects. For new projects, if you then talk about that for next year, the main part of those will then come into the late part of 2017, not impacting 2017 CapEx that much. Only this year we have the Trestakk and the Utgard, which are the new developments that we expect coming into place.
Teodor, we will have to come back and be more specific on CapEx for 2016 at a later stage.
Just a follow-up on the CapEx. Assuming that oil price stays at the current level, is it fair to assume that a higher portion of overall CapEx will be invested in Norway compared to internationally than we will see this year?
Too early to say. One of the dilemmas is, for instance, U.S. onshore, where we have a frack crew in Bakken and Eagle Ford. We don't run CapEx by the spot. We take a long term and this is some of the things that we discuss on a more continuous basis based on the market assessment in the various segments.
Okay, understand. Thank you.
Thank you. We'll take our next question from Rob West from Redburn. Please go ahead.
Hi there. Thanks for taking my questions. I've got two, please. The first one is on the recent wage agreement that I think was announced with Norwegian workers over the course of the quarter. Maybe they're still even ongoing in some places. The way that's been agreed, can you talk about do you still have the scope to improve the productivity of the way you use workers and labor and drive down costs on the Norwegian continental shelf from that? Then secondly, this is a bit of a niche question about the cash flow. I was wondering, could you comment about some of the specific one-offs that we can't see impacting the numbers in the quarter, and particularly around derivatives.
Were there any payments against derivatives in the quarter? Just from trying to back out of the cash flow statement you reported, there might have been a bit of a payment into that category. Thank you.
Thank you, Rob. First on the wage agreement, first of all, we think it's good that we reach an agreement. We work closely with the workers and the unions on improving our business. This is one of the explanations why we have succeeded reducing the costs 11% down on DPN, on per barrel on the OpEx SG&A. It's been a very positive trend over several quarters when it comes to reducing the costs. We engage in a close dialogue with the workers on not only reducing the external services, doing more of the work ourselves, but also reducing the overtime spent.
One of the reasons we have succeeded is because we have seen that we could plan better, do more of the work ourselves, and be aligned on the practical execution of the work. It's good also that we have a wage agreement. On the cash flow area, a bit more color-
Yeah.
Specifically on the derivatives
Yeah.
MMP.
There are derivatives effects both from commodity derivatives and also financial derivatives. It's kind of negative on the commodity side and positive on the financial side. I would say that on the cash flow, on the specific elements, I would highlight maybe the collateral inflow. Close to $1 billion in cash inflow. Then, of course, hitting the financing activities. I think that is the main part that I would highlight.
Operator?
Are we able to call for the next?
Oh, pardon. Yes. We'll now take our next question from Biraj Borkhataria from RBC. Please go ahead. Your line is open.
Hi, thanks for taking my questions. I had a couple. Firstly, on exploration, you're 10% down on the budget. I was wondering if you'd talk about the level of activity there. What is the number of wells you're gonna drill now versus the number you plan to drill at the start of this year? That'll be my first question. Then the second question is on the U.S. onshore. Could you just remind us what the CapEx that was spent in this business in the second quarter, and what the full year budget is for CapEx there? Thanks.
Thank you, Biraj. First on the exploration and the number of wells. Let me just take you through a quick update. We drilled eight wells in the second quarter. We have 15 year to date. I mentioned the 19-month drilling program, East Coast Canada, that confirmed the volume of 300 million-600 million barrel range. We are maturing further prospects there. Two discoveries. We also had success. We were awarded five licenses in the 23rd round. Four as operator on the first well will be drilled in 2017. In terms of spending guidance, as you said, we reduce it by 10%, see continued efficiencies. We also see that there will be a bit more activity going forward, more seismic in the second half, around 20 wells, for the full year.
That's the main point on exploration. CapEx U.S. onshore was very low in the first quarter due to hardly any fracking. One rig in each play. Expect to see a bit higher spend in the second quarter. Still at an activity level reflecting the current prices, which we cautiously call value over volume. Strict prioritization, main focus on costs.
Could you just remind us what the full year CapEx budget is for the U.S. onshore business?
We do not go into that level of detail, unfortunately.
Okay. Thank you.
Thank you. We'll now take our next question from Jon Rigby from UBS. Please go ahead.
Yeah. Hi, thanks for taking the question. Just a quick one, clarification on Canada. I think when you originally announced the Bay du Nord discovery, you said 300 million-600 million barrels, and then that was after Mizzen and Harpoon. I think you've made two further discoveries. I'm just trying to square that with what you're saying about the 300 million-600 million barrels that you have confirmed. Well, anyway, can you sort of explain how that arithmetic works, please?
Yeah. The discoveries, Jon, is Bay de Verde and Baccalieu.
Yeah.
They overall, we could say that, I'm a bit disappointed that we didn't prove even more volumes. Having said that, from the campaign. But due to the new discoveries, we are still at the 300 million-600 million barrels. It's more confirming the range that we said prior to these discoveries. We are working on further exploration potential in the area and maturing further prospects. We are also looking at the lean development solution on the Bay du Nord. The timeline and the concept solutions are being reworked.
Right. That range is enough critical mass to support the development, is it?
We will.
That's your current thinking.
In terms of our potential FID decision, that will be based on not only the volumes and the confirmation of those, but also the lean development solutions and the cost attractiveness of that. It's a bit early to conclude.
Okay. Thank you.
Thank you. We will now take our next question from Anders Holte from Danske Bank. Please go ahead. Your line is open.
Good afternoon, gentlemen, and thank you for taking my quick questions. The first one relates to the cash flow from for the quarter before taxes and working capital, as earlier mentioned. I mean, I think we're all pleasantly surprised of the Q1 results at $3.4 billion, and now we're down to $3 billion despite the higher prices that have been throughout the quarter. Question then, is this the level that we should expect if prices remain unchanged for the remainder of the year? Second question is related to your spoken positive view on gas prices in mainland Europe, and how much of that is tied to and expecting higher pricing of carbon, which I guess is a prerequisite for starting to retire the brown coal power plants in Europe. Thank you.
Okay. Let me do the first question, and then Svein takes the second one. The results reflect the current commodity prices no doubt, but cash is very much in line with what we said at the CMU. We have the maintenance seasons and the cost associated with that. That will be higher in the third quarter. Remember, we have the underlying production growth, and we see the costs coming down. We are all making our portfolio even more robust with lower break-even levels. Also going forward, the market effect will increase when as we reduce the service costs in 2017 and 2018. At the CMU, we showed the graph indicating around $10 billion in annual average cash flow at $40 for 2016-2017.
The cash flow from operations in the first half of 2016 has been $4.1 billion at slightly below $40, which is lower than the run rate suggests. Keep in mind that the cash tax payments in the first half is based on the results from 2015 and does not reflect the $40 per barrel we saw in the first half. Cash tax was almost $700 million higher in first half than on adjusted earnings. Also at flat prices, the cash flow from operations should be higher in 2017 than 2016, as we will have higher production next year. Svein, the second question goes to you.
Yes. Thank you. Regarding the gas outlook as we do, as Jakob explained a bit earlier on the outlook going forward. In the shorter term, there are gas coming into Europe. But still, if you look at the indigenous production, the Groningen field is going down. Going forward also based on the Paris discussions that we had, there are expectations for Europe to do something with the carbon emissions. In such a context, pricing on carbon in one way or another will probably be an efficient measure to do it.
What we expect is that, going also forward based on the agreement that we had in Paris, we should expect that there will be more pressure to take out coal with high CO2 emissions. Gas is very well-placed to replace it. Since we have the pipeline in place, we have the field in place, we have very competitive gas that could supply Europe with new gas also going forward.
Thank you. That does it for me.
Thank you. Our next question comes from Joshua Stone from Barclays. Please go ahead.
Hi. Good afternoon. I've got two quick questions, please. Firstly, on efficiency, are you able to say what's been achieved already versus the $2.5 billion efficiency target from February? Secondly on gas deferrals, are you able to say what the production impact was during the second quarter? Thanks.
Thank you, Josh. On the efficiencies, it's very encouraging to not only state that we started early prior to the drop in the oil price, but also that we've been able to increase and double the efficiency gains over time. We're not changing the guiding on the $2.5 billion. It's still valid, and we are running according to plan. Several encouraging areas to pick on the specifics. I have mentioned already the drilling on well. We see that on the U.S. onshore operations. Even if the activity has been taken down, the efficiency is increasing. The service costs has also been partly covered in this call, but relatively limited effects are still valid, the $300 million-$400 million in 2016.
Going forward, I think it's definitely a higher potential when it comes to the service costs and the effect of that as new projects are being sanctioned. Last but not least, on the OpEx side, we see the MMO contracts on the modifications and maintenance on the Norwegian shelf that was implemented in April. The implementation period will go on to the end of October this year. In the transition period, you could also actually see a bit higher costs short-term when you change from one company to the other. My experience from the operations is that when the wheels start turning with the new players in there you would definitely see more efficiency.
The $2.5 billion is still valid. Remember that when we reduce the activity, the basis for doing the improvements is also decreasing. It's not purely about the activity level. It's also about the basis you are improving from. On gas deferrals, Svein.
Yes. In this quarter compared with the last year there was a slight reduction that we did then on Oseberg field. But not a major, I think. We are following the market very closely how it develops and looking at the structure in the market. Since we have the flexibility, we also have the flexibility if the market opportunity is there to defer gas if that makes value. Because we are focusing on the value side of it, not the volume side of it.
Great. Thanks very much.
Thank you. We'll now take our next question from Hamish Clegg from Bank of America. Please go ahead.
Hi, good afternoon. Thanks, guys. Just first of all, revisiting the cash flow comments you made earlier, on that capital markets day slide that very usefully kind of outlines CFO versus CapEx at the different oil prices. As you said, the sort of cash tax element was slightly, let's call it back-end loaded. Could you maybe tell us if you feel entirely comfortable with that sort of approximate $10 billion of CFO for the full year? With that in mind, what's the impact of the swap out of Edvard Grieg in the second half? How will that impact that number, or will it not? My second question, very simply, U.S. gas prices obviously made a bit of a recovery towards the end of the quarter.
Although sort of I know they were down slightly in the quarter, can you tell us if you think you'll be capturing these higher gas prices going forwards? Because my sort of back-calculated gas realization suggested that you were probably making a slightly lower U.S. gas realization than I'd expected. Is there some hedging involved in that?
Okay. Thank you, Hamish. First, on the cash flow and CMU. Yes, we are comfortable with the $ 10 billion in cash flow from operations at $40 per barrel. This is for 2016 and 2017, not only 2016. We'll be higher next year due to taxes and production growth. On the impact from Edvard Grieg, yes, this will have an impact along with other portfolio adjustments we have done. That's the short answer to your second question. As you know, we don't generally update the guidance after individual transactions.
Okay. We'll wait for next year's capital markets day for a change on that. Or will you be giving us some guidance on Edvard Grieg's, how we should account for that in our modeling?
Well, you know the direction.
Yeah, we do. Thanks.
Thank you. We'll now take our final question from Nitin Sharma from JPMorgan. Please go ahead.
Thanks. Afternoon, everyone. Just a quick one. Hans Jakob Hegge, when you think of the three key objectives, organically covering your dividend, investing for future growth, improving reserve life, and finally gearing, how do you think about balancing those three objectives in terms of the decisions that you take this year and next, please?
Thank you for that question. I think it's fair to say that we take a long-term perspective on our business and balancing this on the dividend. We've said it's important, we confirm that today by maintaining at the same level, continuing to pay dividend, continuing with the scrip, offering the 5% discount. We focus on the fundamental improvements. We think it's very important to address the cost and efficiency issue that has been a theme not only this year, but over a period of several years. We continue to invest in high-quality projects, ensuring that these are as good as they can at the point of the FID. Mainly two elements in the decision. Can we improve further on the concept, on the economics?
If not, we should sanction it if it's a robust project going forward. Also, what do we think about the timing in the market with the capacity in the supplier industry and the rates offered? We do this within a strong financial framework. We have a stable outlook on the credit rating. We have, we are comfortable with the current gearing level, and we have $16 billion in cash.
At what level of gearing, if I may ask as a follow-up, what level of gearing does that strong credit rating come into question? Or is there a gearing level at all?
The ambition level on gearing is to stay over time between 15% and 30%. When we cross the line, as we did in this quarter, it is in line with the guidance we did at the CMU. We said this is expected at the current prices. We have a more optimistic view on the market long term, so we think we will have a recovery of the prices. We see some signs that we are moving towards a more balanced market, maybe 2017, and then we will eat out of the high storages, and we'll probably see a more normalized situation where geopolitics and things like that would affect the prices and have a positive response on that.
The long-term perspective with value over volume and quite stable outlook is important to us when we make these decisions.
Thank you.
Okay.
Thanks, everybody. That's the end of the questions and of the presentation. Thanks for joining us today. As ever, if there's any follow-up questions, please don't hesitate to call the Investor Relations team. With that, I'll wish you the best, and we'll be calling again in the future. Thank you. Bye-bye.