Good morning, ladies and gentlemen, and welcome to the Statoil analyst conference call for the Q3 2017. With me this morning, I'm pleased to welcome Hans Jakob Hegge, Chief Financial Officer, Svein Skeie, Head of Performance, and Ørjan Kvelvane, Head of Accounting. Hans Jakob Hegge will present the results in around 15-20 minutes, then we will reinvite polling for questions and take Q&A for around 45 minutes, expecting to close the call around 12:30 P.M. CET. With that, I hand over to Hans Jakob Hegge to start the call.
Thank you, Peter, and good morning, everybody. Thank you for calling in. This morning, we presented Equinor's Q3 results. Let me share some of the highlights from another strong quarter. Adjusted earnings before tax was $2.3 billion. The quarter is characterized by solid earnings and underlying cash flow, good operating performance and high production sold at higher prices, continued progress on our cost reduction and efficiency improvements. The IFRS result before tax was $1.1 billion impacted by $0.8 billion in net impairments. Reported net income was -$5 billion. We are cash flow neutral at $50, including the scrip.
Note that reported cash flow from operations in Q3 was impacted by NOK 0.5 billion of cash outflow related to FX movements on derivatives, which is mainly offset at group level and does not impact the gearing. We will cover this in more detail on a later slide. Before we go into the results in detail, have a look at this picture. It shows the Aasta Hansteen topside, the world's largest small platform, on its way to Norway from South Korea. The field will start producing in 2018. We have increased reserves, and when Snøhvit Nord is tied to Aasta as a satellite in 2019, this will result in further value creation. We have good progress on Johan Sverdrup, and this quarter we reduced the CapEx by another NOK 5 billion– NOK 92 billion for phase one.
We have also started electricity production from the Dudgeon and Hywind projects offshore U.K., and we took a first step into solar energy in Brazil. To the macro. There has been a strengthening of oil and gas markets, and we are heading towards a rebalancing in the oil markets, and we see firmer gas prices compared to last year. However, oil and gas prices continue to be volatile, with uncertainty linked to the prolonging of production curtailment among the OPEC members, the production level realized from unconventional U.S., and geopolitical uncertainties. We adjust our medium-term price expectations somewhat this quarter. We previously assumed an oil price of $75 per barrel in 2020. We now assume $75 in 2022. Our fundamental oil price review remains the same. We see increasing demand taking inventories closer to balance.
We have seen underinvestment in new oil supply for 3 years, and we believe in an uptick in the prices going forward. Equinor has been an active explorer in 2017. During the first 3 quarters, we completed 22 exploration wells and made 11 discoveries. Some of these discoveries can be tied into producing fields rather quickly. In the Barents Sea, we completed a very efficient 5-well campaign and made the Kayak discovery, adding volumes to Johan Castberg. The value of the Kayak discovery alone pays for the entire campaign in the Barents Sea. We also collected valuable information for next year's campaign, and we continued to replenish our exploration prospect inventories. The 3 main takeaways this quarter are solid earnings and underlying cash flow, good operational performance and high production sold at higher prices.
Expected production growth in 2017 is increased from 5% to around 6%. Due to good progress in our field development project portfolio, continued capital discipline, as well as the further improved efficiencies, we are reducing our CapEx guidance for this year from $11 billion to around $10 billion. In sum, Statoil is doing a lot more for less. We cover our investment and dividend at $50 as communicated at the Capital Markets Update. We have made the company more resilient and better positioned for further recovery in the oil price. As noted earlier, our IFRS result before tax is reduced by net impairment. We have made impairments and reversals. Based on asset market reviews, operational asset reviews, and the effect of price changes, the net sum of impairment and reversals is $0.8 billion negative.
The largest impairment of $0.85 billion is specifically on Eagle Ford. This was triggered by lower than expected production volumes, but the impairment in itself is calculated based on a market valuation. As you would know, there is volatility and uncertainty in valuation, and we have therefore used an independent third party in this case. Remember, we have made impairments and reversals. In fact, since Q4 2015 on Eagle Ford, we have made reversals of $0.6 billion. We are working hard on an improvement plan for the asset. Our other U.S. onshore assets are not affected. To the dividend. The Equinor board of directors has decided to maintain the dividend also for this quarter at $0.221 per share with a 5% discount and scrip dividend option. We have run the scrip program in a predictable way.
Q3 2017 is the last quarter of the program, and we have no plans for any extension or new program. From Q4 2017 onwards, you should have the expectations that we will return to full cash dividend with no scrip option. To safety. Equinor's serious incident frequency the last 12 months was 0.7 per million hours worked. This is down from 0.8 in the last quarter. Safety is, and will always be Equinor's top priority. We continue executing our safety improvement agenda to further improve Equinor's safety record. Let's now have a look at the Q3 and year-to-date financial results. We deliver a solid $2.3 billion in adjusted earnings before tax this quarter. This is up from $0.6 billion for the same period last year.
The key levers behind our Q3 earnings are good operations with high production and regularity, capturing higher realized prices. Adjusted earnings after tax was $0.8 billion compared to a loss of $0.3 billion in the Q3 last year. The tax rate in the quarter was 65%. We realized an average liquids price of $47 a barrel, an increase of 18% compared to Q3 last year. Realized European and North American natural gas prices were also higher in the Q3 by 8% and 11% respectively. Equinor's OpEx and SG&A costs measured in underlying currency have been further reduced by 11% per barrel compared to the same period last year. Now let's have a look at the segments. E&P Norway delivered an adjusted earnings before tax of $2 billion.
This is a doubling of the result delivered in the same period last year. Our improvement agenda continues to yield good results. This quarter, we delivered the highest Q3 production since 2009. In addition, we utilized our flexibility to produce more gas at higher realized prices. Also in the quarter, we had fewer planned turnarounds compared to last year. This resulted in an underlying production growth of 27% compared to Q3 2016. The underlying OpEx SDNA costs are at the same level as in the same quarter last year, even if you added new producing fields. On a per barrel basis, we see a reduction of 18% measured in NOK. Liquids prices are 16% higher, and the internal gas transfer price, 59% higher. Our liquids production increased by 8% and the natural gas production by 48%.
E&P International delivered adjusted earnings before tax close to zero, compared to adjusted earnings of -$0.6 billion in the same period last year. E&P International delivered an underlying flat production year-on-year, adjusted to changes in the portfolio. Higher prices and lower exploration costs contribute to the improvement. The cash flow per barrel after tax from E&P International is strong at around $18 per barrel on par with the NCS. Year to date, E&P International has delivered positive adjusted earnings of $1.1 billion. Our MMP segment delivered strong pre-tax adjusted earnings of more than $0.4 billion compared to $0.3 billion in the Q3 last year. The increase in earnings is due to strong liquid trading results, higher margins, and strong regularity at our refineries. The increase was partly offset by a price review arbitration award.
To the production. During the quarter, Equinor's total average liquids and gas production was 2,045,000 barrels of oil equivalent per day. This is up 240,000 barrels per day year-on-year. On the NCS, uptime was high. This combined with IOR and new wells largely offset the natural decline. Important incremental production volumes were added by increased production of flexible gas volumes at higher prices, mainly from Troll. Compared to last year, our turnaround activities this quarter resulted in lower production losses. Finally, ramp-up of production from new fields like Gina Krog, Ivar Aasen, and Byrding on the NCS, and increased production in the Gulf of Mexico contribute significantly. Early in 2017, we guided that Equinor would be cash flow neutral at an oil price of $50 per barrel, including our dividend program based on organic investment.
With an oil price just below $52 per barrel during the first nine months, we can report solid year-to-date progress with free cash flow of $3.6 billion. The organic free cash flow in the Q3 was around 0. Our net debt ratio is 27.8%, on par with last quarter. The figure reported for cash flow from operations in the quarter was impacted by $545 million related to FX movement on financial derivatives. We optimize interest charges through derivative instruments, and these may not be in USD, so we hedge these so there is no FX risk. Any movement in the USD/EUR shows on operating cash, but equal opposite effect in cash is shown elsewhere on the cash flow statement, mainly in cash flow from investments.
This is difficult to see directly, but explains why operating cash flow may seem below some expectations. Net at group level, no impact on overall cash flow on a year-on-year. Let me close with a few comments about our guidance. As I mentioned in my introduction, we are adjusting our 2017 CapEx guidance downwards from $11 billion to around $10 billion. This is due to excellent project execution, efficiency improvements, cost reductions, and strict capital discipline. We increased our production growth from 5% to around 6% in our guidance. The average annual production growth rate during 2016-2020 is unchanged at around 3% per year. Our 2017 exploration expenditure is unchanged at $1.3 billion.
In closing, please make a note that Statoil's Capital Markets Update will take place in London, February seventh, two thousand and eighteen. Thank you for your attention. I look forward to your questions, and Peter will guide us through it.
Thank you, Hans Jakob Hegge. With that, I'll pass the phones back to the operator who can explain the process for polling for questions. Thank you.
Thank you. As a reminder to ask a question, please press star one. We will now take our first question from Theepan Jothilingam at BNP Paribas Exane. Please go ahead. Your line is open.
Yeah. Hi, good morning, gentlemen. I just wanted to come back to the cash flow, if that's possible, please. Thank you for the clarification on the FX impact from derivatives. I wanted to perhaps just come back to cash taxes in previous times. Could you just update on where you see cash tax guidance going forward, perhaps both between the Norwegian piece and also international E&P? Just to bridge the gap therefore to Q4 cash flows. Thank you.
Thank you, Deepan. Let me just take one step back on the cash flow. As I said, we're neutral at $50, so this is in line with our guidance, $3.6 positive year to date. In the Q3 , the organic cash flow to investment and derivatives is an important explanation. In the first half of this year, we had $2 billion in the deferred taxes and $1 billion on CapEx. If you look at Q3 versus the Q2 on the operating activities, -$400, the derivative is $0.5, and taxes is $0.45. On this key P&L tax versus cash taxes, the P&L tax was $1.4 billion, taxes payable $1.5. There's a negative deferred tax of around $100.
We paid NOK 1.6 billion in taxes in the Q3 , and of those NOK 1.2 billion were in Norway. If you look at the Q4 , we will have 2 tax payments, each of NOK 1.2 billion. Only one we had this quarter. We still have free cash flow for the year, and we continue our efforts.
Was there any particular higher cash tax in international or?
Well, saying you can go into the international segment. As Hans Jakob said, it's we paid NOK 1.2 then in Norway, and you see the total then of around NOK 1.6. On the international segment, it can vary between the quarters. It's then also related to several of the countries that we are, where we are then paying taxes so it varies between the quarters. No major changes. Yeah. If you look at what we actually paid on the international, the tax on the adjusted earnings were NOK 51 million versus compared to the Q3 in last year, it was NOK 121 million. It was lower this quarter.
Okay. We'll move to the next question.
Our next question comes from Biraj Borkhataria from RBC. Please go ahead. Your line is open.
Hi. Thanks for taking my question. It was on the Eagle Ford. Could you just give some more details on that impairment and some more color around that asset? Is this a localized issue in certain acreage that you have, or is this an asset level issue? Can you talk a little bit about recovery rates and how things have changed versus your expectations, because it does look like quite a significant shift. Thank you.
Thank you, Biraj. The history we're coming from is that we both in this quarter and in previous quarters we had impairments and reversals. The largest one in this quarter is Eagle Ford. This is due to the trigger of reduced production rate. We, as part of the industry, started a year ago to do tighter well spacing, 200-250 feet. We had great faith in this measure, of course. We actually reversed based on the plans and the indicative results. That didn't turn out to be as favorable as we hoped for. We have, of course, stopped that practice and are changing it. This is an Eagle Ford issue, as it has been for the industry with tighter well spacing.
Based on that, we did evaluation, third-party market assessment, and we have started working improvement plan. We have moved from 250 feet well spacing to 500 feet, very early days, too early to conclude. The indicative result so far is in the positive direction. This is something we will come back to. As I said, there's uncertainty in valuation and reserves, so that's why we have these changes.
Great. That's very helpful. Thank you.
Our next question comes from Oswald Clint from Bernstein. Please go ahead. Your line is open.
Thank you very much. Good morning. Maybe just on the CapEx, the reduction, perhaps you could go into some examples of where you're actually getting more for less, if that's possible, certainly over the last nine months to actually cause that reduction. Maybe also can we expect that similar saving to flow into 2018? The second question, just quickly, I was curious if you could give us some numbers on the uptime or the regularity that you're speaking about maybe so far in 2017 versus same time period last year if possible, please. Thank you.
Okay. Thank you for the question. On the CapEx, this is very encouraging to see because we have more than 30 development projects, and we see small pockets of improvements across the board. It is what we call the cultural component. The obvious example, of course, from this quarter is the continuation of the improved world-class performance of Johan Sverdrup, taking it down another NOK 5 billion this quarter to NOK 92 billion. This is, as you know, a very big project, many elements, many moving parts, 60% completion rate on the project, and they just continue. This is very encouraging. The other clear examples over time have been in the drilling and well area where we are drilling faster, more cost efficient, less time, fewer mistakes. These are very strong contribution.
In terms of 2018 and CapEx, that's a natural theme for the Capital Markets Update, we'll revert to that. On the production efficiency and the uptime, we see very high regularity on the MTS, also on Peregrino for the quarter. We typically talk about uptime caused by not only very sound operational judgment by our people offshore, but also very good execution of the turnarounds, fewer unplanned losses. This is really a strong performance adding to the strong production in the quarter.
Okay. Very good. Thank you.
Our next question comes from Lydia Rainforth from Barclays. Please go ahead, your line is open.
Thank you very much. Two questions if I could, hopefully both very simple. Just to go back to the cash flow from ops and the $500 million that you were talking about. Is, just to be 100% clear on that, is that something that was just one-off related to the FX rate, or is there something else that means that that the cash flow will constantly be switched between the CFFO and the investment lines within that? I just want to make sure it's just one-off for this quarter. And then the second one, you talked about the use of flex gas in terms of what was a good production number for 3Q. Are you utilizing that flex gas capacity in the Q4 as well? Thank you.
To the last one, Lydia, probably for the Q4 , the flex gas, this is winter season, normally high demand. We have the power. We also have the increased permit on Troll to 36 giga. So this is likely to be used, and taken into account also when we say around 6% production. On the first one, they will vary quarter-on-quarter. This quarter is FX, so it depends on your view on FX and fluctuations in that.
Okay, that's it. Thank you.
Our next question comes from Teodor Sveen-Nilsen. Please go ahead, your line is open.
Good morning, and thanks for taking my questions. First I have another question on CapEx. It's like a stated CapEx guidance of $10 billion per year. Is that sufficient to support a 3% growth up to 2020, excluding any potential post-inflation effects? Then my second primary question is another one on Eagle Ford. It definitely makes sense that the changes you have made to the book value there, but by how much have you changed the assumed production level going forward? Thanks.
Okay, Teodor Sveen-Nilsen. On the CapEx, $10 billion sufficient to support 3% growth? Yes. No changes to the growth rate. We think this is sustainable. On the Eagle Ford, our production guidance for this year takes into account all the changes in the portfolio. It doesn't give a level of detail specifically on Eagle Ford or the US, but it was a high quarter, a high production in the quarter in the U.S., a combination of ramp up in the Gulf of Mexico, but also significant contributions from the onshore, particularly Bakken and Marcellus produced very well. Since we are into a phase now with improvement work on Eagle Ford, I think this is a topic that we will revert to on the implications for onshore.
Let there be no doubt that our production guidance from around 6% is an increase, and we have changes because we think we are likely to reach it.
Okay. Just another one on the Eagle Ford. Could you, is it possible to indicate somewhat like the range or the reduction from what we estimated production? Is it down 5% or down 50% compared to your previous plans?
No range today.
Okay, that's fair. Thank you.
Our next question comes from Alastair Syme from Citi. Please go ahead, your line is open.
Hi. Good morning. Can I ask about the revision to the medium-term oil price that you've made? You know, OPEC has acted to firm the oil market this year, so I wonder what made you change or delay your $75 view by 2 years. Can I also ask what the $75 view is based on? You know, why is it not 60 or 90?
Very simple answer to that. It is complex, but simple answer, more cautious view.
Is there a-
The 75 is unchanged, and it's a two-year deferral due to some of the resilience that could potentially come from the onshore part, it hasn't been overly strong, the production from the onshore, but they still have the capacity. We think the development in the storage levels, yes, they are coming down. They're coming into a rebalancing of the market. Just a more cautious view on it might take some time to reach the 75.
A view essentially that U.S. shale comes back into the market a little bit more aggressively. Is that what it takes to reach?
To reach the 75, we also need conventional production kicking in. You know, we had three years of under-investment. We still have a firm view on the oil price going to go up over time.
Okay, thank you very much.
Our next question comes from Rob West from Redburn. Please go ahead. Your line is open.
Yeah, hi. Thank you very much. I'd like to ask two. One is on the different shale basins in the U.S. Could you give us a sense of how you are in terms of free cash flow within those basins? So are they absorbing cash, or something like the back end? Is that, you know, getting towards a more cash generating position? Really, the reason I was wondering is in the Eagle Ford, you know, you talked about the impairments there that are typically non-cash. I was wondering, are there any one-off extra cash flow hits from, you know, what some of your competitors call things like train wreck wells with that tighter down spacing in Eagle Ford?
Whether there's some extra CapEx that's sort of dropped out and not be spent going forward. Second one's just really quick. Was there something elevating your depreciation rate in Norway in the quarter? Normally, when Troll ramps up, it does. Are you expecting depreciation to go down? But it stayed pretty high, and so I was wondering if you could comment on that. Thank you.
Okay, thank you for those questions. On the shale in the U.S. and the cash flow, what we say is, on the international, it's on par with NCS, overall. Remember we have given figures on wells with a competitive breakeven, and we've also given ambitions for cash generation of $12.5. We have good progress on this program, which we call the 90 to 50. On the well spacing and the change of CapEx, it's too early to conclude. We have changed the well spacing to a wider space of 500 feet, but we haven't gone to say any change in the CapEx related to the changes. It's too early. On the DD&A, this was Norway, right?
In Norway, it's -5.5% per barrel year-over-year in NOK. Remember we have new barrels like Gina Krog, Wisting, Ivar Aasen. They are NOK 140 million. If you look at contributions and the FX, it's around NOK 60 million. There is NOK 200 million related to that.
Okay. Yeah, I guess that's clear. It's maybe also the FX is contributing there as well. Thank you. Helpful.
Yeah. Around 60.
Our next question comes from Jon Rigby from UBS. Please go ahead. Your line is open.
Yes, hi. Take the point about the increase in guidance for production for 2017, but also note that you've not changed the medium-term guidance. I just wanted to look a little closer at this increased gas production in the Q3 Are you able to characterize the quarter in terms of what was just you taking opportunity, what you think was unusual demand characteristics in the quarter, and what you think may be somewhat more structural?
If there is some kind of uptick in structural demand in continental Europe, and the U.K., is or does your portfolio technically, from a license perspective, allow you to run at higher rates over the next 2-3 years than is currently envisaged in your production guidance, which will be more consistent with your 2017 performance? Thanks.
Thank you, John. To the last part, yes, our portfolio allows us. Remember, we have the increased permit on Troll 36 here from Q4 , and we are ready to use it. To the first part on unusual demand versus structural demand, U.K. is of course an example. You gave it yourself, replacing coal with gas. We also saw quite high demand in Europe, warm weather boosted gas to power. We saw fairly low storage levels and/or strong gas production in the quarter. We also saw some deferred volumes from 2016.
The EU gas prices were up 8%, and in addition to the increased production permit for Q4 , we actually see some bullish pricing for the EU gas for the rest of 2017. I didn't mention the storage and the capping of Groningen. This, taken into account, we have a quite optimistic view going forward. Yes, we have the capacity.
Just to confirm, when you set out your medium term view last year, it was a mix of what you could technically produce and what you thought the market would technically or would want, and you sort of plotted a course between those two numbers. Is that a way of thinking about it?
Yes. Yes.
Yeah.
You're right.
Thank you.
Our next question comes from Brendan Warn from BMO Capital Markets. Please go ahead. Your line is open.
Yeah. Good morning, gentlemen. Thanks for the opportunity to ask a question. Most have been answered, but I just wanna look at 2018, Hans Jakob Hegge. Just you've still got quite a stubbornly high gearing. You've made note that you've got allowance to produce for more from Troll, but I just remember seeing something that 2018 we're expecting higher annual sort of turnarounds. Can you sort of talk through, obviously we're gonna have higher cash taxes in 2018 because of the oil price this year. You're moving to a full cash dividend in 2018. Just the expected impact to your gearing level, if you're expecting that to actually tick up in 2019 at sort of current oil price levels, or what you're looking to do to sort of arrest some of that issue.
Okay, thank you, Brendan. On the gearing, we maintained it flat in the quarter, still below 28%. Turnaround activity next year, yeah, it is higher than this year, but we will come back to the specifics on that one. Increased prices, more taxes, you're right. Cash dividend, you're right. Remember, we have reduced annual expenditure and improvement of NOK 3.2 billion, adding another NOK 1 billion this year. We are fostering a culture of continuous improvement. We expect to see across the board further improvements. We are not stopping by any means. We have more than 30 digital pilots. We haven't talked a lot about those. Many things to look forward to, I think.
Can we move to the next question?
Our next question comes from Christyan Malek from J.P. Morgan. Please go ahead. Your line is open.
Hi, good morning, gentlemen. Thanks for answering our call and to ask questions. Three questions. First, I know you talked about $10 billion being sort of the updated guidance. Can you just confirm that's gonna be your medium term outlook on CapEx, and there's no upside risk to that, particularly with a slightly more bullish view on oil prices versus where the forward curve is, those are surprises to the $10 billion? The second question is regarding sort of the approach of derivative instruments in your cash flow. Clearly given the negative reversal into Q3, I just want to understand how we think about that in the context of your cash flow going into Q4, particularly as tax installments go up.
It was strong in the first half, yet didn't seem to be netted out of cash flow and now it is being netted out. The third question is regarding the switch off the scrip. Is it too early to ask you whether there is a view or a discussion around the board on whether you look to some neutralize or buyback in 2018?
Okay, thank you. On the last one, this will be part of our CMU communication in February. On the derivatives, this is a one-off, and on the NOK 10 million CapEx medium term outlook, unchanged.
Very clear. Thank you.
Our next question comes from Hamish Clegg from Bank of America. Please go ahead. Your line is open.
Hi there. Thanks a lot. A couple of quick ones. Just first of all, just could you give us a tiny bit of color on what we can expect in international exploration in the Q4 ? We saw a bit of a kick up this quarter and to hit your guidance, and see that somewhat higher than the first half of the year. Also, this is a long shot. You know, if you pull your guidance down to 10 for this year, you're guiding 11 for the two-year period, should we be forecasting a higher number next year to account for all those projects like Johan Castberg and that you're intending on FIDing? Can we see a slightly busier FID pipeline? MIT, thanks.
Thank you, Hamish. On the last one, no, not higher CapEx for 2018, but we will revert to the CapEx for 2018. We cannot interpret it as a significant change from this year. It's something we will revert to. On the international exploration guidance, we keep it unchanged activity level of $1.3 billion for the year. We have said that we would do around 30 wells. We haven't given any changes to that. We had several discoveries that could be tied in. There will be wells around year-end, which has not been completed. Yeah, there's no change as such on the guidance and most of the wells will have been drilled and we don't expect any major changes.
That's why we keep the guidance unchanged.
A tiny follow-up. When we hear about the Brazilian licensing rounds, can we expect that to be fed into the CMU? Or might you give us a little bit of color, kind of post that announcement? I'm guessing it will be at some point on Friday.
That would be a part of CMU.
Okay, cool. Thanks a lot.
Our next question comes from Anne Gjøen from Handelsbanken. Please go ahead. Your line is open.
Thank you for taking my question. 2 questions, if I may. First, on page 5, E&P Norway, 18% cost reduction per barrel. Could you comment something on the cost level, next quarter and into 2018 as well? On the same slide, MMP natural gas impacted by price review. Could you comment, give a bit more flavor on how much the impact is of that review? Thank you.
On the first one, on the E&P Norway, you're absolutely right. We're still getting cost improvements. On group level, the OpEx reduction is 11% in the Q3 , and in E&P Norway, it's 18%, as you said, year-on-year per barrel. We see field costs down year-on-year, and we also know that cost per barrel will vary with the production mix. Typically towards the end of the year, you would see high levels of gas produced, and with an increased premix. That gives an indication of the development. In this quarter, we added significant volumes from Gina, Byrding, Ivar Aasen. The production mix is also part of this. You know, remember, NCS is now at a 10-year low on cost.
Our next question comes from Anish Kapadia from Tudor, Pickering, Holt & Co. Please go ahead. Your line is open.
Hi. First question was on the balance in your portfolio of short cycle U.S. onshore versus longer cycle, following this, the downgrade in Eagle Ford. Just wondering how do you see that balance at present? Would you be more inclined to make acquisitions U.S. onshore or outside of that space? And just kind of related to the Eagle Ford downgrade, I think there's some concern in the market over your relatively low reserve life. And I'm guessing that's gonna fall further on the back of the Eagle Ford downgrade to reserves. Just how are you kind of thinking about reserve life within that context as well? And then just one quick clarification.
Based on kind of current oil prices, is it fair to assume that your cash tax payable in 2018 will be about $2 billion–$3 billion higher than in 2017? Thank you.
Okay. I'll start with on the second question before I refer to you, so excuse me for that. On the price review, it is significant, but it's less than NOK 100 million in the quarter. To your three questions. Onshore M&A, well, unfortunately I have no announcement on M&A, either onshore or offshore, today. We have an opportunistic view on M&A we have had in the past, so we'll talk about it if and when something happens. In terms of reserve life on a portfolio level, we like to talk about the next generation portfolio with an excellent breakeven with $27 on average. Short payback time, 2-3 year IRR, 20%. You've heard me say this before, so we're not worried about that.
On Eagle Ford, this is part of what we are assessing, based on the change and the improvement work we are doing. On cash tax, going forward, I leave that to Svein Skeie.
On cash taxes, remember what we said for the first half of this year is then we had the benefit then from the oil price level and gas price levels from 2016. We said that for the first half that it has an impact of approximately 2. It will be dependent on the price of oil in the second half. We are paying the cash taxes on NCS based on the prices that we're currently seeing.
I said that we paid NOK 1.6 billion in taxes in this quarter, and that was NOK 1.2 billion related to the first tax installment in 2017 Norway. I also said I think that we will have two tax installments, NOK 1.2 billion each in the Q4 .
Thank you.
Thank you. We will now take our next question from Marc Kofler from Jefferies. Please go ahead. Your line is open.
Oh, hi there everyone. Thanks for taking my question. Just to Les please. Hans Jacob Hegge, a few weeks ago you talked about CapEx rising slightly 2020 from $11 billion in 2017. I'm not 100% clear in my mind if that's now rising slightly from $10 billion in 2017 or if 2018 number is still premised off that rising slowly off $11 billion for this year. Could you also give a bit more color around the trajectory on volume growth out of the U.S. year-end? Thanks very much.
Well, thank you, Marc. On the volume growth, the U.S. towards year end. If you look where we're starting, we continue to look closely at the economics before we raise activity. At the moment on the onshore, we have the 5 operator rigs and 4 completion crews, 2 in Bakken. Onshore has increased year-over-year with new wells in Bakken and Marcellus non-operated due to improved basin prices. In the Gulf of Mexico, we are up year-over-year on Heidelberg, Tahiti, Julia and 7 new wells. That's the starting point. Offshore we have increased production. Onshore, we will assess it based on cautious economic considerations. Bear in mind that, you know, our guidance on production for the group has been raised to around 6%.
On CapEx going forward, I think this is a natural theme for the Capital Markets Update in February.
Okay, thank you.
Our next question comes from John Olaisen from ABG Sundal Collier. Please go ahead. Your line is open.
All my questions have been taken. Thank you.
We'll now take our next question from Iain Reid from Macquarie. Please go ahead. Your line is open.
Yeah, hi guys. Just another question on CapEx. Maybe you can answer this one. The Brazil pre-salt license rounds, as was previously mentioned, that's closing tomorrow. You're gonna be awarded the doorstep counterpart, which has got a signature bonus of BRL 3 billion. Are you gonna take your share of that in the Q4 , or is that gonna be a 2018 item? Thanks.
The day before the bid closes, I won't make any comments on Brazil. I will have to revert to that.
Okay. Well, I can ask just one other quick one then. When you gave that answer about cash taxes in 2018, I couldn't hear the answer because there was a lot of interference on the line. Do you think you can just repeat the answer to that a few minutes ago?
I did comment on it. Sorry if that's not coming through to you. I just commented on the taxes that we had in first half of this year and where we said that those had the benefit from the price level in 2016 and then estimated that to be around NOK 2 billion in the first half in lower taxes compared to if we had paid the taxes based on 2017 prices, on 2017 production. This-
Okay.
The next quarter is.
Okay, thank you everybody. I think that's the end of the questions. I'd just like to thank all the participants both on the call and here in the room in Oslo. Just as a reminder, we have our Q4 earnings and capital markets day, as Hans Jakob Hegge said, on the seventh of February. Look forward to meeting you then and, of course, engaging with you before then. Any other questions, as always, please direct them through to investor relations. Thanks very much.