Lundin Petroleum AB (OTCPK:LNDNF) Q3 2018 Earnings Conference Call November 7, 2018 3:00 AM ET
Edward Westropp - VP, IR
Alexandre Schneiter - CEO
Teitur Poulsen - CFO
Rafal Gutaj - Bank of America Merrill Lynch
Teodor Nilsen - SB1 Markets
James Thompson - JP Morgan
Johan Spetz - Pareto Securities
Robin Haworth - Stifel Nicolaus
Gudmund Hartveit - Fearnley Securities
Mark Wilson - Jefferies
Good morning. Welcome to the 2018 Third Quarter Results from Lundin Petroleum. I'm going to hand over shortly to Alex Schneiter, the Chief Executive Officer, who will take you through the highlights and operations; and Teitur Poulsen, the CFO will take you through the financials. We'll then have a Q&A session following that.
And I hand over to Alex now.
Yes. Thank you, Ed, and good morning, everybody. Very pleased to be here and also very pleased with the sets of results we announced today for the first nine months in the third quarter. But let me move on directly to the presentation, the highlights.
First of all, as you've seen, strong production is continuing. First nine months, we've averaged in excess of 80,000 barrels of oil equivalent per day and delivering 78,000 for the third quarter. This is very much in line with the guidance of 78,000 to 82,000, and we're firmly on track to achieve our mid-line guidance for the full year.
You've seen also in the operating cost that we continued to deliver very low operating cost. In actual fact, we've actually now reduced our guidance from what used to be below $4 per barrel to today below $3.8, and those are extraordinary operating cost per barrel and really shows the efficiency and the level and the quality of the assets along the petroleum asset. And of course, strong production, low operating cost goes along with the financial performance, and very pleased with the historical record free cash flow for the first nine months at close to $0.5 billion. For the Q3 alone, we generated USD 230 million of U.S. dollars on free cash flow, so very strong numbers.
On the EBITDA, for the second quarter in a row, above $0.5 billion and also strong operating cash flow. So of course, those numbers give us very strong elements to -- for dividend stories. However, we said we will be paying dividend and this is sustainable in the long term. And with these numbers, you can see that, more than ever, we will fulfill those promises.
Those performance of course come mainly from Edvard Grieg, which is our main assets today and where we operate and we own 65%. Our production efficiency of Edvard Grieg continued to outperform. But in reality, both the above surface and below surface are outperforming Edvard Grieg. That's been the ongoing story, and I'm convinced that this will continue. As you've seen on the -- this morning news, we've actually extended the plateau for another six months, and that's really on the back of the performance of Edvard Grieg.
Johan Sverdrup, a lot of you know quite a lot also from the operator's news in Equinor, another very good year. We pretty much -- or 2018 installation is behind us. A lot has happened. We are more than 80% complete. I think -- and we also increased our resources from today standing at 2.2 to 3.2. One thing we can say today firmly is that we are on track to achieve first oil by November 2019, and Equinor is the operator. Johan Sverdrup has done a very, very good job in executing this project.
I think the big story for me is also the growth opportunities. I always said that the organic growth strategy is the main strategy of Lundin Petroleum, and I think we're delivering and we continue to deliver positive news on that front. We have now six potential new projects beyond Johan Sverdrup, and I will say a little bit more in my presentation. And we have still five exploration well for the remainder of the year, some very exciting exploration wells in different areas and really pleased with the results so far. But I will say a few words later on when we come to that.
I think you've seen that slide, but it's quite phenomenal when you think about it. We've -- for the last 14 quarters in a row, we've been producing at or above guidance, and while our production has more than tripled from '15 and three years later to where we are today at 80,000. And while we were increasing our production and fulfilling our own guidance, we've also been able to reduce operating cost. So we definitely are very proud of this performance.
On the production side, I already stated where we stand with the -- for the first nine months of 80,000. And as I stated to you, we are firmly on track to achieve our guidance for year-end. I think this is really very much on the back of the performance of Edvard Grieg. We have an uptime of 97%; and in Alvheim, 96%. And I really continue to see this -- both these assets performing and providing really high uptime, so very pleased. I don't know, of course, the uptimes have direct impact on the performance on the production.
Edvard Grieg, I think there's two things we can say. Number one is that Edvard Grieg continues to perform both above surface and below surface. We still see no material water production from Edvard Grieg, and above all, this has led us to increase the plateau or extended plateau to another six months, which is now standing from what was end of '19 to mid 2020, so very positive news on Edvard Grieg.
The second point is, this is really important for Edvard Grieg, is that we see a pipeline of opportunities coming, which will actually extend further the plateau by tying new discoveries into Edvard Grieg and keeping the facilities of Edvard Grieg full for a long time. I'm thinking, of course, of Luno II appraisal, successful in the project. We're going to submit a Plan of Development early next year already. And I'm also thinking about the Rolvsnes, the basement play, which we successfully tested there a few months ago. And we also have Lille Prinsen for the North, which is also a potential tieback. So as you can see, beyond the Edvard Grieg, there's also a lot more we will be doing, and that we'll keep the facilities full for a long time.
Alvheim really is the same story. Alvheim has been producing -- it's a more mature field, been producing for the last 10 years or a little bit more than 10 years and very successful in its infill drilling and in reducing the decline rates of the field. And the second point that's been very important in Alvheim is what has happened with Frosk. It's a good discovery with a lot of follow-up.
With this year alone, we're going to be drilling two more wells there in that area of Froskelår and Rumpetroll. It's actually fascinating to see that, that area has a potential of over 250 million. That was actually the resource -- the reserves we quoted when we submitted the PDO in Alvheim. So even 10 years later, we are able to show that there are even more to come, and those obviously will be -- ties back to the Alvheim facilities. And again, we will be able to maintain the facilities full for a long time, so very, very good story for Alvheim, very successful, too.
Johan Sverdrup, I think a lot has been said. A lot of events this year. We've seen the resources increasing to a range from 2.2 to 3.2. Phase 1, Phase 2 remains at 440,000 for Phase 1 growth and when we come in production of Phase 2 2022, 660,000. The big event on Phase 2 was the submission of the development plan end of August of Phase 2. And now we're already on track to execute this Phase 2 project. And we've seen cost continuously coming down. So, overall, really a very, very strong project and very pleased where we are today with this project.
And in terms of execution and delivering, in red, in this slide, you see what has been achieved so far. So really the major operations in the history of Johan Sverdrup is pretty much behind us. The only thing left to do this year is to complete the gas pipeline. And it's fascinating to see that actually, both platform today are already powered from onshore. The two remaining items is really the installation of the two platforms, remaining two platforms, the processing platform of living quarter, which will be installed next year and then achieving first oil in November 2019.
This is one slide that I think is important. We're going to be more and more explicit in terms of the, call it, the beyond Johan Sverdrup. But from this slide, you see how active we've been. And you also see how successful we've been this year in terms of maturing this appraisal project such as Alta, Luno II and Rolvsnes. But let me say a few words on each of one because I think it's important. Luno II, we successfully appraised this year the discovery. We increased our resources to -- from -- to 40 to 100. And we also increased our equity in Luno II by 15%, so that Luno II and Edvard Grieg are fully aligned. So commercially, a big advantage. And we are going to submit a PDO by early of next year. So this is moving, and it will be a tieback to Edvard Grieg.
Rolvsnes, we successfully tested along horizantal well of two kilometers over 6,000 barrels per day, very successful well, very pleased with the results. We've seen also the resources increasing, and we're going to sanction next year and extend well test, which will also tie back to the platform in Edvard Grieg. And we will going to see further appraisal with also the oil exploration with Goddo coming next year, which can further increase the overall resources in that area.
Alta/Gohta, really the same story. The extended well test for two months was completed very successfully. Very pleased with the results. We're currently digesting all these results. We also acquired a large 3D seismic, which we're currently interpreting. So we will be coming back to you towards the Capital Market Day there with updated resources. And in '19, we're expecting for the appraisal. But we're definitely moving closer to commerciality in Alta/Gohta.
And then we have the Frosk discovery, which I talked about just a while ago with two follow-up wells in Q4 of this year. Lille Prinsen also will be appraised next year. And the Gekko appraisal, the well was successful. So you can see already now six potential new project, which will be potentially delivered during and post Johan Sverdrup. This is actually to give you a more clarity in terms of the timing. We've talked about all this pretty much in the previous slide. But you see that between 2021 and 2025, we have the optionality to bring all these project on stream above the production profile of Johan Sverdrup.
And then on the exploration side, the story continues. We've been very successful to date. We've drilled three exploration wells and add two discoveries, I'm thinking about Frosk and Lille Prinsen. But today, we are -- ahead of us, there are some really exciting new exploration wells. We will be drilling on the Norwegian Sea. We will be drilling on the Mandal High, and we will be drilling towards the Alvheim area. So a lot of activities. And as we speak, we're actually drilling now Silfari well, which we anticipate results towards end of November, early December.
And you will see and we will come more clearer next year, our exploration activity will be very high and we will continue to explore what it is now six core areas. So very successful, and I really see that our organic growth story is continuing and is very powerful.
So with that, I think I'll leave it to Teitur, and hopefully, I can adjust my voice. I have a bit of a cold, I apologize. Thank you.
Okay. Thank you, Alex, and good morning, everyone. And well done to you, Alex, for busting through that cold. So as Alex already said, a fantastic quarter again both from an operational perspective and that has obviously fed through into the financials as well. So I'll take you through the key financial highlight numbers on this first slide, some of which Alex has already touched upon. Production, as Alex said, is in line with guidance, in fact, in -- towards the midpoint of our guidance, just over 78,000 barrels oil equivalent per day for the quarter and just below 81,000 barrels oil equivalent per day for the first nine months.
The Brent price continues to be strong. In fact, this third quarter is the strongest quarterly oil price since the collapse almost three years ago, $75 Brent for the quarter, and we've averaged for the first nine months $72 per barrel.
Operating cost continues to be extremely low. In fact, this is the third quarter in a row where we have achieved operating cost below $4 a barrel; in the third quarter, $3.88, and for the first nine months, $3.50.
Operating cash flow and EBITDA generation continues at pace. Operating cash flow 600 -- sorry, $460 million for the third quarter and just above $1.4 billion now for the first nine months, and EBITDA, as Alex said, the second quarter in a row where we have achieved in excess of $0.5 billion EBITDA, $503 million in the third quarter this year. And the nine months, close to $1.5 billion in the EBITDA generation.
Free cash flow is improving all the time for us as well. In the third quarter, as Alex said, a record of $230 million and now close to $0.5 billion for the first nine months. These free cash flow numbers are before dividend payments. And the net results for the quarter, 60 -- just below $63 million and just below $330 million for the first nine months.
Looking at operating cash flow and the comparative periods to 2017, taking the first nine months first, you can see the realized price we achieved is 39% up on the same nine months last year, whilst production is down around about 7%. So that has allowed us to increase operating cash flow by 30%, as I said, off to just above $1.4 billion. In our first nine months, we have accrued for $55 million of current taxes arising from our Norway operations compared to the nine months last year when we did not have any material current taxes coming through our operating cash flow.
For the third quarter, similar metrics on oil price and production, but the third quarter operating cash flow is up 18%. So a smaller increase to -- compared to the nine months. And the reason for that is in the third quarter alone, we have accrued for $46 million of current tax charges, again, relating to Norway versus no current tax charges in the third quarter last year, but nevertheless, a healthy improvement of close to 20% quarter-on-quarter.
EBITDA generation, which is a much cleaner metric, given that there are no tax distortions in here. So EBITDA up 37% on the nine months, obviously driven by the higher oil prices, offset by lower production, but we also had lower OpEx around about $15 million and lower G&A of around about $7 million compared to the same nine months last year. And for the third quarter, as I said, over $0.5 billion, up 32% on the same quarter last year.
Free cash flow generations, very strong indeed. You can see here for the first nine months, it's more than a tenfold increase of close to $0.5 billion for free cash flow. And for the third quarter, up more than three-folds, 238% increase to $230 million. This was generated by funds from operations of $480 million or thereabout, offset by CapEx and E&A investments of $250 million, so giving us $230 million of free cash flow.
And just zooming out a bit and setting this into a historical context, I won't go through all these slides, but just to show you over the last 11 quarters, you see the red and orange bars EBITDA and operating cash flow, which read against the left-hand axis here, really a very strong continued sort of improving trend, really right from first quarter '16. You look at EBITDA back in '16 was just below $100 million for that quarter versus over $500 million, also a fivefold improvement, so very healthy indeed.
And on the free cash flow numbers, which are all pre-dividend payments, you can see this cash flow inflection point we talked about last year, which occurred between second and third quarter last year. And we now, for five quarters in a row, generated free cash flow, and we very much see that trend continuing going out starting at these oil price levels.
Then the net result itself, the top of the bar share is what we have reported on the face of the P&L over the nine months and the third quarter. So we've seen a drop both for nine months and for the third quarter, and that's driven by mainly non-cash FX impacts we incur when we mark-to-market FX rates on intercompany loan balances and also the loan balance to the external banks. But if you look at the underlying performance of the business, which is these horizontal stipulated lines, you can see from the nine months in '17 to nine months this year is an improvement of 116%, over $100 million improvement after tax. And similarly, for the third quarter, from $41 million third quarter last year to $73 million this year when you strip out the non-cash FX items.
Then looking at the income statement itself, this chart excludes the revenue and cost from the third-party crude oil marketing that we're doing and which we have pre-announced to the market. So excluding that, we had total revenues for the nine months of close to $1.6 billion and we have production cost of $105 million, and including the G&A that effectively gives us an EBITDA margin of over 90% again for the nine months, so extremely good EBITDA margin generation here.
We also had the margin from the crude oil marketing activity to third parties of just below $2 million. That margin is generated outside Norway, so it's not subject to the Norway tax regime, which, therefore, means that on an after-tax basis, that margin is not too bad. So that generated the cash margin of $1.48 billion.
Depletion rate runs at our normal level of around about $15 a barrel and that translated into $340 million of depletion charge. And then we had the exploration cost of just one dry well written off in the first nine months, which was Korpfjell of $6 million, giving us a gross result of just above $1.1 billion.
G&A of just below $18 million, and financial items is a positive given the one-off accounting gain we recognized in the second quarter from modifying our loan agreement, that's a record $98 million post-tax gain on that, so that's why we have a positive all-in financial items of close to $50 million.
The tax incurred on the face of the P&L, $840 million. Most of that is, in fact, deferred. Out of that $55 million is current tax, the rest is deferred. And thus, that gives us a net profit after tax of just below $330 million for the first nine months.
The realized oil prices we are achieving, as you know, we are very oil-weighted in our portfolio. Typically, around about 90% of the total hydrocarbon sales we have in any quarter is oil. And you can see here at the top of the green bar is what we have realized for our oil sales, and you measure that against the stipulated horizontal bars, which is the Brent average for the quarter. And you can see here we've averaged just below $1 discount to what the Brent price was. And we then blend in the gas and the NGLs. We have an all-in realized BOE price of just below $71 a barrel.
During the third quarter, we had nine Edvard Grieg liftings, and those sold at an average discount Brent of $1.40. And we had one Alvheim lifting, which sold at $1.80 premium to Brent. But in terms of Edvard Grieg when we have looked at the sales we've done in October and we've completed the sales program for November, that discount to Brent has actually been narrowing over those two months. So that's very positive to see.
Our operating costs are trending at a very stable sort of level of all-in around about $35 million per quarter. You see in the second quarter, we had a one-off reversal of an accrual relating to Brynhild of $5.5 million. But if you add that back, then also in the second quarter, we were around about $35 million all-in on operating cost. And as I said, you can see here on the red line that this is our unit operating cost once we have netted off the tariff income from Ivar Aasen. And we've been now achieving, as I said, three quarters in a row of below $4 a barrel operating cost. So this is industry-leading numbers, very low numbers indeed. And as we say, we see this trend continuing for some time going forward.
G&A and financials, no major items to report here really on the G&A, $18 million; we have guided for the full year around about $25 million, $26 million. We always have a slightly higher G&A in the fourth quarter given that we accrue for year-end bonuses, et cetera, in that quarter. So expect our G&A to be roughly in line with the full year guidance that we gave at the Capital Markets Day.
Net financial cost items in the third quarter, we had a $51 million cost. But for the nine months, we had an income of $50 million. And that, as I said, relates to the loan modification gain here of $166 million. We have now recognized that on the balance sheet as an asset, which we then unwind for the remainder of the loan life. And you can see that unwinding in the third quarter translated into around about $11 million, which is a non-cash item now, but you should expect to see around about that level of unwinding every quarter going forward.
In terms of the interest expenses for the first nine months, just below $70 million charge to the P&L, but in addition to that, we have capitalized another $65 million of interest costs. The foreign exchange losses are for the nine months almost 0. In the third quarter, we had an FX loss of $11 million, which we also pre-announced. And it's also worth pointing out that for the first nine months, we have actually realized gains on our NOK hedges of over $7 million. And you can also see here resource on our interest rate hedges for -- in the third quarter was close to $2 million. So those hedging instruments are now starting to be in the money.
Our cash flow generation, as we have touched upon already, has been very, very strong. So this is from our cash flow statement. We had funds flow from operating activities of close to $1.3 billion. Our CapEx and E&A investment levels have been around about $800 million for the first nine months. And that has, therefore, given us close to $0.5 billion of cash flow, free cash flow.
We repaid debt of over $300 million for the first nine months, and we distributed additional -- our first inaugural cash dividends in May this year, $153 million. We purchased some shares into Treasury, not in the third quarter, but earlier in the year, $14 million. And with that loan notification that we closed on the 1st of June this year, we paid fees on that notification process of $17 million. And during the nine months, we've had a small cash build of $3.7 million, and we also include in that an FX gain of $8.7 million. So very good cash flow generation, as you saw earlier, and that now leaves us with a net debt of $3.6 billion, which, therefore, gives us a liquidity headroom within our credit lines of $1.4 billion. So a very strong liquidity position for the company.
This is my last slide, and this is just to reiterate on our guidance. The only change here, as Alex already mentioned, is the fact that we are guiding down our unit operating cost from the previous four -- below $4 a barrel. Our guidance now moves to below $3.80 per barrel for the full year, whilst production and CapEx and E&A remains unchanged at $800 million and $300 million, respectively, for the full year.
So with that, I will hand back to Alex for concluding remarks. Thank you.
Thank you, Teitur. Yes, this is our last slide before we go into Q&A. Really, I have really four messages I would like to leave with you.
First of all, we're well our way to be on a leading production growth company. Years after year for the next four years, we will have a company growth rate of about 20%, and that is really led by Johan Sverdrup. But as you've seen from our previous slides, beyond that, we will do better, particularly with these six new potential project, and hopefully, with further exploration successes.
Of course, the low operating cost and good productions has led to very strong financial results, and we are well on our way to generate significant long-term free cash flow for the years to come. And that leaves obviously to our capacity also to sustain long-term dividend and significant, and we already stated to the market that we will be paying '19 at or above $350 million. So well on the way to do so, and we'll be clear towards year-end when we have the full financial year in terms of guidance, final guidance for dividend for '19.
And as you've seen, in terms of organic growth, we are delivering. So far, the first nine months have been very good for the company with exploration successes and also further maturing and bringing closer to commerciality other projects such as Luno, Alta and Rolvsnes and a lot more to come. This year alone, we have five more exploration wells that we will be drilling. And next year, you will see, particularly when we're going to meet for the Capital Market Day, our exploration program will be very exciting, so very pleased overall.
So with that, I think we leave the floor for questions, so maybe, Teitur and Ed, if you come back with us.
[Operator Instructions] And the first question comes from the line of Rafal Gutaj from Bank of America Merrill Lynch. Please go ahead. Your line is open.
I have three questions all around the theme of production, please. First one, I just wanted to get a little bit more color on quarter-on-quarter production trends in Q3 versus Q2, given that production efficiency on Edvard Grieg, I guess, was flat. I just wanted to get a little bit more color on why we saw a small notch down there? Then secondly, as we get into closer to 2019 and we think about the three main production drivers for you Edvard Grieg, Alvheim and Volund, I wonder if perhaps maybe it's -- if it's still too early to give specific numbers. I wondered if you could just characterize how we might see those fields producing into 2019. And then last question, just on the Johan Sverdrup and the guidance on start-up being November and obviously plateau guided for Phase 1 is about 440,000 barrels a day. Could you just remind us on what the pace of ramp-up might be on that field? And should it be -- should we assume a straight line? Or is it going to be slow first and then quicker towards the end? Or yes, if you just give us some color on that, that will be great.
Yes. Thanks, Rafal. I will take all these three questions. I think your question regarding quarter-after-quarter, first of all, if we started with the core Tier 1, which was our best in terms of production so far this year, that was already much led by our ability to actually fill in more capacity because of Iver Aasen. As you know, we have a commission arrangement. And right now, we're assuming the Iver Aasen takes the full capacity. But at times, we are able to fill in more than what we anticipated. And that really is the main drive in terms of our performance quarter-after-quarter. So Q1 saw a strong, quite a relatively strong production, and that was because we have the opportunity to fill in more capacity. And the other quarters, I would say, they're pretty much equal. We had a planned maintenance in the third quarter. But overall, I would say, Edvard Grieg hasn't changed as performed over the nine months equally, and the change is very much related to our capacity or not to fill in more when Iver Aasen perhaps -- when Iver Aasen has not filling in their commercial capacity. And right now, for the fourth quarter, that I'm -- I said Edvard Grieg is performing very strongly.
So really, when you think about the production for the full year, you should be very comfortable to use the midpoint for -- midpoint guidance production of 80,000. And your second question was in relation to the more, I guess, you're looking more into '19. I think you're right. I mean, I see two assets: The Alvheim hub, which is made of Volund and Alvheim and Edvard Grieg before Johan Sverdrup comes on stream. Now Edvard Grieg will behave the same. The Edvard Grieg, as you know, will be still on plateau. So -- and as of today, we see no sign of any water. In any event, we have more than 100% extra capacity on the wells. So Edvard Grieg will continue to perform the way it has been performing this year, so it shouldn't be different from '18. And Alvheim, we have few wells infill. There is a slight decline on Alvheim. But overall, I would say, 2019 -- we will be more specific during the Capital Market Day, but 2019 will be not very different from '18. What will affect mainly the production of guidance on '19 will be the first oil on Johan Sverdrup. Other than that, I would say it will be quite equal to '18. And your third question was in relation to Johan Sverdrup, and I think the question was on the ramp-up, yes.
The ramp-up, yes.
It will be very quick because the -- today, I mean, very -- in weeks, we're going to start to do the tieback of the wells onto the platform and the commissioning. So this is starting as pretty much as we speak. So by the time we come on first oil, all these wells will be coming on ramp-up very quickly. We're talking about nine months, weeks. So we expect the ramp-up of production to the 440,000 being not very long at all. And we -- and each well has got a very high productivity. So it's not that we need a lot of wells. So I will foresee a very fast ramp-up in Johan Sverdrup.
Could I maybe ask for more specifics just in terms of with that be, say, six months, 12 months? How should I think about it?
Yes. I think we will -- we haven't guided specifically, but we will be guiding more specifically during the Capital Market Day and then the ramp-up or the production. But you're talking about few months, not more.
Okay, thank you very much.
And the next question comes from the line of Teodor Nilsen from SB1 Markets. Please go ahead.
Hey, good morning, and thanks for taking my questions. A couple of questions on Sverdrup, you highlight that you have a lower base in third quarter, which is impressive. Do you expect to report even lower OpEx per barrel after Sverdrup first oil? And second question on Sverdrup is related to the 660,000 barrels per day of plateau production in Phase 1. How is the chances for a debottlenecking and potentially increasing that capacity like we see you done at Edvard Grieg?
Yes. Thank you. And your first question, on the operating cost, we guided now openly that for the next 10 years, we will be guiding OpEx between 3.9 to 4.4. Of course, when Johan Sverdrup comes, particularly after commissioning, we'll be producing a very low operating cost. But I think, indeed, we'll stand for now for this guidance between 3.9 and 4.4 on the long term. I think that's a good guidance. When it comes to Johan Sverdrup and capacity, yes, you're right. You pointed out the 440,000 Phase 1 and 660,000 Phase 2. This is the capacity today. It's early days to say. We have no plan to debottleneck further. This is the capacity we're using. It is possible, like any other fields when you come into production that, as you have commissioning behind you, that you can actually optimize this. But it's early days to come up with any numbers or any firm statement on that part.
Okay. Just a clarification on the first question on OpEx, so do you expect Sverdrup OpEx to be comparable to Edvard Grieg or maybe slightly higher at all?
No, we haven't guided specifically on OpEx on Johan Sverdrup, but of course, high -- a very, very high productive wells, new facilities. So the OpEx on Johan Sverdrup will be on -- as I said, to be able to guide for a long-term 390,000 to 440,000 is because Johan Sverdrup is the majority of that. So we will expect low operating cost in Johan Sverdrup, yes.
Understood, thank you.
And the next question comes from the line of James Thompson with JP Morgan. Please go ahead.
Good morning, gentlemen. Thank you very much for taking my questions. Just firstly, you obviously outlined the six growth projects, particularly around Edvard Grieg. I was wondering if you could perhaps give us just some more color on how suitable Edvard Grieg facility is for Luno II and Rolvsnes? And are there some large-scale modification work that will need to be carried out? Just want to get a sense of how simple those tiebacks are likely to be. And then just -- I was wondering if -- secondly, separate question, if you could just remind me on the OpEx guidance 2018. Does that include the Brynhild reversal? And just beyond that, what's the sort of outlook for fourth quarter? Obviously, you're guiding to a high operating cost in the fourth quarter. I'm just wondering what the moving parts were there.
Yes. I'll take the first question. I'll let Teitur take your second questions. I mean, let's be clear, the tiebacks will happen. It's not -- there's not a question there. We are actually now in the process of approving all the modification on Edvard Grieg to be able to tie in Luno II and initially the extended well test on Rolvsnes. Those are not major modification, and they are, I would say, relatively straightforward. So it's a subsea tiebacks, and so this will happen. There's no question mark on it. And one of the forms sent back in May is that by the first quarter of next year, our Plan of Development of Luno II will be submitted for approval, and we are well underway now already to have all the approval for the modification of the platform. So it's nothing -- pretty straightforward, I would say.
Yes, good morning James, and and on your OpEx question of the guidance of below 380. That number does include the reversal of the Brynhild accrual. Probably, of course, we released that already in Q2 when our guidance was below $4 per barrel. So we have managed to optimize our operating cost somewhat particularly on Edvard Grieg, and that's what this led to this lower guidance today. And as you say, to get to 380, you need a slightly higher OpEx in the fourth quarter, and that's typically something we see. We see slightly higher operating costs in the fourth quarter with various year-end items coming through, and it's obviously difficult to know the exact phasing of that, but it obviously slips into '19 or not. But below 380 is what we are comfortable with guiding at the moment, and we have a reasonable margin within that number as well. So we're comfortable with that.
Okay. So is there any big sort of specific items in the fourth quarter?
Okay, thank you very much.
And the next question comes from the line of Johan Spetz from Pareto Securities. Please go ahead.
Thank you, and good morning guys. A quick follow-up on my end on the -- be it on Johan Sverdrup satellite opportunities that you see, in particular around Grieg there. Perhaps Luno II is the one where you have the most advanced work done thus far. Any indication you can provide on the potential CapEx involved with Luno II? Of course, it will be highly value-accretive for you, but just an indication there, perhaps.
Yes. We -- at this moment, we're not guiding on CapEx. So we're actually not even guiding on the additional production profile with Luno II, but we will. When it comes to -- because we're going to submit the Plan of Development, there, we'll include the production profile, the CapEx. So at the Capital Market Day, which is in a few months now, I think end of January, we will actually give you more clarity on the new guidance in terms of CapEx and production. And mind you also, for other projects such as Rolvsnes, which we're going to sanction the extended well test as early as next year, we also have Frosk, which will start an extended well test next year and there's more activity in Alta. So we will actually be more clear towards the Capital Market Day on this six potential new project and what does that mean in terms of CapEx and also potential production profiles.
And the next question comes from the line of Robin Haworth from Stifel. Please go ahead.
Good morning all, thank you. This might be something that I have to wait for the Capital Markets Day for, but just wondering if you could talk through how you're thinking about infill drilling on Edvard Grieg versus tying back new projects. Is it a question that your -- I can't imagine that you have -- you'd be able to put those tiebacks kind of on the shelf and bring them on when you need them. You will presumably have to spend the money sort of upfront and then you may find yourself with more well capacity than you need. Obviously, that's a good problem to have, but is that what you're going to be doing rather than delaying tiebacks if Edvard Grieg continues to outperform?
Yes. No, it's a good question. But I mean, first of all, we have to treat Luno II and Rolvsnes as different partnerships. So when they come back with a request of tieback, we have to actually give them a specific capacity in order for them to move forward and that has been done, of course. Now infill -- those tiebacks, so we have now a set date. You've seen from the presentation, we anticipated first oil on Luno II in 2021, and we're expecting also the extended well test on 2021. And in parallel, we also -- you're right, we also have the infill drilling campaign, which will be ongoing. But if you look at today, our production, we have plateau production until mid-2020. And from there, we anticipate -- we assume that the field will decline. Now infill drilling will come thereafter, but at the same time, we also have to assume a decline from Iver Aasen. So there will be enough capacity.
Let's assume we are extremely successful with the performance at Edvard Grieg, and Edvard Grieg continues to outperform. One thing we should keep in mind is that now between Luno II and Edvard Grieg, we are fully aligned with 65% and the partnership is the same. So should that happen, we'll have to take a view. But right now, we're planning that we can actually tieback and have the tiebacks as planned and also continue infill, and that fits with the current production profiles and assumption we made.
Okay, thanks very much. That's very clear.
[Operator Instructions] And the next question comes from the line of Gudmund Hartveit from Fearnley Securities. Please go ahead.
Yes. Thank you. Good morning, and thanks for taking my question. In light of the performance at Edvard Grieg and prolonging the expected plateau, I was wondering whether you can give any indications about potential additional reserve bookings as of year-end impact of that. And then on the topic of reserves, I would assume that Luno II will now -- or after then, that '18 will qualify for a reclassification from continued resources to reserves. But do you -- can you confirm that? And do you expect any of the other potential new projects that you list to potentially qualify as reserves already in 2018?
Yes. So in Edvard Grieg, I'm not expecting any increase in reserves this year. But of course, as we continue with the production and the outperformance, we may have revision later on. I think the key now in Edvard Grieg is really understanding the -- how water -- when the water comes, which hasn't come really. Once we have more of this data, we can update geological and reservoir model and that will allow us to be more specific. So I'm not expecting this year any update in reserves in Edvard Grieg. But yes, you're right, I mean, Luno II, Luno II, of course, as we soon we submit the Plan of Development, we will be able to move the contingent resources into reserves, that's definitely. But likely, they're going to -- since the PDO will be submitted and the approval will be in 2019, the booking of the reserves will be most likely 2019. In '18, I think the big story in terms of reserves booking comes from Johan Sverdrup. We had two row of increasing reserves in Johan Sverdrup and none of them have been booked into reserves so far. So this will happen obviously, of course, towards the year -- this year, reserve certification. The other one is, also, we've been quite successful in exploration and appraisal. So I'm also anticipating an impact on contingent resources.
Okay, thank you.
And the next question comes from the line of Mark Wilson from Jefferies. Please go ahead.
Hi, good morning gents. Just trying to explain to myself the market reaction today, and I think, I mean, tax rate may be one of them. So can you just speak to the effective tax rate in 3Q, Teitur? And what you would expect as the longer-term rate going forward? And then secondly, move us onto the growth side of things. The exploration campaigns and appraisal you've done this year, you would expect a similar sort of level of resource size to address over the longer term, would you say? I mean, the opportunities within Norway to explore in multiyear event, even though they may not be visible at the moment.
Yes. Okay, Mark, and yes, I can take the tax question first. So on the face of the P&L, the tax rate seems high at over 80%. But as usual, there are certain one-off items that are impacting that. This quarter, we had an FX loss of $11 million, which is non-tax deductible, so that pushes off that tax rate. And we also had some certain one-off items coming through in Norway, which impacted the tax rate in Norway somewhat. But fundamentally, in Norway, the operational rate we would expect from our Norway business should be 72% or 73% thereabout, and that's what we see and forecast going forward. I think what's also important to point out is that, at the moment, we are incurring tax charges on the P&L, which only relates to the corporation tax. We still have tax losses available for the special petroleum tax, which is the higher tax rate regime. And as we go into next year, we certainly don't anticipate to utilize those tax losses fully this year. But as we're going to next year, depending on oil prices and depending on where production levels come out, that we would expect to have fully utilized those special petroleum tax that proves to next year, not unless we have a complete collapse on oil price again, then perhaps we can defer those tax charges right out to the end of 2019. But I would expect on current oil prices that at some point during 2019, we will have fully utilized those tax losses. But fundamentally, the business operation, we should be running at around about 72% tax rate.
Good. I think your question is very much on -- in terms of exploration activity and a bit of color on how the future is going to look like for Lundin Petroleum. But first of all, this year, I think most of our activity in exploration are starting now. We drilled three wells where we have five ahead of us. One is ongoing. The second one will be starting very soon, too. So, a lot of new activities and news on the next few months until year-end. When it comes to next year, yes, we will be more specific at the Capital Market Day. But what I can say is that in the last two years, the company has been very active on that front, A, because there were a lot of opportunities in terms of doing deals with other companies and picking up acreage and then, of course, as always, on the upper rounds or the bidding rounds. So from the last two years and when we're going to release the new upper rounds in January, our acreage position in Norway will be almost double. It will be -- as increased significantly. And also just three years ago, we're active in three core areas, mainly it was Utsira High, the Aibel area and the Barents. And now we're active in six core areas. We've added the Norwegian Sea. We've added also the Mandal High. And so you're going to see next year a high level of activity, I think, both on appraisal and also explorations. And so I'm actually very pleased where we are and the position we've built ourselves. So I foresee a continuous high activity on that front.
Okay, thank you gents.
And as there are no further questions, I'll hand back to the speakers.
Thanks very much. We have got couple of questions from the web actually. I'll ask them. Amy Wong from UBS on exploration; five remaining wells in 2018, and they're in various areas. Can you talk about the drill time for each and when we should expect results from them?
Yes. I think as I just mentioned, still five is ongoing, and I'm expecting results towards early December. The Mandal High, we'll have the Oppdal well, which will be drilled in -- could start anytime soon. And we'll have the results also in December, early December. And then you will have the Frosk area, this is the Alvheim area, which -- there, we still have to be -- we still need to spud the well. So it will be, I would say, a lot towards year-end for when -- we'll be generic.
The next one is from Karl Fredrik from ABG. Exploration again and exploration spending in 2019, we're not guiding on it at the moment, but is there anything you can give on a direction of up or down? Is it going to be more than this year or less than this year?
I think, generally, we've -- this year's exploration is about $300 million. So I think that is a number that it's a fair number. Anything between $250 million, $300 million is fair numbers to bring forward. And I think that we -- that's kind of the number we've been playing with for the last few years, and I don't think that will be -- will fundamentally change. And remember, also, we still are in a market that it's favorable market in terms recontract. We're still using recontract at very low rates, so we are able to do more today than we did in the past for actually the same amount of money.
Al Stanton from RBC on tax liability again, Teitur, the current -- how is the current $49 million tax liability will be paid in Q4 2018? And any updated guidance on cash payments of 0% to 4% of EBITDA?
Yes. No, that tax level, they will not be paid in Q4 this year. It will be paid in 2019. So the way it works in Norway is that you provide the oil taxation obviously with the projection around about mid-year, which locks in an installment schedule, which we are now following. So we paid our first installment in August. And we'll pay two in Q4, one in October, one in December. And if you look at our cash flow statement, we have for the first nine months paid $5 million. So expect another $5 million in October and another $5 million in December. So that is the installment schedule we're following. And then we have a similar schedule for the first half next year. And then by mid next year, we will then update for the 2019 tax installments. But clearly, those installments, we're cutting at a lower oil price what we're currently seeing, which is why we're paying installments at a lower rate than what we are incurring on the P&L. So we have to settle the debt on that through 2019.
Right. We've got one from a private investor here on dividends. Are we planning to pay them annually, semiannually or quarterly?
Yes. I think we'll -- in terms of dividend policies, we -- towards the end, this is a decision we have to make for the board, and then we will come much more explicit on the dividend quantum, the dividend payments and quarterly versus yearly or semiannual. So that will come clear towards year-end or after we have defined or crystallized this policy with the board.
And the last question, which relates to last week's release and activities. Will Sudan affect us in any way going forward?
As a company, no, I mean, as a company, we will continue -- first of all, I mean, it's maybe an opportunity for me to say on Sudan. The -- we're absolutely convinced in terms of all these allegation and any wrongdoing that we don't believe of any of this accusation will be made at it through individual or company. Now this being said, all the news is out. People are well aware of the news. And from a company point of view, it doesn't affect the company and its ability to continue to grow and to perform as it's done in the past.
Great. Thanks very much.
Okay. Thank you very much.