Lundin Petroleum's (LNDNF) CEO Alexandre Schneiter on Q3 2017 Results - Earnings Call Transcript
Lundin Petroleum AB (OTCPK:LNDNF) Q3 2017 Earnings Conference Call November 1, 2017 3:00 AM ET
Alexandre Schneiter - CEO
Teitur Poulsen - CFO
Alex Budden - VP, Investor Relations and Communication
Niki Kouzmanov - Jefferies
Rafal Gutaj - Bank of America Merrill Lynch
Brendan Warn - BMO Capital Markets
Karl Pedersen - ABG
Teodor Nilsen Nelson - SB1 Markets
David Mirzai - Deutsche Bank
James Hosie - Barclays
Alwyn Thomas - Exane BNP Paribas
Robin Haworth - Stiefel
Duncan Milligan - Goldman Sachs
Good morning, everybody, and welcome to the webcast for the first nine months of Lundin Petroleum. My name is Alex Schneiter, I'm the CEO, and I'm joined in today by Teitur Poulsen, the CFO; and Alex Budden, our VP, Investor Relations and Communication. So, well let me move right away into -- I will give you an operation update and Teitur, later on, will give you the financial highlights.
So moving on to the first nine months of ' 17 and the highlights. As you've seen on the press release, a strong production for the first nine months, in excess of 87,000 barrels of oil equivalent per day. And in Q3, we had another record production, close to 90,000. As we mentioned, we have revised our guidance again, and we expect the full year at the top or exceeding the 85,000 barrels of oil per day guidance range. In terms of the operating cost, again, a very successful quarter and the first nine months. We've seen operating costs at $4.15 per barrel and the Q3 was standing at just below $4.3. We actually also revised our guidance in terms of the operating cost, and we expect now operating costs for the full year to be below US$4.6 per BOE.
This successful and very strong results obviously led by our two key assets Edvard Grieg and Alvheim, but Edvard Grieg particularly where we are the operators. We've seen, again, an outperformance on the facilities and on subsurface, and I'm expecting a significant increase in reserves by year-end in Edvard Grieg. Johan Sverdrup, our main development project, is also progressing very well. We are now in Phase 1 over 60% complete, and we are extremely on track to achieve first oil by end of 2019. We actually have seen now evidence on the ground of the progress of this project where we installed the jacket offshore and the first jacket and the drilling platform was assembled and sitting in Norway.
We've seen also cost going down not only in Phase 1 with a reduction now down to NOK92 billion, and what we've seen also overall Phase 2 cost reduction, which were already outlined in the previous webcast. In terms of growth, currently, we're drilling two wells on trend with the Filicudi discovery in the southern Barents Sea where we'll see the results by yearend. And we're also very active on the appraisal side. When I mention appraisal, I think about Alta/Rolvsnes, which is close to Edvard Grieg and Luno II, and the plants are being progressed and in 2018, we're going to be very busy busy also there. We've also been busy building new exploration area or core areas at the Utsira High in the southern Barents Sea, but we've also started to look at other areas such as the Mandal High and the Froya High. So you're going to see Lundin Petroleum very active in '18 on the exploration front. So very pleased with the results overall.
This is really a graph that I like very much, and it really shows, over the years, how the company has increasing production and tremendous growth where we more than doubled our production since '15 and also the trend of the low operating cost. That graph will continue. We know that when -- the onset of first oil be in the '19, the production will increase again, and we would almost double again by the time Phase 2 comes on stream in 2022. And you've also seen that we've been performing. If you look at the yellow range, this is our guidance, and you've seen that the last two years, we've been always at or above the guidance range. So very good performance from our team in general.
In terms of production, I already said a few key items. Here you see our production and performance from Q1, Q2 and Q3, which was at the top end of our guided range. Production, as I mentioned for Q3, is 89,000 barrels of oil per day, and this is really very much led by the performance on the reservoir and facilities, both on Alvheim and Edvard Grieg, but particularly in Edvard Grieg, which is our main operating asset. And you see on the right hand side of this slide, the production efficiency standing at 92% for Edvard Grieg and a record 97% on the Alvheim area. So production-wise, very, very pleased with the performance.
Let me say a few words about our two key assets, producing asset Edvard Grieg and Alvheim. Starting with Edvard Grieg. The main activity really in Edvard Grieg is the continued drilling activities. We have now seven producing wells on stream, three water injection. And based on this latest drilling, really our performance has been better than expected, and we see really good results from the drilling, both on water injection and production.
We have in total 14 wells to be drilled from our jack-up rig, and we're currently drilling a fourth water injection, and we'll be drilling three further wells in 2018. And that will be the end of the plan of development drilling activity. But of course, we would be looking also at further opportunities, infill drilling opportunity in Edvard Grieg, particularly with the forecast of increased reserves. As I mentioned before today, proven plus probable reserves stand at 223 million barrels of oil, and we expect a significant increase by year end on this number. And the operating cost in Edvard Grieg standing at just below USD $4.7 per BOE.
This is, again, as I mentioned to you, the reservoir performance has been very good in the Edvard Grieg, both in their ability to inject water and maintain pressure and also in the productivity of the wells. We've drilled early on our first appraisal well, which was very successful, and we guided the market between 10 to 30 gross resources upside. That still stands. But also what we see is that with the latest drilling, we see also more potential around the Edvard Grieg in general, and we're currently finalizing all the modeling on the subsurface. And when this work is completed, we will be announcing the new reserves.
We also seen great results over the Tellus area, which is the area to the Northeast. That well was very interesting, which also penetrated our fractured basement area which is producing, and this is very good for the raw business activity and the appraisal activity, which we will see in 2018. We also see the depletion rate being more favorable than anticipated. And as I mentioned, all this will be updated in our model. So overall, very pleased with the subsurface in Edvard Grieg, and I see this continuing over the years.
Alvheim has been also a very good asset, producing very well, Aker BP-operated, doing a tremendous job. The key in Alvheim really is the infill drilling, is the ability. Now it's a very matured field, the ability to find new infill candidates, and that has been done very successful, both in Alvheim and Volund, and that has led to the performance we see in production, which was above expectation, and also very low operating cost.
But let me move now to Johan Sverdrup, our major development project. You've heard a lot of the news from Statoil. I think if one can summarize, Phase 1 is really -- we are on target to achieve first oil by end of '19. We see continuing cost reduction on Phase 1 with the latest release of NOK 92 billion for Phase 1. And the ongoing project, both in on the drilling and the execution, the project is going really well. So very pleased. I was actually myself in South Korea a few weeks ago and could see from my own eyes and was very impressed with the work that has been achieved to date. Few activities. We really now start to see the real thing on the ground. We've actually installed the first jacket, the riser platform jacket you see on the picture of this slide. And we actually assembled also the platform, the drilling platform, which you see on the right hand side, which is now sitting in Norway. By summer of next year, we will install all the jackets, and we will have installed two modules. So we are well on the way to achieve the first oil by end of '19. In actual fact, in some of the areas, we are ahead of schedule. So very [indiscernible]. Phase 2. We are -- now we have selected a concept, and we anticipate to submit the PDO in the second half of 2018 with first oil in 2022. You've seen this is not new news, but you've seen cost reduced by 50% from the original plan of development, and we've seen now full field breakeven oil price of below $25 per barrel, so exceptional cost. The picture you see on this slide is really what the full field development will look like.
But let me move on to the appraisal. As I stated to you, we have the producing assets development, but we're also very active on the appraisal front. We see significant upside on the field areas. When I say significant upside, I'm thinking about the Alta/Gohta area, where we've done an active drilling -- appraisal drilling in '17, which is completed, and we're now looking at the option for '18, which may include that extended well test. In Rolvsnes appraisal, we're going to see this happening in '18. This is very close to the Edvard Grieg platform. It's a basement high with a lot of potential. And as I stated, we already tested a well, we've tested oil, one of the -- if not the first basement that tested oil in Norway. But we've seen also now in Edvard Grieg, we tested the basement successfully. So I'm really excited about this play, which is just next door to our existing facility. And then Luno II appraisal drilling will continue in '18, and we will see the results. But all that will lead to a potential, quite significant increase from the 2P of over 700, which could again lead to well close to 1 billion. So a lot of activity in '18 on that front. Exploration, very alive. As I say all the time, Lundin Petroleum is active and main strategy is the organic growth. We're very active in the souther Barents Sea, but you're going to see Lundin Petroleum very active next year, both on the southern Barents Sea, on the Utsira High, but also towards the Norwegian Sea and further down, we're now developing a new area called the Mandal area, where you're can to see Lundin also very active.
So in the last two years, very active building up of a very exciting portfolio, and I expect we're not going to release an exact number now. But I expect in 2018, over 10 wells of exploration appraisal, that includes operated and non-operated, but they're very active time. And as we speak today, we're drilling two wells in the southern Barents Sea, results still to come, and those wells are drilled on the on-trend with the Filicudi discovery.
This is a snapshot in the southern Barents Sea, where in addition to the key areas and core area, we see three impact exploration trends. We showed you that before. One is the -- what we call the Southeastern Trend with Korpfjell, but also Signalhorn, and still a lot to do there, big area, just those two major structures only, there's 100s of kilometers in between. And we see the Loppa High, where we have the Alta discovery, Gohta, the Neiden discovery and further activity you will see in '18 and onwards. And then the Filicudi or the Johan Castberg trend where we have the Filicudi discovery and where we're drilling today the Hufsa prospect, which you see on the slide and later on the Hurri prospect. So on the exploration side, really my message still very active and you will continue to see the company very active in the years to come.
With this, I will leave the ground to Teitur Poulsen, our CFO, and later on, we will -- can answer all your questions. Thank you.
Thank you, Alex, and good morning, everyone. So it's very pleasing yet again to have a very good quarterly performance on the financial side when you have your two key assets continuously performing above expectations at the same time as having your main development project continuously seeing falling costs. That combination makes for excellent financial performance for the company.
So the key highlights for the first 9 months and the third quarter, you see on this slide. Production, as Alex said, 89,200 barrels oil equivalent per day. That is just shy of 5% ahead of our midpoint guidance. So excellent performance there, both from Edvard Grieg and outline. The first 9 months, 87,100 boe per day. The macro environment is continuing to improve for us. We saw average Brent oil price in the third quarter just over $52 per barrel, and that's pretty much the same number for the 9 months average of $51.90.
Our cash operating costs are continuing to trend very nicely, very, very low indeed. I think we are ahead of the pack on this metric in terms North Sea producers, $4.30 cash operating cost for the third quarter and even lower at $4.15 for the first 9 months, and this despite a strengthening knock through the year which should otherwise lead to a higher dollar cost for us. EBITDA and operating cash flow for the quarter are both record setting numbers for us, just over $380 million on EBITDA, $1.07 billion for 9 months and just below $390 million operating cash flow, $1.1 billion for the 9 months. Net results, $227 million for the quarter, somewhat driven by non-cash FX gains, which we will come back to, and $432 million for the first 9 months, [indiscernible] to earnings per share from continuing operations of $1.28 per share.
The operating cash flow and comparisons to the same periods in 2016. You see here for the first 9 months, it's effectively a doubling on operating cash flow up to $1.1 billion. As I said, the first 9 months last year was also positively impacted by $64 million current tax credits from the E&A spend we incurred last year. This year, we do not have any current tax credits to help our operating cash flow performance.
And for the third quarter, we are up 60%, as I said $390 million. Also in the third quarter last year, we had a current tax credit of $22 million. So flattering the 2016 number somewhat. You see production increase here on nine months this year versus last year, 58% up. Brent prices 24% up. Our achieved sales prices are up 27% on the nine months this year on 2016. So very strong cash generation from the company, as usual.
EBITDA, a pretty similar story really, more than doubling EBITDA on the nine months this year versus last year. That's also helped by the fact that the production mix is now more heavily weighted on Edvard Grieg and Alvheim versus last year, and both Edvard Grieg and Alvheim barrels are very high margin barrels. So that improves our relative EBITDA performance even more compared to last year. So of that is 125% on the nine months and 78% up on quarter-on-quarter, $382 million EBITDA generation in the quarter.
Net results, as I said, somewhat boosted by FX gains -- non-cash FX gains. Net results after tax $431 million for the nine months, that's up 64%. We also recorded healthy FX gains in the first -- for the first nine months in '16, but relative to two periods, our FX gains are $75 million more in nine months 2017 versus 2016. But even stripping out the FX gains, the company has generated very good net profits from the main operations. During the third quarter, we preannounced an FX gain of $185 million non-cash in the quarter. So that led to a $227 net profit for the quarter, which is up 34% on the same quarter last year.
So looking just at the face of the income statement and what the line items look like. We are stripping out of these numbers the third-party crude -- marketing and sales we are doing on behalf of other people, roughly $188 million of revenue and cost of sales, therefore taking out of both the revenue number and the operating cost number. So excluding the marketing business, we generated $1.2 billion of revenue for the first nine months and had cash operating -- operating costs, should I say, of $121 million, giving us a cash margin of just below $1.1 billion for the nine months. So as I said, very cash generative nine months for us.
Depletion rate is still running around about $18 a barrel, so no change there really. It's just a function of what we produce, $430 million depletion charge in the period. Exploration costs were preannounced, $42 million expensed versus a spend of $171 million during the nine months. And impairment costs, which are relating to the Brynhild assets, totaling $31 million pre-tax, and that gives us a gross results of just below $600 million for the nine months. G&A is pretty much trending as we expected, $25 million for the nine months.
Financial items, obviously, heavily impacted by the FX gains. The knock over the nine months has strengthened by roughly 8% relative to the dollar, which then released a non-cash gain of $325 million. The net financial items are positive of $192. Taxes all deferred to $330 million for the nine months, giving us a net profit of $432 million from our continuing operations.
The net back calculations is a slide we always show. You see the average Brent for the third quarter is just over $52 per barrel. We had very good realized sale prices in the quarter of $51.60, so just $0.50 a barrel discount to Brent. That was also helped by favorable timing of some of the cargo liftings we had in the quarter. We sold 11 Edvard Grieg cargos and two Alvheim cargos. But we're also seeing a general improvement in the Edvard Grieg or the Grane blend, which Edvard Grieg is part of, and that blend has recently been trading at a lower discount to Brent than it historically has been doing. So that's also helping these numbers. So $51.60 realized price in the third quarter and $49.70 for the nine months.
You see the cost of operations and the tariff transportation costs. There's no major changes here really. They're all trending at a very low level indeed. And as we said, $4.27 all-in cash cost for third quarter and $4.15 for the first nine months. Other costs is mainly made up of insurance costs, which we pay upfront, and then these turn out to be non-cash as we amortize that through the period, only $0.22 a barrel. So giving us a cash margin of $47 for the third quarter and $45 for the nine months.
Cash taxes, we will come back to. They're essentially zero, so the operating cash flow is the same. And our G&A costs are still trending at a low level of below a dollar of barrel, giving us an EBITDA for the third quarter of $46 per barrel from a $52 Brent or $44.30 for the first nine months.
Exploration and impairment costs. These have all been preannounced to the market, so no major news here, $42 million pre-tax charge for the first nine months. Most of that happens in Norway. So we get the 78% credit against that in tax. So post-tax $10 million of exploration costs. Impairment costs all relate to Brynhild. We took an impairment charge of $13 million in Q2 and another $6 million or $17 million in Q3, giving us a total impairment of $30 million for the first nine months, $7 million post-tax. And as previously announced, we have sold 39% of Brynhild to CapeOmega. We expect that deal to complete this quarter and upon completion, we will incur a loss on sale of another $16 million post tax. This has got to do with the book value of the tax balances we have on the balance sheet, which are higher than what we sell these tax balances for since these tax balances are discounted in an M&A deal.
G&A net financial items. As I said, G&A is trending pretty much as we expect, so nothing to report there, $8 million for the quarter, $25 million for the first nine months. You see here the impact from the foreign exchange gain on net financial items, $325 million for the first nine months, which includes a cash loss of $3 million on our FX hedges. Well, actually in the third quarter this year, we actually recorded a $3.3 million gain on our cash-settled hedges. So that $3 million gain is embedded in that $185.9 million for the third quarter. Interest expenses for the nine months, $88 million. We have capitalized on additional $44 million. So all-in cash interest rate cost for the nine months just over $130 million. And various other line items here which are pretty normal as per our guidance, giving us $192 million of net financial gain for the nine months. Tax charges, as I said, is all deferred. We had an effective tax rate on the face of the income statement of 33% in the quarter. That's obviously heavily impacted by the FX gain, which is non-taxable. And if we adjust for that, our operational tax rate, if you like, is close to 72%, which is roughly where you would expect it to be given that all our production is in Norway. And for the first nine months, 43% tax -- effective tax rate on the income statement and again if adjusted for FX gains, that is around about 73%, 74% for the first nine months.
The net debt position for the company. As I said, the company is very cash generative, even in the $52 oil price environment. So when you read this from left to right, you can see that our net debt has actually reduced over the nine months. We entered the year at just below $4.1 billion of net debt. And as I said, we generated cash -- operating cash flow of just below $1.1 billion. Our development and exploration and appraisal spend has amounted to just over $900 million so far this year and our cash G&A in financial cost at $20 million and $158 million, respectively. And we are also benefiting from a positive working capital movement on net debt, mainly relating to the fact that we've been overlifted over these nine months of $55 million working capital contribution, giving us end September net debt number of $4.02 billion. So that is definitely trending down and by year-end, we do expect to be below $4 billion in net debt. The liquidity position of the company remains extremely solid indeed. This slide hasn't really changed through the year as our debt number has been pretty flat. So we continue to have around about $1 billion of available liquidity headroom. As you know, we have an RBL facility in place of $5 billion and that RBL doesn't start to amortize until end 2020, so a year after John Sverdrup will come into production. So the company's liquidity position is extremely healthy indeed and that gives us obviously lots of flexibility as well in terms of organic and inorganic growth opportunities.
We are updating the guidance. As you've seen in the report, we're now guiding production for the full year to be at or above 85,000 barrels oil equivalent per day. We are also guiding our cash operating cost, which is the flip side in a way to the production number to be below $4.60 despite the NOK strengthening somewhat. And we're also reducing full year CapEx guidance by roughly 10% down to $980 million, whilst E&A expenditure guidance remains unchanged.
Just a quick update on hedges. We had certain hedges outstanding as of end of the reporting period, end of September. As you can see here, $6 billion worth of NOK buying for an average rate of NOK 8.27 per dollar. And in these quarters or after the periods end, we have entered into further hedging on NOK, NOK 2.25 billion, both at an average rate of NOK 7.65, and that is to cover some of our NOK exposure for Phase 2 of John Sverdrup through the years 2020 to 2022.
And similarly, on interest rate swaps, we have the notional borrowings of $3 billion up to end 2018 at an average fixed LIBOR rate of 1.65%. And in subsequent events, we have entered into further interest rate swaps, $1.75 billion in 2020 and $1 billion for '21 and '22. This is done on weighted average of 2.15% fixed LIBOR.
So with that I'll hand back to Alex, who will give some concluding remarks. Thank you.
Thank you, Teitur. So let me move on to the summary, we can then move to the questions. But as we stated, record first 9 months with production at 87,000 barrels of oil equivalent per day. And as we mentioned, we expect to meet the top or exceeding the top of the range at 85,000 or higher than 85,000. And you also heard from Teitur, the record low first 9 months in terms of operating cost standing at quite an incredible USD 4.15 per BOE. And we expect the full year operating cost below guidance and below USD 4.6, which was the latest number we gave you at the last webcast. As I mentioned, very pleased with Edvard Grieg, our main field, outperforming both on subsurface and above-surface on the top side, and as I stated, we expect significant increase in reserves that will come to fruition towards mid-January of next year. Johan Sverdrup, right on track, and we're definitely on the right track to achieve first oil by end of 2019. Beyond that, on the appraisal, hope we show you that we're still very active. We got plan for Alta/Gohta, for Luno II and Rolvsnes. All those will be active in 2018.
And the exploration drilling, as we speak, drilling two further wells, on trend with the Filicudi discovery and in '18, still very busy with an excess of 10 wells exploration appraisal already in the plan and something we're finalizing will be more specific towards the Capital Market Day. And meanwhile, we've also been building new core areas such as the Mandal High and the Froya High. So we've been very -- is going to be very active in the years to come. And of course, as always, strong HSE track record. That's also a very important part of the business, and I have to say the team in Norway has done a fantastic job there.
So with that, I think we open it for questions.
Thank you very much, Alex and Teitur. And if we could just hear from the operator whether we have any telephone questions coming through?
[Operator Instructions] Our first question comes from Niki Kouzmanov from Jefferies. Please go ahead. Your line is open.
I have a couple of questions. I'm sure others will ask similar ones, but if we talk about the Norwegian portfolio and restructuring that, not just in terms of asset quality, but also, let's say, in terms of cash flow, you currently have some on the balance sheet, obviously, but positioning for the time when John Sverdrup comes on stream eats through them. We've seen your peer, Aker BP, already making moves on that front. Just wondering what your thoughts are there. And then in terms of the additional hedging on the FX, $300 million or thereabout. Phase 2, you mentioned tighter. But if I assume -- if I gross this up and assume 50% hedging on the exposure, I get about NOK20 billion. Is that where you're seeing cost come down to or shall I not read too much into it at this stage? And finally, just in terms of exploration for next year, you're going back to the Foyar High, to the Mandal High. You've been there before, probably not as successful as you would have expected. What have you learned that now makes the strategy different? Thank you.
Yes. Good morning, Niki. No, I don't think you should read too much into those levels of NOK hedges we've entered into for 2020 to 2022. Obviously, we haven't got full clarity on the exact currency split for Phase 2 as yet because we haven't really awarded any material contracts for Phase II. But we know to history that there will certainly be some NOK exposure on Phase 2, and we just decided to move early and make sure we lock in some of the NOK which we think, in the long run may, strengthen from current levels. But I don't think you can infer any CapEx guidance number on Phase 2 from what we've done on hedges.
I think your first question was related to M&A in general. As I stated before, I mean, main strategy of Lundin Petroleum is organic growth and provided we can continue to show ability to find new barrels, that's where we believe we'll create a lot of value to shareholders. Now this being said, we are turning every stone and looking at every option out there and yes, our competitors have been -- some of them have been quite active and done very well, and perhaps that's more on the mature side of the fields, and we're looking and if the right opportunity comes for us, definitely we will be acting on that front.
And as Teitur showed, we have ample liquidity to achieve just that. Now when it comes to exploration, yes, we've been there before when you mentioned the Mandal High and the Froya High, and obviously also Utsira and southern Barents Sea, and along the way, when you drill wells and you acquire more seismic, you earn a lot. And of course, we now -- this next move in the Mandal High and Froya High is based on the latest data we've seen, the latest work we've seen, and we're quite excited about the prospectivity there. So in essence now, you'll see Lundin Petroleum, the key core areas, which we know, the Utsira High and southern Barents Sea, but you're obviously seeing us now building up new areas, and this will come to -- become more and more active in the years to come for sure.
Next question comes from the line of Rafal Gutaj from Bank of America Merrill Lynch. Please go ahead. Your line is open.
I've got two questions, please. The first one on Edvard Grieg. And just looking at the production efficiency number there, which was 92%, suggesting that the weakness and uptime here was towards the end of the third quarter. I wondered if you could give some color why the power issues had a disproportionate impact in September? And can you comment on 4Q production so far? And then secondly, I recall $60 has always been the threshold, we're talking about a dip-end, before the start of John Sverdrup, first set of results in nine quarters and were there. I wondered how thinking has progressed and whether 70% completion on Phase 1 at Sverdrup at year-end is enough buffer to bring that discussion back to the table? Thank you.
Yes. Okay. 92% you're mentioning on the third quarter, we had some issue with power generation. I would say those issues now have been really well on the way to be resolved. It hasn't really had such a negative impact on our production as you've seen in the third quarter, nothing going into fourth quarter. I don't foresee major issue whatsoever. And as I said, they were some issues, but those are well on the way to be resolved or being resolved. So not really a concern there. In terms of the dividend, yes, good memory. I stated all along that we would pay dividend at first oil of Johan Sverdrup and if the oil price reaches $60, we will think about paying dividend beforehand then, but I also mentioned that it should be $60 and sustainable. But of course, now is beginning, the market is improving and I'm personally quite optimistic on the oil price going forward. So it is definitely something that is on the table, and it's definitely something we will be looking very seriously to potentially pay dividend before Johan Sverdrup first oil.
And next question comes from Brendan Warn from BMO Capital Markets. Please go ahead. Your line is now open.
Just two questions. I guess first question relates to costs, just whether you're seeing any inflationary signals in this, call it, more sustainable oil price environment in Norwegian Continental Shelf and just what you believe is actually achievable in terms of getting below, say, $4 a barrel across the group? And then I guess second question just in relating to Alta, I want to just ask two questions, the asset quality. I'm just wondering what you need to see from the possible AWT next year? But could you just talk through in terms of your analysis of Alta, what expected sort of costs are? I just worry about, you've got such a good portfolio that you're, call it, keeping this asset to grade your overall portfolio.
Okay. So first question on inflation. Really, the straight answer will be today, right now, we don't see really impact on inflation because the improvement in the market. I'm think about also kind of the drilling side or the seismic side, there are still ample opportunities there, and we still see the same cost we've seen for awhile. In terms of execution in project, obviously, I always stated John Sverdrup is in a perfect storm, and we continue to see downtrend, but of course with the market and the oil price increasing, you may see some inflation coming. And I think what is important, and that's what we've been doing, is that try to be ahead of the game. An example I give you only one is on the drilling side, we've actually contracted two rigs at the very attractive rates, and we have options. So we will be able to use those options and those rigs simply for '18 and beyond '18. So it's positioning itself in utilizing this market before inflation kicks in. Alta, we've been obviously busy with the appraisal. We're currently doing a lot of work in terms of the subsurface. The challenge with Alta is that it's a limestone play and as such, it's not as easy as sandstone play in terms of particularly productivity and extensive -- how extensive it is across this whole structure. So a long-term production test is exactly to try to reduce that risk and understanding the productivity and connection between the different rocks. But the results we've seen so far are very encouraging. So I think I will leave it to that because we're still doing a lot of work, and we will be very much more specific at the Capital Market Day with the results of all our geological model and the way forward. But of course, we will move forward with Alta as it's obviously a strong project and its economic. But so far the results are encouraging.
And the next question is from Karl Pedersen from ABG. Please go ahead your line is open.
I was wondering if you could elaborate somewhat on or quantify what do you see as a significant resource potential on that Edvard Grieg? Will that be the 30 that you have quantified already on the appraisal where you said a half of the current risks are sized just to get the kind of a scope on it? And also looking at M&A, would you be -- do you have kind of a list of what would be an ideal target for you if you were to do transactions?
Edvard Grieg, in terms of the potential, of course, we already guided the market previously with the successful appraisal well we drilled, which we say gave a range between 10 million to 30 million barrels of oil equivalent, and since then, we've drilled new developing wells. We're also seeing the production and pressure depletion, and so we have now taken into account all this and put all that in a model, which is ongoing, and will be closed to be finalized. And obviously, I would say, overall -- I'm going to give a specific number, but overall, we are very pleased with the results, and I think the appraisal well is one part of the puzzle and the other development wells we drilled, and also the performance in production and what we see in terms of depletion and pressure is also positive. So all that now has been put together and hence in my statement, I say significant. What significant is? I think for now, I'll leave it, let it be ambiguous as something will become much clearer when we provide the reserves upgrade in January. And mind you, it's not just Edvard Grieg, it's also other assets such as Ivan Aasen and Johan Sverdrup. So on that point, in general, I'm optimistic of what I see. On your question M&A, well, I'm not going to give you a list, that I'll keep it close to my chest. But, of course, again, we're looking -- it's always been opportunistic in Lundin Petroleum, the M&A. A good example is what we did with Edvard Grieg and 15% of Statoil, which today, I'm very pleased, and I think it's been an excellent deal for both parties. If we see other deals like these that are close to our infrastructure or areas of focus, but it could be also beyond, but it has to be the right opportunity, and if it takes a little bit more time, it would take more time, but let's be clear, we are turning every stone and we're looking at every option we have in our way.
May be I can add on the M&A. W e have these tax pools in Norway of $2.6 billion, $2.7 billion at the moment, and because of that, we are not paying any taxes at the moment. But obviously, the idea is always to try to accelerate the usage of those tax losses. But clearly as the closer and closer we get to Johan Sverdrup first oil, the time value of money of that tax pools gets eroded all the time.
So the evaluation uplift by doing the deal now is actually quite small given that we will be starting to pay cash taxes once Johan Sverdrup starts off in 2020. So that-- the time value of money argument on the tax pool is less effective now than it was last year or even in to 2015. So it has to be the quality of the asset that's going to drive any deal we do.
Next question is from the line of Teodor Nilsen Nelson from SB1 Markets. Please go ahead.
Two questions, if I may. The first one is a follow-up on Edvard Grieg, obviously and pretty impressive performance and also development there. But when should we start to see a natural decline given the current working program? And then second question, on the slide [indiscernible] hours ahead of schedule. How would that impact first oil? Thank you.
Okay. Edvard Grieg, of course, you're asking decline. I think we will be more specific at the Capital Market Day. But of course, by increasing your reserves, one of the obvious things is that you extend your plateau production. The regional plateau production in Edvard Grieg was two years and this will definitely be extended. But we will be more specific once we have the reserves and all the updated models. But I think we're definitely going to be -- you shouldn't anticipate an extension of the plateau production in Edvard Grieg. Your second question was, I forgot now was -- Johan Sverdrup first oil, yes. No, it's a good question. I think there is one thing we have to realize is that Johan Sverdrup completion and execution is very much driven by the seasons, that is you install your jackets and your modules during the summer seasons. So next year, next summer, we're going to install four jackets to all the jacket of Phase 1 of Johan Sverdru, and we're going to install two modules. And then in the following year, following summer year, that we're going to install the last two modules. So that tells you that even if you do extremely well, your fourth quarter end of '19 is pretty much set on stone. Now, of course, if you're ahead of the game, that means that everything that goes offshore is extremely well prepared and the likely of an extension to that date because of additional growth in offshore man-hours, it's unlikely. So if anything, that is making the project in first oil more robust than ever.
Next question is from David Mirzai from Deutsche Bank. Please go ahead.
Just a couple questions on exploration. Just, first, could you clarify what you see is the key risks on the Hurri and Hufsa? And then just following on from there, there was a lot of potential and hopefully expectations of the drilling programs, not just of yourselves, but of some of the other Norwegian players. And by and large, the market has been somewhat disappointed. Now leaving aside the frontier wells, there's also been a number of wells [indiscernible] and close to existing areas where you would expect maybe greater knowledge, higher chance of success, such as the Volund West, for example, or Borselv. Can you give us an idea of where you think the industry has kind of the overreached itself the last couple year, and what the industry is doing to kind of improve its chance of success going forward? Is it about seismic, is it about getting the wells drilled or is it simply about not drilling such risky prospects? Thanks.
All right. Your second question is quite a large one. The first one, Hurri and Hufsa risk. I think Hufsa and Hurri obviously on trend with Filicudi, which is a discovery. So with Filicudi with proven reservoir, caprock, petroleum system, and those two will be drilled just next to it. So you have all the ingredients and you have nothing to prove. I see the largest risk on those two Hufsa and Hurri is probably the trapping, if that is there and present, but I see less risk when it comes to the petroleum system and the reservoir. So that's probably the major risk. But taking to account that we are next to Filicudi, so most of the ingredients have been proven. Now to your big question.
In general, yes, 2017 hasn't been a successful year, in general. In the southern Barents Sea and perhaps in some other areas, the activity have been low, first of all. On the southern Barents Sea also, we said we're touching the top of the iceberg or the tip of the iceberg. And despite some of the setbacks, mind you there's still two wells ongoing, so it's early days. I think the industry is doing a job and if you look at the chance of success in Norway, it' actually quite high compared to other areas. And I think the seismic, for instance, still will lead to new technology and the ability to see better the subsurface. But it's not just that, it's also the ability of your people to find new play. I think the game definitely is not over.
I think the exploration game is a long game and you have to be patient, and I think one year doesn't give you the right picture. And what is important in my view is that you have to continue to fund assets of new opportunities and you have to continue to be active. And I -- you mentioned all the areas such as the Volund, that was a relatively small play and one well. So I think the important thing in the NCS is that there are still plenty of opportunities. And in general, if you compare to the U.K. side, Norway is really under explore. So certainly as Lundin, we see plenty of opportunities and one of our emphasis is obviously on acquiring very, very high-tech 3D seismic, such as what we call the top sides, which hopefully have an early breakthrough and will allow us to see new things. So overall, I think we're on track, it's a matter of volumes and activity also from all the players.
Just a quick question for Teitur. Can you just confirm that you're selling the OMV and Wintershall volumes from Edvard Grieg, and just give us an idea of how your trading team is improving this learning ahead of the Johan Sverdrup volumes coming on stream? Thanks.
No, we are not trading those volumes at the moment, but we are keen to get as much volume as we can from the Grane Blend, of course, because the more control we have of the Grane Blend, the better we can -- the higher the non-price we can achieve, which is effectively reflecting what our revenues are. I think the team's doing really well. We have a trading -- marketing department, it's not trading its marketing, in Geneva of two guys running our operations there. And as I say, they are keen to get more volume, but so far they have been doing a great job, and we have seen the general Grane Blend discount narrowing to Brent over the recent years. So it's a good trend at the moment.
And next question is from the line of James Hosie from Barclays. Please go ahead. Your line is open.
A couple of questions from me. Firstly, on 2018 production of Det Norske, should we use Q4 kind of production of at least over 80,000 barrels a day as a guide of where you want to keep production through the next year? I mean, on Alta, what needs to happen for this possible extended well to actually become a firm commitment in 2018? Is it just a case of getting partner approvals?
Okay. 2018 production, as you know, we become more specific in the Capital Market Day. And using Q4, I won't say this is the way to do it, but I think in general, we're really in the middle of doing all the work and also that includes the Edvard Grieg operating model. So it's too early to come up with a specific number at this point. On the Alta, what needs to happen, we're currently finalizing all the work on the appraisal that we did conduct this year. And of course, that includes also the partners. We have to inform the partners. So we're finalizing all this as we speak. And so again, definitely when we come to the Capital Market Day, we will have the -- we will be far more specific and hence, the reason that today, we're not specific sayomg we're going to go ahead with the extended well test because there are still few milestones to be achieved, partners and the subsurface work to be completed.
Okay. And just going back in the production points. So you effectively confirm that Edvard Grieg's will to a plateau through next year. Are you anticipating the claims in the rest of the portfolio?
Now, we have really two assets, Alvheim and Edvard Grieg. As I said, Edvard Grieg, we're expecting extended plateau, but of course, Edvard Grieg, also we have to take into account the Ivar Aasen portion of the production. On Alvheim, Alvheim is a mature field. Alvheim is declining, but of course, we're trying to halt the decline as much as possible by doing our infill activities, both in Alvheim and in Volund. But that will become much more clear at the Capital Market Day.
And the next question is from the line of Alwyn Thomas from Exane BNP Paribas. Please go ahead. Your line is open.
Quick question, just following up on the exploration strategy. As part of moving to further south in the Mandal High and Froya high, is that influenced by lack of commercial volumes discovered in the Barents in general through 2016 and 2017? And if I may, just a follow-up on the capacity sharing with Ivar Aasen given the upgrade, should we expect too much impacts going into 2018? I know it's probably a different way of talking about the production guidance, but perhaps, if you can give a bit more color there, that will be helpful. Thank you.
Yes. No, your first question, not at all, the move to the Mandal has no relevance to the southern Barents Sea or other areas. In actual fact, both the southern Barents Sea, Utsira High, the Mandal, Froya, these are all areas that we're very excited and earlier, we were doing a lot of work. It's just a normal processes as you move forward and through the upper regime. You're trying to acquire more and more licenses and you do more and more work and you build up new areas. We started with Utsira High very successfully, moved to the Loppa High in the southern Barents Sea and now we're also putting our eyes in other areas such as the Froya and the Mandal. And of course, as I mentioned before, we're doing a lot of work and you see new models, new things. So in general, very, very optimistic about the exploration potential in Norway in general. And as I stated, it is difficult for me to give the exact number, wells we'll be drilling next year, because there's still work ongoing, but I stated that we will be drilling in excess of 10 wells, and '18 will be again a very active year for Lundin Petroleum on that front. Your second question, Ivar Aasen guidance. Again, I think it is difficult for me to be more specific than I've been because we still -- there's still quite a bit of work ongoing. But the two element is going to be Edvard Grieng and Alvheim. Alvheim, the field we mentiond, it's infill drilling ongoing, which will have an impact on the production. But overall, Alvheim is a field that is on t decline. Then Edvard Grieg, increased reserves. We anticipate an extend plateau and that's compounded also obviously with the volumes we have to -- the capacity we have to make available for Ivar Aasen. But again, all that will become much clearer in -- on the Capital Market Day, we will be very specific. But obviously, Edvard Grieg is helping a lot right now.
And next question is from the line of Robin Haworth from Stiefel. Please go ahead your line is open.
A couple of questions, if I may. So just on the development drilling at Edvard Grieg and you mentioned PDO drilling program will conclude in '18. I was just wondering given the decent production performance, if you see scope for additional drilling into '19 or if that's -- you can call a halt for it for a little while? And perhaps also if you could talk about the what's going on with Grane Blend, and if you could talk through the dynamics of that, that would be very helpful? For instance, at what proportion of that crude stream is coming from Grieg at this point and is it just -- is the improvement in realization just a function of higher crude quality versus what was going into that blend previously?
I will take the first question and then let Teitur perhaps take the second question. But the first one is a good question. We drilled 10 wells now, seven producers intra-injection, and we have four more to come and that will make the PDO of total 14 wells, which will be completed in '18. And of course, the obvious question is do we continue from here? And certainly, we' re looking very actively to start our infill campaign, because the field is growing, so we see a lot of opportunity there. So its definitely on our agenda, and we will going to be looking and if we're going to be putting in the -- in our budget '18 as well as '18 on further drilling activity. But that's an ongoing discussion with the partners and also with the work we're doing on the subsurface in the modeling. So -- and again, I think by the Capital Market Day, we will be really able to say if we're going to continue beyond the, call it, the plan of development drilling activities, but there is a likelihood we may.
Good morning, Robin, and on the Grane Blend, so currently, the fields producing into the Grane pipeline or Grane filed itself obviously and then Edvard Grieg and Ivar Aasen, and there's a third party field going into Grane as well. So that is effectively the Grane Blend. And generally, the Edvard Grieg Ivar Aasen crudes are improving the weighted blend of Grane in quality, and that's what is improving the lower discount to Brent and what we have previously seen. But then, obviously, you have also other market forces which are competing with the Grane Blend, the Euros, and then you also had certain sort of one-off issues with hurricanes in the states where crudes have been landlocked. So there've been another few external factors, I would say, which may impact from a month-to-month basis on what the actual discount on the Grane Blend is. But I think all we are saying at the moment is that the general trend of discount to Brent is narrowing. So I think that's all we can say at the moment.
That's very helpful. Just one follow-up, if I may. I know you don't disclose the details of the commercial agreement between Edvard Grieg and Ivar Aasen, but other parameters of it was set in stone and all the dynamic factors relating to production capacity and so on that play into that, the seat of that allocation between the two fields moving around over time. Thank you.
I mean, the parameters really for the production in Edvard Grieg is the commercial arrangement, obviously, is Edvard Grieg itself, the performance at Edvard Grieg. Second is the commercial arrangement between Ivar Aasen and Edvard Grieg, which is very -- that's something that is black and white and it is quite clear. And then obviously, the third one is also the production efficiencies. What production efficiency you apply to your production will impact your production guidance. So those are, I would say, the three factors really that make up the overall, call it, the Ivar Aasen/Edvard Grieg hub. And so, again, we're going to be very clear in the Capital Market Day with different guidance and how this is playing between Ivar Aasen and Edvard Grieg also.
And next question is from Duncan Milligan from Goldman Sachs. Please go ahead.
Just a couple of questions on Edvard Grieg. One is I think I see this before, but what cuts of the fields have started to be seen now and when did they first appear if they have appeared? And the second question is with the subsequent wells you've drilled this quarter, has that given you any greater understanding in the potential placement play around Edvard Grieg? Thank you very much.
Yes. Thank you. Water cut, in essence, no. We've seen very -- hardly no water cuts. So that's -- we anticipate any original model to see the water cut come in quite much earlier, and that hasn't come. So that's obviously part of the good news, but very little or no water cut. In terms of the basement play, yes, as I stated, we drilled one interesting well in Edvard Grieg called the Tellus area, which is located, if I'm correct, towards the northern area. And that well was a successful effort of Edvard Grieg, but also penetrated the basement -- fracture basement for certain length. And we established that that basement was productive and still is today productive. So that was really interesting news for what we're doing in Rolvsnes, because Rolvsnes is really the basement play, the up-dip part of Edvard Grieg, so to speak, and then there's a really large area there of fractured basements, so it could be a really interesting area right right next to Edvard Grieg. And so next year, we're going to be drilling a horizontal well there, test it. And then if that is successful, we will be able to tie in this well the year after very quickly and produce it and see the productivity. So -- but so far, what we see is very encouraging.
I wonder just on the robustness question. It's obvious, I see an extension [Indiscernible] potentially meaning that Utsira High could have some basement productivity if it works?
Yes, absolutely. I mean, that's the whole idea is that now to -- we already tested fractured basement and we know the productivity is there. What we need to establish is that this productivity is commercial and if it is extensive. So next year's objective is to drill and test and then if that's successful, is to tie it in into Edvard Grieg platform and do a long-term extension. And that is successful, then we can build on to that and that opens up a very large area up-dip of the Edvard Grieg and towards basement high. And we're fortunate because we have a platform. It would be more difficult without a platform, because there are quite a risky play, but with a platform, we can really play this game very well. So it's going to be really interesting.
And there are currently no further questions registered, so I'll hand the call back to the speakers. Please go ahead.
Thank you very much, and we're nearing the end of the webcast. We have one final question that we'll take from the web. Can we provide any further detail on further cost saving potential on Johan Sverdrup Phase 1 and 2?
Yes. I think we're riding on the back of capital on that area. But if you ask me what is my expectation is that we're seeing quarter-after-quarter cost reduction on Phase 1, we've seen also in Phase 2. And I personally think it's reasonable to anticipate further cost reduction on Phase 1 as we come along and Statoil become more specific hopefully next year, but certainly, what we see so far is very pleasing, and we're still carrying a significant portion of allowances continuing in the project. So there is scope for further reduction, yes.
Great. Alex, Teitur, thank you very much. Thank you to you all for joining us on the webcast, and that's the end of the session. Thank you.
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