Lundin Petroleum's (LNDNF) CEO Alex Schneiter on Q2 2016 Results - Earnings Call Transcript

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Lundin Petroleum AB (OTCPK:LNDNF) Q2 2016 Earnings Conference Call August 3, 2016 3:00 AM ET

Executives

Alex Schneiter - President and CEO

Mike Nicholson - CFO

Maria Hamilton - Head of Corporate Communications

Analysts

Rafal Gutaj - Bank of America Merrill Lynch

Anders Holte - Danske Bank

Julian Beer - SEB

Michael Alsford - Citi

David Mirzai - Deutsche Bank

Niki Kouzmanov - Jefferies

Henrik Madsen - Arctic Securities

John Olaisen - ABG

Teodor Nilsen - Swedbank

Justin Teo - Credit Suisse

Dan Ekstein - UBS

Julian Beer - SEB

Operator

Ladies and gentlemen, welcome to the Lundin Petroleum Q2 report, 2016. For the first half of this conference all participant are in listen only mode, and after there will be a question and answer session. Just remind you the call is being recorded.

I am now pleased to present our speakers, President and CEO, Alex Schneiter, and CFO, Mike Nicholson. Gentlemen, please begin.

Mike Nicholson

Okay, thank you very much indeed, and a very warm welcome to everyone to Lundin Petroleum's second quarter results, and operations update presentation. My name is Mike Nicholson, I'm the Chief Financial Officer, and I'll begin in the usual fashion, by taking you through the financial highlights for the second quarter, and for the half year.

Once I've finished, I'll pass across to Alex Schneiter, our Chief Executive Officer, and he will take you through an operations update. At the end of both presentations, you will of course, have the opportunity to ask questions, and we'll take those from the participants who are joining from the conference call. But if you like you can also send in your questions via email.

So to turn to page two of the presentation, to start with the financial highlights for the half year; a very strong performance for Lundin Petroleum, in the second quarter. We've had a second quarter of record high production, up from 62,400 barrels of oil equivalent per day, in the first quarter, to 63,900 barrels of oil equivalent per day in the second quarter. And that was a 15 percentage point increase, above the midpoint guidance that we had for the second quarter.

First half, average production was 63,100 barrels of oil equivalent per day, and that was 12% above our midpoint guidance. And really the single factor driving the outperformance was the performance of our Edvard Grieg field, and Alex will come back to that later in his presentation.

We did see a partial recovery in crude prices during the second quarter. If you recall, the Brent price's average in the first quarter, $34 per barrel; just under $46 per barrel Brent on average in the second quarter. That gave us a first half average Brent price of close to $40 per barrel.

In line with the record high production, Lundin Petroleum also had record low total operating costs and cost of operations. Our cost of operations for the second quarter was $7.12 per boe, and for the half year, $7.30 per boe. So we continue to see as our production ramps up, record low cash operating costs.

And it's really that combination of record high production, a recovery in oil prices, a very low cash operating cost that has allowed us to generate, for the second quarter, an operating cash flow of just over $223 million, $386 million for the half year. And an EBITDA of $206 million; just over $330 million for the first half. We did record a small loss in the second quarter of $48 million. That was impacted by a largely non-cash foreign exchange charge of $63.5 million, and I'll come back to that later in the presentation. But for the first half, we recorded a profit of $66 million.

Turning to page three now of the presentation and this shows the comparatives, the EBITDA comparatives with 2015. And what you can see for the half year is the dramatic and transformational increase in our production levels. Our average production for the half year increased from 27,400 barrels of oil equivalent per day, up to 63,100 barrels per day. That's 130% increase from the first half of last year. We did experience lower oil prices on an average for the half year; prices were $58 per barrel, and we realized, as I mentioned, $40 per barrel for the first half of 2016. That was a 30% drop in oil prices, and, together with the lower cash operating cost, that's allowed us to increase our EBITDA by 72% for the half year, up from $192 million to just over $330 million. And a similar performance for the second quarter; we see our EBITDA has increased significantly, up by 94% from $107 million, to just over $206 million.

Turning to Page 4 and the operating cash flow numbers. We've seen a strong increase also, but smaller in percentage terms than we've seen with the EBITDA numbers. Our operating cash flow is up from $347 million in the first half of 2015, an increase of 11%, up to $386 million. The reason for the relatively smaller percentage increase was the fact that we had a higher tax credit coming through in the first half of 2015. We recorded a tax credit of $133 million in the first half of 2015, compared with a $43 million tax credit coming through in the first half of 2016. But still very strong cash flow generation indeed. If you look at the cash flow generation from the second quarter comparatives, up from $192 million, up 17% to just over $223 million.

Turning to Page 5 and the net results; in the first half of 2015 we recorded a loss of $171 million. One of the big factors driving the loss in the first half of 2015 was a foreign exchange charge of $177 million. We did see that reverse in the first half of 2016, and we recorded a foreign exchange gain of $95 million in the first half; I'll come back to that. That's allowed us, together with increased production and lower cost of operations, to generate a net profit for the half year of $66 million. The second quarter comparatives, as I mentioned, we had a loss of $48 million, compared with a profit in the second quarter of 2015 of $60 million. And what we saw was some weakness in the Norwegian krone from the end of March to the end of June.

Turning to Page 6, the reconciliation of the net result for the half year; our revenue that we generated was just under $457 million, and that was from production of 63,100 barrels of oil equivalent per day, and our average realized price was just over $37.70 per boe. From our revenue we deduct our operating cost of $113 million. Our cost of operations was just below $7.30 per barrel, that gave us a cash margin of $343 million.

From the cash margin we deduct the non-cash charges, the depletion charge was just over $215 million, and the exploration costs just under $69 million; and that gave us gross profit of $59 million. From the gross profit we had a small charge, a $3.5 million charge for the sale of assets. That relates to the Indonesian sale. We completed that transaction on April 28. We did book the result for the first four months and that really just reflects the reversal of that result because the effective date of the transaction was October last year. G&A charge was just under $15 million, and a net financial charge was just under $30 million. And against that we had tax credits of just of $55 million, which gave us that net result for the half year of $66 million.

Turning to page 7, if we look at the netback calculations, again you can see the very strong cash flow netbacks and low operating cost for the Company. As I mentioned, the second quarter Brent prices averaged just over $45 dollars per barrel. Our actual revenue per boe was in line with the Brent price, $45.60. Continued very low base cost of operations, $6.40 per barrel, and when we include our project activity of $0.73 that gives us $7.12 per boe for the second quarter for our total cost of operations. We add in our additional cash costs, our tariff and transportation and our production taxes; that gives us a record low total cash operating cost of $8.85 per barrel, so less than $9 dollars per boe cash operating cost.

When you deduct inventory movements and other items, that gives us a cash margin netback for the second quarter of just of $36 per barrel, and for the half year, $30 per barrel. From our cash margin netback, if we have a cash tax credit coming through of just under $2.20 per barrel, that gives us an operating cash flow netback for the second quarter of just over $30.40 per barrel, and for the half year, $33.60. From the cash margin netback if we deduct the G&A charge of just under $0.80 per barrel, that gives us an EBITDA netback of $35.50 for the second quarter, or just under $29 per barrel for the half year. If you look at the half-year netbacks cash flow and EBITDA of $33.60 and $28.80. Those are in line with the guidance that we gave at our Capital Markets day back in early February.

Next slide on page 8 shows the cost of operations, and the phasing that we have across the year. You can see very low base cost of operations, and we're retaining our guidance for the full year at $6.35 per barrel. We did see a slight reduction in our project activity and project costs in the first half, so we are reducing slightly our full-year total cost of operations guidance including project activity, down from $7.35 per barrel to $7.10 per barrel. What we're seeing is -- the largest single factor driving the lower cost of operations is the onset of the production contribution from Edvard Grieg during 2016.

Next slide page nine, shows the exploration costs nothing really material to report in the second quarter. No expensed wells in the second quarter. So the first half charge really relates to the wells that were drilled during the first quarter; in Norway that was the Lorry well and the Fosen well. The full first half charge is just under $56 million on a pre-tax basis. But of course, under the favorable Norwegian fiscal regime we get a full 78% tax credit against those exploration costs, so the after tax charge coming through the P&L is just over $12 million.

For Malaysia we actually recorded a small credit, a reversal of some of the accruals that we had in the first quarter; and the after tax charge for those Malaysian wells drilled in the first quarter was just over $13 million. So the total after tax charge for our exploration costs for the first half was just over $25 million.

Turning to G&A and financial items; our second quarter G&A was in line with our expectations, total charge of $5.6 million, and that gives us a first half charge of just under $15 million. If we turn now to the net financial items, you can see the total charge for second quarter was just under $140 million. The biggest single item in the financial charge was the foreign exchange loss that we saw coming through in the second quarter. And what we saw was a partial reversal of the gain that we recorded during the first quarter.

The Norwegian krone weakened from $8.27 to $8.38 during the second quarter and that drove a largely non-cash foreign exchange loss of $63.5 million. But we did record a foreign exchange gain during the first quarter of $159 million. So the net gain that we're recording for the half year was just over $95 million.

Interest expense for the second quarter was $39.4, for the first half just under $74 million. And what we had in addition to that charge during the first half was we capitalized additional interest rate costs of just under $8 million. Another item that I want to draw your attention to in the second quarter; you can see that for the amortization of our loan fees, we had a charge of $26.4 million. What's included in those second quarter numbers is a charge of $22.3 million. What that charge relates to is the capitalized financing fees that we had in relation to our 2012 and 2014 credit facilities. We amortized those fees over the life of the loan. But given that we refinanced our credit facilities earlier this year, we've expensed the fees in relation to the $2.5 billion and the $4 billion facility that predated the refinancing. So the total financial charge coming through for the first half, just under $30 million.

During the second quarter we benefited from a current tax credit of just under $2.20 per barrel. And against that we've had a deferred tax charge of $2.50, giving us a small tax charge for the second quarter of $0.30 per barrel. But for the first half we have a tax credit of just under $4.80 per barrel.

Slide 12 shows the reconciliation of our net debt position for the first six months. We started the year with an opening net debt of $3.786 billion. You can see that we generated an operating cash flow of just under $390 million. We've funded our development expenditures, which stood at just over $400 million, our E&A cost of just under $80 million. We've had financial charges and G&A charges of $235 million and $10 million respectively. We've also had working capital movements of $96 million. And that's taken us to a closing net debt position of just over $4.2 billion at the end of June.

Turning to Page 13, we're providing here an update on our funding and liquidity position. You recall in early February we announced that we'd secured a new 7 year reserve-based lending facility of $5 billion. And initially back in February we had bank commitments of $4.3 billion. By the end of the first quarter we had increased bank commitments to close to $4.5 billion. And I'm pleased to report that a lot of work has been done in the second quarter to further secure long-term commitments. What we've been able to do is increase the commitment levels by a further $0.5 billion from a combination of existing banks and new banks. That means that we've now fully filled the accordion mechanism that we had within our RBL facility. Just to remind you in terms of cost of that facility, it remains very competitive, an attractive margin. We pay U.S. LIBOR plus 315 basis points. We also benefit from the tax deductibility of our interest charges in Norway. So when you look at our after-tax cost of debt, it approaches 2%. So very low cost to fund our ongoing development projects.

We took the opportunity to restate the reserve-based lending facility to allow us to fund our Johan Sverdrup project. And we don't have any planned amortizations under that facility for a period of five years, for five years. We have recently gone through half-year redetermination in June. And I'm pleased to report that, using the latest bank price forecasts, we have access to, or the capacity of our assets support in excess of that $5 billion facility. So you will recall that we announced during the second quarter that we'd put in place a short-term revolving credit facility of $300 million.

That was important for us to be able to demonstrate that we had diversified sources of funding. But given the fact that we've increased our long-term financial commitments under the RBL by $0.5 billion, we took the decision to cancel that short-term $300 million revolving credit facility. The final point to mention was on our FPSO sale; we had reported in our Capital Markets Day that we had entered into a transaction and agreed to dispose of our FPSO interest. M3nergy, which was the counterparty in that transaction, was unable to secure the financing to fund the acquisition within the time limit that was permitted under the sale and purchase agreement. So, that transaction has now been terminated.

But if we step back and look at the overall financial position of the Company, our sources of liquidity are our 5 billion for the committed reserve-based lending facility, and in addition to that, our $250 million exploration refund facility. If you compare that with our net debt position at the end of the half year, which stood at just over $4.2 billion, Lundin Petroleum has significantly enhanced its financial strength and liquidity position. And we now currently have more than $1 billion of committed long-term funding, so very strong position indeed to be in.

The final slide in the presentation shows the hedging position that we have in place. No new hedges have been put in place. We can see here the hedging position in relation to our NOK/US dollar exposure. We did take the decision in September last year to lock in 50% of all of our Johan Sverdrup phase 1 NOK exposure. 60% of the costs in relation to phase 1 of Johan Sverdrup are NOK denominated. And we've hedged 50% of that, which translates into forward sales of $890 million at an average NOK rate of NOK8.43 per $1.

The interest rate position, the hedging position, has remained unchanged from that that we reported at the end of the first quarter. So that concludes the financial part of the presentation. I'd like to hand across now to Alex and he will take you through the update for the operations for the half year. So, Alex over to you.

Alex Schneiter

Thanks, Mike. And good morning, everybody. So I will start straight away with slide 15. I guess before I start I would like to say that I'm very pleased with the first six months, certainly from an operational point of view. As Mike mentioned, in terms of the production performance, a very good, very strong first half which is 12% ahead of the mid-point guidance, and a Q2 that is an even stronger with a 15% ahead of mid-point guidance, that's close to 64,000 barrels. I would like to also reiterate that the full-year 2016 guidance is retained. And that is between 65,000 barrels to 75,000 barrels of oil equivalent per day. I will say more about this when I talk about Edvard Grieg later on. Also good performance in production, but also low or high operating efficiency, you see from my presentation also our Q2 cash operating costs are at a record low, at 8.85 boe, or below $9. And this is really the results of an outstanding facility uptime. This is true obviously for Edvard Grieg, but it's also true for most of our operations as you will see later on.

On the highlights also on the transaction, I'm pleased to say that the Edvard Grieg deal with Statoil is completed as of June 30 as expected. We are now accounting the additional production as of July 1, 2016. Also on a smaller scale, the Singa sale in Indonesia was completed in April of this year and that formally is the exiting of Lundin Petroleum from Indonesia.

Mike went into a great detail in terms of the financing. Suffice to say that today Lundin is in a very strong position. We have now a firm commitment of 5 billion. And that's more than sufficient to bring us to Johan Sverdrup first oil, even at today's low oil price. And finally on the highlights exploration, we've been very successful in the 23rd round, which was focusing on the Barents Sea. We had five license awards actually Statoil and ourselves were leading this 23rd licensing round. You will see later on in my presentation that gives us a very enviable position in the Barents Sea. And today we have started now exploration activity in the southern Barents Sea.

Turning to page sixteen, on the production recap. I'm not going to go through all the details. Suffice to say as I mentioned before, record production. We're actually exceeding the upper end guidance for both the first quarter and second quarter. Secondly, I reiterate that our production guidance for the full year will be retained, obviously particularly on the back of the performance of Edvard Grieg. We are now accounting as of the third and fourth quarter, we are accounting 15% additional interest from Edvard Grieg from the acquisition from Statoil interest. And you'll see from this slide that now Norway accounts for in excess of 80% of the total production. And so again I will say a little bit more about the guidance for the full year when I come to Edvard Grieg, but overall very pleased with the production. I'm very pleased overall, both on the Edvard Grieg level, but also the other operations.

If you turn to page seventeen, this is really the reflection of our high production numbers. This is the result of excellent operating performance. You see the numbers from our major fields, Alvheim, Edvard Grieg, and Bertam particularly. And you see that the uptime has been in excess of 95%, also 98% to 96%, 98%, so outstanding performance from our team and very pleased with that.

Now turning to Edvard Grieg, which actually is important to the Company, Edvard Grieg today accounts for almost 60% of oil production. So obviously we have a lot of focus and I'm sure you're doing the same. First half '16 gross production close to 65,000, I would say outstanding performance in terms of the top side and the up time, as you've seen on the previous slide. But it's also fair to say that the subsoil phase is also performing very well, all three producers are exceeding expectations.

On top of that, our latest water injection, water injection one, has started the water injection. This well is now injecting water as expected. We actually do see the response already from our producers to increase pressures, so very good news indeed for the field. It's also important to highlight that the first water injection encountered the top reservoir 23 meters shallower than prognosis. This is significant, today we are drilling a second water injection, and we come back during the third quarter about potential impact of having a top reservoir higher than prognosis. It's also fair to say that the reservoir in general was better than expected.

So drilling is ongoing, we're currently drilling a second water injection and following the second water injection, we'll be drilling a fourth producer. Fourth producer is essential, because with the fourth producer we will meet our plateau production in Edvard Grieg, and as we stated all along we need the fourth producer to reach plateau production in Edvard Grieg. As we said all along, this will happen during the second half of 2016. Now it has been mentioned that the first injection took a little bit longer than anticipated, that means that the fourth producer will come on stream towards the end of 2016, hence maintaining our guidance. We also guided the market that we will not exceed the upper end of the guidance, but rather will be within guidance but perhaps towards the lower part of the mid-range. I don't see this as being a significant issue, it's a phasing issue. As I stated before, we remain very confident that we will meet the guidance between 65,000 to 75,000 barrels of oil equivalent per day. Overall Edvard Grieg is performing very well; in actual fact there's a lot of good news. If I resume, excellent performance in terms of top side, excellent subsurface performance, and upside when we're looking at the first water injection with the reservoir coming higher than prognosis.

Turning to Page 19, this is a summary of the acquisition of Edvard Grieg. As mentioned before we acquired 15% of Edvard Grieg and pipelines from Statoil. This is adding 31 million barrels of oil on 2P reserves, and adds 10,000 barrels equivalent per day on the production. That led to the revised guidance between 65,000 to 75,000 barrels of oil equivalent per day in 2016. For that, the consideration is that Statoil now owns over 20% of the total shareholding in Lundin Petroleum. Today the number of shares outstanding in Lundin Petroleum stands now at 340 million.

Page 20 is a summary of the deal pre and post deal, production 2016, as I mentioned, moving from 60,000 boepd to 70,000 boepd to 65,000 boepd to 75,000 boepd on the back of the Edvard Grieg transaction. 2P reserves now stand at close to 720 million barrels of oil equivalent, 2P reserves. Operating costs, as a result of this acquisition, are now reducing from $9.25 barrels of oil equivalent to close to $9. Development CapEx slightly increasing to $970 million; that's obviously our increased shares and is related to the ongoing development drilling. To emphasize, as I stated before, record low operating cash costs in Q2 standing below $9 boe out of guidance.

Alvheim, briefly on Page 21, the field is performing outstandingly. We've seen for the first half of 2016 operating costs of close to $5 per barrel. A lot of our drilling activity in Alvheim, I'm not going to go into intricate details, but I would say that the infield drilling so far has been excellent. Results have in general been above expectations, and we are very pleased with the performance and what we've seen in terms of the results of the ongoing drilling. On the Volund side, we are preparing for the development drilling, which will commence in 2016, December 2016, and both new wells will be expected to commence production in the second half of 2017. Alvheim is the second biggest producer, non-operated, operated by Statoil, we're very pleased with the performance. Johan Sverdrup, our largest project, obviously major importance to all of us, and, as I stated before, will account for over 40% of the NCS oil production at plateau, just to give a sense of the size of this project. Today the construction of all four platforms has commenced. We also have started the drilling and drilling is ahead of schedule. Today the project is actually moving according to plan, and we are above 18% in terms of execution, and that's according to plan.

To remind you, phase 1 costs also has been a positive story. We submitted a plan of development with NOK123 billion for phase 1, this is now down 12% at NOK108.5 billion, and we expect further cost reduction as we along. We also revised the guidance for phase 1 from 380,000 boepd to 440,000 boepd on the back of debottlenecking, starting on phase 1. Overall very pleased with the progress on Johan Sverdrup. We will hear more from Statoil on costs both for phase 1 and phase 2 probably during the second half of 2016.

Moving now to the exploration side of the story, obviously our story is very much led by the Southern Barents Sea, definitely the most important core area exploration-wise for Lundin Petroleum. You've seen that we have started activity by starting the drilling of our appraisal well in Alta-3; it's an appraisal well which we're re-entering. We'll be deepening the well and also testing the well. That well is obviously important for the feasibility study of the Alta discoveries as we go forward. Then follow the Alta appraisal, Alta-3 appraisal, we'll be re-entering Neiden which is on trend and on the north of the Alta discovery. Then we will be spudding a well called Filicudi which is right on-trend with the Castberg discovery, a very interesting and exciting program coming this summer.

Leiv Eiriksson we've secured three firm slots and we also have six options going forward, so a lot of flexibility for us. It's a fully winterized rig. Just to highlight quite a lot of activity in that area, the Loppa High where recently in the last four years over 1 billion barrels of oil has been discovered and that is through Johan Castberg from Statoil, the OMV discovery, Wisting, and obviously Alta and Gohta, so a very interesting area, and very exciting going forward. In terms of the story of the Southern Barents Sea, you see from the slide on page 24 that our acreage positon is very enviable, it's a very exciting position. This was also true with the result of the 23rd licensing round where both Statoil and Lundin were the leading companies in terms of licensing awards. That has opened up the area and particularly close to the Russian border with some really fascinating areas and what we believe potentially very prospective areas. I'm very pleased with the position of Lundin Petroleum in the Southern Barents Sea, and obviously you're going to see with the years to come a lot of activity in that area.

On the next page is to give you a feel of some of this potential. The slide you see here, it's an image of those new blocks awarded on the 23rd licensing round. Just as a comparison, which is quite amazing, some of the structures which are very, I would say, straightforward structures, some of them are three to four times the size of Johan Sverdrup. So you can imagine that we are very excited here in Lundin Petroleum and really looking forward to drill this very large prospect.

Moving on to the other side of the world to Malaysia, I will have only one slide, this is on Bertam. I think Bertam is our third biggest producer, so I think it's important to say a few words about it. It's performing very well. We've completed a new well called A15, which you see highlighted on the figure to the right. This well commenced production in May 2016, and overall the results were better than anticipated. Production overall in Malaysia is very good and we're very happy with the production performance.

We're obviously now looking at different infill drilling options and again, in the figure on the right-hand side, you see this blue shape of those areas where we see further potential on the Bertam, so pleased overall with the Bertam.

That brings me to the summary. I think the summary is really four points. First of all record quarterly production with excellent operational uptime performance. We continue to show low operating costs per barrel, and this has also been on the back of excellent performance on Edvard Grieg, which accounts to close to 60% of oil production. As Mike's mentioned, our financial position remains strong or stronger, particularly with today a firm commitment from the bank of $5 billion, which, as I stated before, is in excess of what we need to reach first oil in Johan Sverdrup. That gives us a headroom of about $1 billion of liquidity. And organic growth strategy continues. We've now started drilling again on the Southern Barents Sea, and we have built up a very strategic position in that part of the world. Overall I'm pleased with the results pleased the way the Company is heading, and with that, I think we'll open up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] first question from conference call is from Rafal Gutaj, Bank of America Merrill Lynch. Go ahead sir your line is open.

Rafal Gutaj

Just two questions from me, please. The first one on Edvard Grieg and the injection well that you've had delays on there. Can you just give us a bit more detail as to what caused the issues? Was it issues with the jackup rig and how many weeks has that set the program back? Then secondly, I know it's probably far too early to be talking about volume upside potential on Edvard Grieg, but I just wondered if you could give us some sensitivities on the basis of what you've seen from the first injection well, what you've seen from well productivity on the first three production wells? Then also if there has been any further thoughts on potential debottlenecking of the plateau there. I'll leave it there.

Alex Schneiter

I guess I will take those two questions. Your first question, Edvard Grieg injection yes, the first water injection took longer than anticipated. That was not related to the rig itself, it was pure operationally driven. And it took us longer to set the casing and some other technicality; I don't think we need to go into the detail now. But what is important is that the first water injection is up and running. It's injecting exactly what we wanted them to inject, and more importantly the results of the well actually are very positive, and that will come to your second questions.

In terms of the exact numbers, you're asking weeks so it's a slight delay. But fortunate thing is that by -- because the first injection has been delayed slightly, it has an impact on the fourth producer. But we're not talking about -- we're talking about weeks rather than months. So hence, overall our guidance that we're giving you today. In terms of the impact in the volume, I think it's too early to say. Clearly, 23 meters above prognosis, it's a lot, it's significant. And now we have to establish if this trend on the western flank of the field continues, and the best way to establish this is by assessing the result of water injection two. So I think we need to be a bit patient, but currently, water injection two is going according to plan. We should be -- by the time we release our third quarter, we should have further news, and at that point we will be able to say more in terms of potential. But clearly, it is good news. One thing also to add is that what we see is the pressure depletion, it's significantly lower than expected. That's also positive. It could be either there's more pressure support from the aquifer or there are higher volumes, or there are both. So overall, I would say there's a lot of positive going on for Edvard Grieg.

Rafal Gutaj

Perfect. And then just on the production plateau. Obviously, debottlenecking has been achieved on the Sverdrup plan. Would that -- is there any scope within Grieg to do that?

Alex Schneiter

That's right. I think before we talk about debottlenecking, we need to bring the fourth producer on stream and then we can test the plan. We know the design capacity, which is the plateau, which is the 100,000 boe that we've always been guided. I think again that's early days. Now we really need to bring the fourth producer and test the top side, and at that point we will see if the actual capacity can be ahead of the design capacity. But it's early days. But you've seen, as an example in Alvheim, we've been producing well above the design capacity, and that's not unusual on fields. But it's something we need to establish when we bring the fourth producer on stream.

Operator

And our next question comes from Anders Holte with Danske Bank. Go ahead sir, your line is open.

Anders Holte

Two questions from me. First one, I guess it's a follow-up on Edvard Grieg. Just if you could remind us, on the net pay on that side of the reservoir where you saw the reservoir coming in 23 meters above expectations. Then secondly, it's related to your RBL borrowing base, that the coverage was well above $5 billion in terms of the [redetermination] of Q2. I'm just wondering how low would you see oil prices go before that borrowing base goes below $5 billion.

Alex Schneiter

So I'll answer the first question and I'll let Mike respond to the second one. You were asking about the net pay on the water injection. By the fact that we were at 23 meters higher than prognosis, we had a net pay of 26 meters on that particular well. And also, maybe an opportunity for me to say that in general, overall, the net pay both above and below the oil water content was better than anticipated. I'll leave it to you for the second question, Mike.

Mike Nicholson

Yes, we don't give exact guidance on the actual borrowing base number, but there's a comfortable margin over and above the $5 billion. I think what's important to mention is we did see the banks actually adjust their short-term oil prices certainly through our June redetermination, relative to where we stood at the year-end. So we're obviously very pleased that we could still support well in excess of $5 billion, notwithstanding the fact that the banks had adjusted downwards their short-term oil prices.

And also, I think what's also very important to mention is the fact, the position that Lundin Petroleum's in, as we move forward in time, and as we approach the startup of Johan Sverdrup, we actually see the borrowing capacity of our asset base increase through time. So if you like, there's a natural hedge for us to see increasing capacity as we move through future redeterminations. But with $1 billion of excess liquidity and our net debt position standing at around $4.2 billion, certainly for this year at current oil prices and post-acquisition of Edvard Grieg, we don't really see material movements in our forecast net debt position between now and the year-end. So we're in a very comfortable position indeed with respect to available liquidity and capacity of our asset base moving through time.

Anders Holte

Okay. So even if the oil price is to remain at these levels for the rest of the year, you don't see any meaningful reduction in the borrowing base in the RBL?

Mike Nicholson

Correct.

Operator

Thank you. And our next question comes from Julian Beer of SEB. Go ahead, your line is open.

Julian Beer

Excellent results; fantastic. Questions on Grieg, if I may, to start with. Just to confirm, did you say that you hit 26 meters of net oil pay with that WI well?

Alex Schneiter

Yes, that's correct. We were anticipating 3 meters of net pay because it was a water injection and we wanted to hit it, mainly below the oil water contact. And it came higher. And so 23 meters higher top reservoir and 26 meters of net pay at that particular location, yes.

Julian Beer

So will your plan be to complete below the oil water contact, or will you -- is there any way that you can actually produce any of those volumes?

Alex Schneiter

Well, as far as the water injection goes, it's a water injection so we're going to -- it's complete and it's injecting water. As far as the additional barrels, as I said, we're going to drill the second injectors, assess probably we will have to re-map the structure towards the Western side and of course, the plan will be then to look at recovering those barrels, but that's early days now.

Julian Beer

Okay. But you don't risk isolating those volumes by injecting directly below that?

Alex Schneiter

No, not at all.

Julian Beer

Okay, good. It's a while since I've done any reservoir engineering, as you can probably hear. On that point, I'm a little bit confused about the reservoir dynamics at Grieg. I think earlier in the year you said that, because of the excellent productivity of the reservoir you were having to choke back the existing producers until you got injected volumes into the reservoir. But now you seem to be saying that the pressure response is better than expected on the fields. Are you actually choking back those existing producers, pending re-pressurization of the reservoir?

Alex Schneiter

Yes, it's reservoir management, as you know, and the first water injection, obviously very pleased because we already see the response on the producers. So we know that the whole field with the injectors in communication, which is obviously a very good place to be. But nevertheless, it doesn't mean because we've got one water injection that we can go full blast with the other three wells. So we are somehow choked back to managing the pressure increases or pressure depletion if you want, as we're drilling the new water injections. So there is a certain amount of management on the producer wells.

Julian Beer

Okay, so if you did have all the injection that you needed what is the theoretical production capacity of the existing three producers?

Alex Schneiter

If you could drill, if you could produce them and you don't have to, you can ignore the water injection, let's say you got a natural drive I would say you would be getting very close to plateau production with the three producers.

Julian Beer

That's great. And can you give us an exact month when you'd expect the sort of month when you'd expect the fourth producer to be ready for production?

Alex Schneiter

Yes, I would say, as I said all along, the best way to describe this will be the end of the second half of '16. But to give you more a hint, we are now drilling the second water injection and that's going very well, so I'm pretty confident that the fourth producer will be there and up and running by the end of this year.

Julian Beer

Okay, I've got several questions, I'll come back at the end of the queue, but just one last one for now relating to operating costs. Mike, could you give us a feeling for the sensitivity of your dollar denominated cost of operations to exchange rate moves? For instance if the Norwegian krone were to be 10% weaker than your base case assumption against the dollar, what sort of impact would that have on your dollar per barrel cost of operations, and have you changed your NOK/dollar assumption since the CMD?

Mike Nicholson

No, Julian, we haven't changed our NOK/dollar assumption, and what we've see is on average it's around 50% between dollar/NOK, NOK exposure. But we haven't seen any material change in the exchange rate assumptions that we used in our external guidance and where our forward forecasts are. So we are comfortable with our operating cost forecasts and the guidance that we've given as it stands.

Julian Beer

So if you were at $9 per barrel for the year and you were to put in current exchange rates, what sort of movement should we see in the 9?

Mike Nicholson

Well we're using current exchange rates to underpin our forecasts, so there would be no change.

Julian Beer

Okay, so the 9 does reflect the changes since the CMD?

Mike Nicholson

Correct, we were using the same exchange rates since CMD, so nothing's changed. Our forecast rates are close to existing market rates, so no changes.

Julian Beer

Good bit of forecasting, you're in the wrong business there, Mike.

Operator

Thank you. And next question comes from Michael Alsford, Citi. Go ahead sir, your line is open.

Michael Alsford

Just a couple of questions from me as well. Just firstly on Alvheim, seen again a good performance from the field. You mentioned, clearly, a couple of the wells came in a bit better than prognosis Kobra and then obviously the exploration well at Kobra East. I just wondered, could you give a sense as to what the volume potential is from those two data points from those wells?

And secondly just on the Southern Barents Sea, you mentioned obviously that the 3D seismic's being shot and these prospects are drill ready. I just wondered if you could talk to us a bit about what operational milestones need to be delivered on to perhaps see them drilled in 2017. Is it simply macro environment or actually is it just simply just getting a rig, effectively for that drilling program? And then finally, just on the FPSO the Bertam FPSO, obviously that's not gone through. I'm just wondering whether you're going to restart the process and is that still a plan to sell that asset and lease it back?

Alex Schneiter

I'll take the first two questions and I'll let Mark answer the third one. In terms of Alvheim and the infill and the result and additional volumes, I think again there we have to be a little bit patient there. They're positive results, that is definitely the case. I think now we're going through all the operators, through the results, and by the time we get to the end of the year we will come up with an update in terms of reserves. So I think that will be the best time to assess that. I think we probably expect to say this is going in the positive direction. In terms of the Southern Barents Sea, I guess you're talking about the new 23rd round blocks in terms of activities. As you rightly stated, the 3D seismic is shot, those prospects are ready to drill. Now it's mainly a matter of securing a rig and doing the necessary work to actually receive the license to drill the approval -- sorry, to drill a well. So Statoil is the operator on both these large blocks where you have this large potential, and there will be more details. But the anticipation is that by in 2017 we will be drilling one first well in one of these areas.

Mike Nicholson

And just to come back on the FPSO process now, Michael, there's no immediate plans to recommence the sale process. This was always going to be a short term liquidity injection, the FPSO deal. I think we guided in our Capital Markets Day there would have been a net liquidity benefit of $200 million coming in by the year-end. But as you go through time, that would reduce because we obviously now still benefit from the FPSO income. Since then we've done the Edvard Greig transaction, we've secured a further $0.5 billion in long-term funding commitments, so from a liquidity perspective there's absolutely no requirement to restart the process. Actually, in fact, in some respects it's a positive development because that Malaysian business now has more materiality and scale from a valuation perspective. So in terms of the options for that business it gives us a bit more room on that front.

Michael Alsford

And just a follow on, does it mean you're splitting it up therefore to IPO?

Mike Nicholson

No, no plans with respect to that yet Michael, it certainly gives us greater optionality.

Operator

Thank you. And our next question comes from David Mirzai with Deutsche Bank. Sir your line is open.

David Mirzai

First question to Mike, please. Just in terms of the additional equity interest taken in Edvard Grieg, has that -- is that related to the fill in of the accordion or can we expect the RBL facility could potentially be upscaled in H2 on the back of that transaction?

Mike Nicholson

Yes, that's a good question, David. Clearly now we have the benefits of including the extra 15% acquired in the Edvard Grieg field and as I mentioned, the asset capacity can generate borrowing base availability well in excess of the $5 billion facility that we have. So in theory we could upscale and upsize the facility, but practically speaking, as Alex mentioned, there is no need to do that because we can fully fund our Johan Sverdrup project, even at very low oil prices, within this credit facility. So in theory that's correct but in practice we don't see any need to upscale to meet the enhanced borrowing base capacity.

David Mirzai

Sure. A question for Alex if I may; one of your Norwegian E&P peers obviously did a fairly large transaction in Q2 as well. They went for a large corporate deal as opposed to you, you went for a very targeted asset-type deal. Can I read into that, although there's probably likely to be more M&A on the Norwegian continental shelf, you would find it hard to extract the same kind of fiscal and operational synergies on a larger transaction, and you think that your Company itself is growing in line with how you want it rather than the potential to maybe double in size?

Alex Schneiter

Yes, first of all, our main strategy remains organic growth and I think we've shown that very -- we've been doing that very successfully and that remains our main strategy. Now in terms of M&A, we did the Statoil per consideration, which was really for us very value-driven and it's -- we were operating in Edvard Grieg and there was an opportunity to do something there now. In terms of new M&A, I would say we take a more opportunistic view. If there is a new M&A for us, it will be Norway and nowhere else. If there is an opportunity again and exactly what type of transaction, corporate or asset, I don't know, but if there is an opportunity which has a strategic importance to us and particularly not just buying barrels to buying barrels but buying barrels that have got a high potential, that's something we would be contemplating. So right now, we are looking -- we're keeping our eyes open at what's happening in the Norwegian continental shelf. And if there is anything of interest, it's something we will be pursuing.

David Mirzai

But in terms of -- if I look at fiscal and operational synergies to your existing business, to your existing business going forward, what type of asset would most suit that? Obviously, clearly, something that's not mature but would it be more development asset or more production asset or one of your existing assets?

Alex Schneiter

Yes, I think production and development, I would say both, provided they have strategic importance. Of course, you can see that our focus is very much driven by the Utsira High and the Southern Barents Sea. Those two areas, if there's any opportunity that can grow our business, it's something we will be looking at. And that could be both development and/or production.

David Mirzai

Okay. And just lastly for me, I'm just going to ask the Edvard Grieg water injector question in a different way. Having brought on the first water injector, once you bring on the second water injector and you're able to support pressure in the reservoir, would you expect production from Edvard Grieg to increase on the back of that, ahead of the fourth producer being installed?

Alex Schneiter

Well, of course, water injection is as important as producers. So as the second water injection is coming on stream, it'll obviously be important to certainly maintain and achieve our plateau production. But in order to achieve our plateau production, nevertheless, we need the fourth producer in terms of total volume.

Operator

Thank you. And our next question comes from Niki Kouzmanov of Jefferies. Go ahead, sir, your line is open.

Niki Kouzmanov

Just one question on Johan Sverdrup. And then, I don't want to deal with the bad, but another on liquidity. So on Johan Sverdrup, what's your view in terms of the balance between realizing cost savings or increasing the throughput on the oilfield development beyond the 650,000 barrels. And then I'll come back with the second question after that, on liquidity.

Alex Schneiter

Okay, on Johan Sverdrup, obviously, right now a lot of the focus is on phase 1 and that's obviously, cost also and execution. And the second focus is obviously the concept selection of phase 2. I think so far our position was made very clear, that we've increased production on phase 1 to the 440,000 and we've maintained guidance for the full field production at 650,000. So this is right now the guidance that we're not changing.

Now of course, the phase 2, because of selection, hasn't been yet presented. And I think Statoil will come first in terms of the cost and the actual concept selection. At that point, things will perhaps become clearer in terms of the full field development. But right now, the main focus is obviously on phase 1 cost reduction as much as possible, and execution and the concept selection of phase 2.

Niki Kouzmanov

Okay, thank you. And just if I can ask the question slightly differently on the RBL, where do you see net debt peak on the price that banks have used? And how confident are you that this is below the 5 billion commitments that you're going to be having?

Mike Nicholson

Niki, we don't give guidance on specific numbers. But certain I can say that within the latest June pricedex that the banks were using within their forecasts and the 5 billion facility, we have sufficient headroom to fully fund Johan Sverdrup under those forecasts.

Niki Kouzmanov

Okay, thank you. And if I can just add one question around the last discussion we did on M&A. If I can turn it around, what kind of point in the cycle do you think, obviously at what price is [indiscernible]. But at what point do you think it's good to spin out a part of the Utsira High and monetize Johan Sverdrup in advance of first oil? Is that part of your M&A non-organic activity discussion?

Alex Schneiter

I think the simple answer is no. Norway is one entity and there would be no spinoff or separate entity within Norway. So there is no intention to do any spinoff at that level.

Niki Kouzmanov

Okay, thank you.

Operator

Thank you. And the next question is from Henrik Madsen, Arctic Securities. Go ahead sir your line is open.

Henrik Madsen

Just one follow-up on Grieg and then a small question on Brynhild as well. In terms of the length that we can expect of Grieg plateau production, could you go into a bit more detail there? And mostly in terms of thinking about the timing for potentially adding on more volumes from the nearby discoveries that you already have in your portfolio such as Luno II, Luno South, North, etc.

And secondly on Brynhild, obviously, the field is still struggling, as we can see from production numbers. Could you give us some more color on what we could expect from that field going forward as well? And what learning you're taking away from the current production? And what type of remedies you're looking at to potentially stabilize production?

Alex Schneiter

Your first question, Edvard Grieg, the plateau on Edvard Grieg is two years. So by the time we have the fourth producer on stream, from there it's about two years. Now in terms of your question on spare capacity, I don't think we're going to be specific at this point. But, of course, right now the focus is looking at the capacity of the platform itself, in terms of design capacity versus actual capacity. As you know, we're also going to tie in Ivar Aasen towards the end of the year. And there will be spare capacity at Edvard Grieg but that will come later and well beyond the two years of the plateau production. In terms of Brynhild, I think in general Brynhild has performed better. If you look at the uptime, it's actually above -- if you take for the first half of 2016, uptime is above what we anticipated. But in Brynhild, there's nothing fundamental - fundamental issues. Things are improving but perhaps it's slower than -- I would like to see a better performance, faster than what we see. And it's just an accumulation of small problems, which impact production. But we're injecting water and the production has been better than what we've seen in the past, but still marginal.

Operator

Thank you. And our next question comes from John Olaisen with ABG. Sir, your line is open.

John Olaisen

First, a housekeeping question. On the operating cash flow, in the slides you say that it's towards $233 million in Q2. But from the cash flow statement in the report, on page 23, it says $133 million. I just wonder what's the difference between those two?

Mike Nicholson

There's a couple of moving parts coming through the working capital, John. And if you look on our slide 12, which shows the reconciliation of our net debt position, for example there was included in those working capital movements of $96 million, we have trade receivables of $59 million. So, for example, we had two Edvard Grieg liftings which were sold on 30-day payment terms, so we've obviously accrued for the cash flow in the period. But there is a 30-day delay in when the actual cash is received from the counterparty there. Then also another item, just as one example, is the cash tax refund, which is earned in the period, doesn't become payable until December of 2017, and that amounts to just under $40 million as at the end of the year. So there's a couple of adjustment factors that need to be made to the operating cash flow numbers to get to the cash flow statements, but we can take that in more detail offline after the call if that's not enough information.

John Olaisen

So, it's basically working capital changes, or delays, or payment of taxes delays and so on. But the cash flow statement, operating cash flow $133 million is the more conventional cash flow from operating activities definition?

Mike Nicholson

Well, we've always had the standard definition of cash flow and we stand by that.

John Olaisen

Okay, and then my second question is regarding the extremely interesting exploration that will be going on next year in the Southeast Barents Sea; you introduced the slide number 25 where you show the structural area closures. I just wondered if you could define a little bit more the structural area closure which is three or four times the size of Johan Sverdrup for the Signalhornet Dome and Haapet High, please. What does it indicate of potential volume in -- if it's successful?

Alex Schneiter

Yes it's, you're referring to, yes, page 25. I think it's too early now to come up with the detailed volumes, but as I stated, in terms of area closure, one of the structures is 570 square kilometers and the other one is 850 square kilometers, and that compares to about 200 square kilometers in Johan Sverdrup. Obviously we're not comparing apple with apple because it's also that volumes will be the definition of the net pay and how many [signs] and reservoirs we're going to find. And so by the time we're going to announce the, and Statoil in particular, the operator, will announce the drilling, will come up with more specific numbers. But I think you don't need to be, it's clear that we're talking about multi-billion barrel resource potential.

John Olaisen

Which one of these two are you most optimistic on, and also secondly can you elaborate a little bit on the risk of there being gas instead of oil?

Alex Schneiter

Well, it's obviously, it's an area, there's being very little activity in terms of exploration of the area. The potential of gas is there, and the potential of oil also, and you may actually have both; you may have reservoirs that are oil-bearing and reservoirs that are gas-bearing. Again it's early days and really we will need to drill those wells and the gas versus oil, it's one of the risk. But so was when we entered the Southern Barents Sea, if you remember in the Loppa High, a lot of people only saw gas in that region and the reality is that in the last few years over 1 billion barrels of oil have been discovered. So you may see multiple options there and multiple results, so -- but that's one risk.

John Olaisen

And you mentioned that there's likely to be one exploration well in this area in 2017. Is that more likely to be the Signalhornet or the Haapet High?

Alex Schneiter

The one exploration well I'm actually referring to is on this, one of the two blocks that has been awarded during the 23rd round, so toward the what we call the Haapet High or the Signalhornet Dome. Those are the areas where likely there will be one well in 2017. And then in terms of the Loppa High we, today we're drilling three wells, one appraisal and two exploration and in 2017 the likelihood that we will continue to have drilling activity in that part of the Southern Barents Sea.

John Olaisen

Sure, but I was a bit more asking if there was on there, is it likely to be Haapet High or Signalhornet Dome next year?

Alex Schneiter

As I said there will be the drilling activities anticipated to have at least one well on the Signalhornet on the area towards the Russian border, and then there will be further activity, drilling activity on the Loppa High.

John Olaisen

Yes, but is it one well on either Haapet High or Signalhornet Dome, but you said more likely the Haapet High or the Signalhornet Dome?

Alex Schneiter

Yes I will be more specific when we come towards the year-end.

Operator

Thank you. Next question comes from Teodor Nilsen, Swedbank. Go ahead sir, you line is open.

Teodor Nilsen

One question on cash flow, you will of course have much more front ended load, front-end loaded cash flow after Edvard Grieg deal and you also have lots of available liquidity. So could you discuss what you're thinking on the dividend potential before Sverdrup first oil?

Mike Nicholson

Yes, good question Teodor. We've always guided in the past, but then when we talked about dividend potential that was in the range of oil prices around $65 to $70. But it's a fair point that you make and with the additional acquisition of the cash generative 15% interest in Grieg, that's obviously going to bring that kind of oil price level down. But we haven't come to a firm decision or guidance yet with respect to when we would commence a dividend program. But clearly that's the kind of guidance that we would refer to that we discussed publicly before.

Teodor Nilsen

Are there any dividend restrictions in your current RBL?

Mike Nicholson

No, not provided we can show we can fund our Johan Sverdrup project and as I mentioned, with the strong liquidity position that we have we've got surplus capacity within our 5 billion facility.

Teodor Nilsen

Okay, and then one question on exploration. Statoil is talking about substantial improvements on efficiency for the drilling activities. I think they're talking about 30%. So what do you see in terms of drilling efficiency and improvement compared to previous years?

Alex Schneiter

I guess the two factors on the drilling side is obviously the cost of platforms and then the efficiency itself in terms of operations. First of all on the drilling side we have seen now costs going down dramatically, both on the rig rates and also on the supply chain, third party supply. So your cost, it's fair to say that your costs are probably half or even more so, cheaper than what they were a few years ago. And Leiv Eiriksson is a good example in terms of rig rate. It's a winterized rig which is well below the $200,000 per day rig rate. On top of that we're still focusing on rig rate, but in actual fact there is also quite a lot of saving on the supply chain side of things. So that's one part.

In terms of efficiency, I would hope that we've been, in the last 10 years in Norway, in terms of drilling, we have always been trying to be as efficient as possible. When you go into the new areas, perhaps you take a more conservative approach because you have less information on the geology, but and as you drill more wells you become more efficient. But today when I look at our drilling activity on the Loppa High, I would say today we are as efficient as one can be.

Teodor Nilsen

Okay and then final from me, a short question on the RBL. What kind of price tick did the bank seize for the last [indiscernible] determination?

Mike Nicholson

Yes we're always asked that question Teodor, and that's obviously a commercial assumption that we don't publicly share. But I guess to give you some guidance that in the shorter-term forecast it's close to the forward curve, but the bank always tends to like to have some protection in relation to the forward curve; I think that's as much as I can say.

Teodor Nilsen

Okay, thank you, that's all from me thank you.

Operator

Thank you. Our next question comes from Justin Teo, Credit Suisse. Sir your line is open.

Justin Teo

Just a quick question on operating costs. I know you talked about the small decrease in guidance for the full year. Did the old guidance have higher costs from the FPSO Bertam included, given the change in arrangements? And also, for Grieg, you talked about $8.20 a barrel. Obviously, it hasn't ramped up yet. Where do you see those costs settling in the, at least, plateau period?

Mike Nicholson

Let me take that question. There's going to be no change in any of our guidance following the termination of the FPSO process. All of our base guidance numbers and the numbers that we've talked about today assume that we still owned -- have interest in the FPSO. I think, during the Capital Markets Day guidance, we did give a range of impacts if the transaction was completed. So the numbers that you receive today should stand firm. And then the second question. Yes, you're right to point out that Edvard Grieg does sit at the lower end of the average of our cost of operations. Clearly, as it starts to ramp up on to plateau production, we'd expect to see those costs fall further. Now, it's too early for us to give any guidance, but I think a couple of years back we showed that on plateau production Edvard Grieg OpEx could drop to around the $6 per barrel mark. So we'll have to come up with our guidance at the end of this year, merge the lower unit cost of operations on Grieg with our other assets. But I think it's fair to say, directionally, to expect that our operation costs should drift down as we move into 2017.

Operator

Thank you. And our next question comes from Dan Ekstein of UBS. Sir, your line is open.

Daniel Ekstein

I've got two questions, both on Edvard Grieg. One of them relates to the question that was asked earlier about capacity on the platform. Obviously you've got Ivar Aasen volumes coming in from the end of this year, and that field ramps up to plateau, I think, in the 2019/2020 timeframe. So you mentioned a two-year plateau for Grieg earlier. In a hypothetical world, if you wanted to and were able to extend plateau, given additional volumes, would you physically be capable of doing so in terms of the capacity on the platform? The second question is about the shallower prognosis reservoir you've seen on the western flank with the water injector. Trying to think about the aerial extent of the zone of uncertainty, shall we call it, and when you've been doing your depth conversion, what's the nearest point of well control to the water injector that you've drilled?

Alex Schneiter

Starting with Edvard Grieg and capacity. I think the key on Edvard Grieg and the capacity now is going to be bringing the fourth producer on line and test it actually will cover design capacity. And also, once we're going to bring Ivar Aasen in terms of the overall capacity, that will give us a good knowledge in terms of the upside. And in the event we extend the plateau of Edvard Grieg, what it means. So I think for now, in terms of capacity, we stand to the 200,000 barrels for the next two years in plateau. And I think the next control point will be really comparing the design capacity versus the actual capacity. But there will be quite a lot of opportunity to be able to, in the event of an extension of the Edvard Grieg plateau, to fit in those additional barrels if we need to. But I don't want to be too specific at this point.

In terms of the western flank, yes, clearly, there's an issue. Well, an issue; there is a positive outcome in terms of the western flank, and so far we see the western flank coming up. And so far with the control point of water injection, one is 23 meters higher. Now, we need to establish if this western flank is regional and it affects the whole western flank, or it's just more a localized event. The nearest control point we have on your questions, obviously, we have the producer, but that's towards the crest of the structure, so that's not very relevant on the depth conversion. And then we have certain wells that we drill in the past; exactly how distant they are, I don't remember off the top of my head, but I think we're talking about probably a couple of kilometers. And there are some control points there also.

Operator

And our final question comes from Julian Beer of SEB. Go ahead, sir, your line is open.

Julian Beer

It's a quick continuation question and it's relating to Statoil's 20% holding. If I look at the Statoil position build, part was clearly linked to the Grieg deal, which was very attractively priced to you, very good for shareholders and, of course, they bought shares, which strengthened your balance sheet. And Statoil have said that they don't intend to further increase their percentage ownership of your Company. Could you discuss how Statoil's corner position could help your valuation creation going forward, if at all?

Alex Schneiter

Yes. Statoil, as you said, I think, the acquisition of Edvard Grieg was purely value-driven and the way we structured that acquisition and end up Statoil owning a 20% ownership on the Company. Now, does that have an impact for the future? I think we stated from both sides, Statoil and Lundin, and I guess also the government, that independence is really important. So at this moment, other than them being shareholders, I don't think that will change really the modus operandi going forward or put us in a different league. So I think it's -- for me it's business as usual, and we personally are going to continue to be driven by value. And I don't think Statoil in this particular, in terms of new acquisition or strategic position, will change anything. But it's as we said all along, we're pleased to have Statoil as a major shareholder and I think we'll leave it to that.

Julian Beer

Okay. So there's no way that the relationship changes in terms of capacity to do deals or willingness to do deals because of that ownership.

Alex Schneiter

I think, for now, the answer will be that we each keep our independence and that's the most important one.

Julian Beer

Have you had any discussions with them regarding how they'd react if you saw a deal which required a further equity issuance, which, of course, they'd have to participate or would maybe want to participate in?

Alex Schneiter

No, at this point, no. We didn't have any further discussion on any of those points. And I don't foresee this being something that we contemplate.

Julian Beer

So a sleeping partner with 20%.

Alex Schneiter

A sleeping partner with 20%, maybe we can leave it to that, yes.

Operator

As there are no further questions on the phone, I'll hand back to our speakers

Maria Hamilton

And in between now we just have a few questions from the Internet. We have a question regarding both Lagansky block and Brynhild update. Just a short update on the two.

Alex Schneiter

Yes, Lagansky, as we announced, received a production license and now we just looking at our various options in terms of our Russian assets. But suffice to say that for now there is no plan to do any work program in the near future in Lagansky. It's more looking at the options available to us going forward.

And the second question, Brynhild. Yes, as I mentioned before, Brynhild is improving. Uptime is better than what it was in the past, but it's marginally better. And it is still a field that requires more attention to improve the overall operations efficiency. But certainly I feel we are in a better position today. It may be worth emphasizing that today Brynhild accounts for less than 5% of the total production of Lundin Petroleum, so when we talk about operational efficiencies in Brynhild, we're talking about plus or minus 1,000 barrels of oil per day. So we should perhaps put that in perspective also.

Maria Hamilton

We have another question to you, Mike. [indiscernible] issue when you were talking about the foreign exchange loss. The foreign exchange loss and an explanation of what that was.

Mike Nicholson

Yes, it's quite simple. For the second quarter, what we saw was a weakening in the foreign exchange rate from an average rate of NOK8.27 at the end of March to NOK8.38 at the end of June. And what we have to do under the accounting treatment is to revalue all the intra-Group lending that we have into our Norwegian subsidiary, which is NOK denominated. So that's been a largely non-cash charge that comes on the back of the revaluation of those loans and working capital balances.

And actually, if you step back as I mentioned, and if you look at the half year, so the six-month period, the NOK actually strengthened from NOK8.80 at the end of December to NOK8.38 at the end of June. And that actually gave us a net gain of 95 million for the half year. So two separate effects: strengthening in the first quarter, some weakness in the second quarter, which gives us a net overall strengthening and, therefore, a gain when you look at those revaluations of those intra-Group loan balances.

Maria Hamilton

Thank you. And the last question is, with the low oil price environment, do you have the financial strength to have an active exploration program in the future, as a summary?

Alex Schneiter

Yes, the answer will be, absolutely. As Mike showed with the numbers, we have the strength and available liquidity to continue exploration organically. And then coupled with that, the low oil price has got some benefit. One of them is, obviously, a significant reduction in costs, which also goes in the right direction. So yes, absolutely.

Maria Hamilton

That's all from us today. Thank you, everyone, for listening in to the Q2 report and if you have any questions, don't hesitate to come back to us.

Alex Schneiter

Thank you very much, everyone.

Mike Nicholson

Thank you.

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