Lundin Petroleum's (LNDNF) CEO Alex Schneiter on Q4 2015 Results - Earnings Call Transcript

| About: Lundin Petroleum (LNDNF)

Lundin Petroleum AB (OTCPK:LNDNF) Q4 2015 Earnings Conference Call February 3, 2016 3:00 AM ET

Executives

Mike Nicholson - CFO

Alex Schneiter - CEO

Maria Hamilton - Head, Corporate Communications

Analysts

Alex Topouzoglou - Exane BNP Paribas

Julian Beer - SEB Equities

Teodor Sveen Nilsen - Swedbank Markets

Mike Nicholson

Okay, a very good morning to everybody and welcome to Lundin Petroleum’s Year-End Results and Operations Update Presentation. My name is Mike Nicholson I’m the Chief Financial Officer. I’m joined here this morning by Alex Schneiter, our Chief Executive Officer and Maria Hamilton, who is our Head of Corporate Communications. I’m going to begin in the usual fashion by taking you through the financial results for the full year and then I’ll pass across to Alex who will take you through a more brief operations update this morning because, of course, this afternoon we do have our Capital Markets Day presentation.

At the end of both presentations you’ll have the opportunity to ask questions and we’ll take those from the participants joining from the conference call and you can also submit your questions via email. So, to begin with the financial highlights for the full year, our production for the fourth quarter and significantly up by 74% from the fourth quarter of 2015, 38,300 barrels of oil equivalent per day and that led to full year production of 32,300 barrels of oil equivalent per day, which was slightly ahead of our latest guidance. Crude prices did continue to remain weak during the fourth quarter Brent averaged just under $44 per barrel and that give us a full year average of $52.40 per barrel.

But Lundin Petroleum continues to have very low cost of operations and those are going to drop further as we start to see the ramp-up in Edvard Grieg. In the fourth quarter, our cost of operations was just over $9.30 per barrel, $10.30 per barrel for the full year. And that combination of higher production and very low cost of operations allowed us to generate an EBITDA for the fourth quarter of just under $94 million and for the full year $385 million and also, given the fact that we’re not in a cash-tax paying position, still generating very strong cash flow and from our core aspects fourth quarter operating cash flow was $175 million and just under $700 million for the full year.

We did record a net loss for the full year of $866 million that was largely driven by two main items. And the first, and I’ll come back to that, was a non-cash impairment charge of $300 million and secondly on the back of very weak NOK we had largely non-cash loss of $507 million, but I’ll come back to those items later in the presentation.

On this next slide, we look at the EBITDA comparatives with 2014 and what we saw was our EBITDA guidance from $671 million for the full year, down to $385 million. Now what we did see for the full year was production was up by 36% from 23,800 barrels of oil equivalent per day to 32,300, but that was more than offset by close to 50% reduction in crude prices. And likewise for the fourth quarter down from $164 million to $94 million and we saw 74% increase in production but again offset by lower oil prices in the fourth quarter.

Turning to our operating cash flow similar story and we are down from $1.14 billion to just under $700 million for the full year. That combination of higher production offset by lower oil prices, but what we also saw was a lower cash tax credit coming through and our operating cash flow numbers in the full year 2015, down by $150 million compared with 2014 numbers, and our fourth quarter operating cash flow down from $335 million to $175 million.

The net result as I mentioned for the full year 2014, we posted a loss of course the $432 million this year, this year the full year net result was minus $866 million and again largely driven by those two non-cash items, the impairments and the foreign exchange losses. And we recorded those impairments in the fourth quarter thus driving the $494 million loss in the fourth quarter, but I’ll come back to those items as I mentioned previously.

If we turn now and look at the reconciliation of our net results, our revenue of $569 million came from our production of $32,300 BOE per day at an average price of $50 per BOE. From that we had cash operating costs of $150 million, $10.30 per BOE, and that gave us a cash margin of $419 million. From the cash margin, we deduct the non-cash charges for depletion $284 million, exploration costs $184 million and the pre-tax impairment charge of $737 million that gave us a gross loss of $786 million.

From that we deduct G&A and financial charges $40 million and 610 million, respectively, but against that we have a tax credit of $570 million, which gives us that net result of a loss of $866 million. But if we turn and look at the cash margin netbacks and still a very strong performance from the Company. If you look at the average Brent price for the full year $52.40 per barrel, our sales realizations on average were $48.390 per BOE. The reason for the discount between the Brent price and our actual realization to the fact that we do have gas within our overall portfolio mix on average around 90% for the full year and when we saw that gas at an average of $44 per BOE, so that explains a discount from the Brent price. But our cost of operations, base cost of operations very low $8.70 per barrel for the full year and project activity of just over $1.50 per BOE and together with our tariffs and transportation charges, production, taxes and other items that gives us a cash margin netback for the full year of $35.50 per barrel.

Given we've been investing significantly in our growth projects in Norway over the last 3 to 4 years we’re in a cash tax credit position, so we actually had a cash credit for the full year of just under $24 per BOE which gave us an operating cash flow netback of $59.30, actually higher than the Brent price, a very favorable position to be in. And when we look at the EBITDA netbacks from the cash margin netback of $35.50 per barrel, we deduce the G&A charge of $2.90 which gives us an EBITDA netback of $32.63 for the full year.

This next slide shows the phasing of our cost of operations through 2015. We saw the reduction in the third quarter as our project ramped up through time. You'll recall Boyla started in the first quarter, Bertam came on stream in the second quarter and we had a production contribution through December from the Edvard Grieg field. And our base cost of operations dropped around $8 per barrel in the second half including project activity we're down to just over $9 per barrel, and if you look at our full year actuals and base cost of operations excluding projects $8.70 was slightly ahead of our Q3 guidance of $9 and when we include project activity our actual is $10.30 per barrel compared with our Q3 guidance of $10.80 per BOE. So a very favorable trend and you will see as we move into 2016, we expect those numbers to fall significantly below $10 per barrel.

Coming to our exploration costs, during the fourth quarter we expensed a number of wells in Norway. We had the Gemini well, the Zulu well, Morkel, Zeppelin, and Ornen were all expensed. The pretax charge for those wells was just over $31 million. The benefits of being in Norway is we do receive a full tax credit at 70% against those exploration costs so that gave us an after tax charge in the fourth quarter of just under $7 million. In Malaysia on the back of our Peninsula Malaysia drilling program, we expensed two wells Mengkuang and Selada, and also one well in Sabah, at the Imbok well. We don't get benefit of the tax credit under the Malaysian fiscal regime, so the after tax charge was $36.3 million. So in total the post-tax exploration charge in the fourth quarter was $43.4 million and for the full year $69.4 million.

Turning to impairments and of course we have seen crude prices weaken significantly and as a result of that we have to go through impairment testing of the carrying value of our oil and gas properties, at the yearend as a result of that for our Brynhild field in Norway, in combination with a decrease in our reserve estimates and we have recorded an impairment charge for Brynhild, the pre-tax charge is $526 million and we do receive a full tax credit against that, so the after tax charge coming though the net result is just under $110 million.

Likewise our Bertam project in Malaysia which is a small field and has also had some impairment charges, the pre-tax charge was $166 million post-tax $141 million and again as a result of weak oil prices, but no other impairment charges for the rest of the asset portfolio. We have as a result of some of our Peninsular Malaysia a drilling activity during the fourth quarter and taken some impairment charges that we're carrying on a number of our licenses just under %26 million in total and no tax credit against us that goes through the net result.

And also in Indonesia following the announcement that we're disposing off our Indonesian interests to Medco and we're taking a charge on our South Sokang and Centrawasih exploration licenses, to write-off the carrying values that we had in relation to those blocks, $19.2 million post tax which gives us a full year of impairment charge, pretax of $737 million, after tax just under $300 million, non-cash though I should stress.

Turning to G&A and financial items, our G&A was in line with expectation $8.3 million for the fourth quarter just under $40 million for the full year, and when we look at our net financial charge for the full year, $610 million that’s largely being driven by foreign exchange losses. What we saw during the fourth quarter was a further weakening in the Norwegian krone, relative to the U.S. dollar. It reduced from NOK8.5 to the U.S. dollar at the end of December to 8.8 at the end of December. That allowed us to record a charge of $129 million during the fourth quarter, which widened the full year charge to $507 million. That’s largely a non-cash charge, but it did include realized foreign exchange losses of $133 million.

And I do want to emphasize the reason for the non-cash component is because we lend into our Norwegian subsidiary in NOKs, to avoid any tax exposure. And at each balance sheet date, we have to revalue those intra-group loans, at the current exchange rate. So whilst of course, as a dollar-driven company and a strong dollar and a weak NOK is very good for funding and our obligations in Norway, we do record these non-cash impairments coming through the income statement.

Interest expense for the fourth quarter was $24.4 million, and in addition to that we’ve capitalized for the full year at $40.2 million to give us a full year charge of $71.4 million. So the total charge, financial charge for the full year of just over $610 million. Because as I said, we’ve been in a significant investment phase in our growth projects we are in a tax credit position. Our full year tax netback was a credit of $23.80 per BOE and as a result of -- and our impairments in relation to the Brynhild asset, we’re also in a deferred tax credit position just under $25 per BOE giving us a full year tax credit of $48.40 per BOE.

If we turn now and look at the reconciliation of our net debt position, we started the year with an opening net debt of just over $2.6 billion. We generated operating cash flow of $700 million. Against that we funded our development projects $1.06 billion, our exploration and appraisal activates of $440 million and our G&A and financial items $254 million and $27, respectively. And together with a working capital adjustment of $122 million that gave us a closing net debt position of $3.786 billion.

And turning now to the liquidity position of the company, you’ll have seen yesterday we are very pleased to announce that we’ve signed a new seven-year reserve-based lending facility. And that facility was supported by a group of 23 international banks. It replaces the previous $4 billion facility that was due to start amortizing in June of this year. The structure of the facility is a $5 billion accordion facility. And what were able to do is we’ve included Johan Sverdrup as a full 2P borrowing based assets. You will recall that previously rather very conservative leverage on Johan Sverdrup and that was capped at a dollar per barrel multiple. And when we run now Johan Sverdrup as a normal borrowing-based asset, we have the capacity under the new structure to borrow-up to $5 billion.

Now the initial commitments and from 23 banks are just marginally about $4.3 billion, but of course with the accordion mechanism, what we have is the optionality to bring in additional commitments. And really the structure of the facility, the new facility, has been designed to fund Johan Sverdrup through to first oil, the previous facility that we have in place was designed to fund Edvard Grieg. And the structure involves a five-year grace period, so there are no amortization of the loan facility to the first five years. So that would be the end of 2020, one year after Johan Sverdrup has planned to commerce production.

Also please to report an attractive margin in line with the margin where company is paying 300 basis points under our existing or previous 4 billion facility and the margin under the new facility is 315 basis points. And when you add on U.S. LIBOR rates, were just under 4% and interest rate before tax but of course under the Malaysian fiscal regime, we are able to claim and approximate 50% tax reductions or after-tax cost of fundings close to 2%, so very low indeed. I’d also given the growth profile of the company under the new forecast we have been able to put in place more flexible covenant package that reflects the growth profile of Lundin Petroleum, so very pleased to have announced that yesterday.

And what does that mean for the funding position of the company in terms of our overall liquidity. So we now have access to reserve-based lending commitments of $4.3 billion. In addition to that, we still have $250 million of liquidity under our exploration refund facility. So if you look at those committed sources we can pair that with our year-end net debt position that gives us committed liquidity of $760 million and of course we have the option under the new facility to access additional commitments from existing banks and new banks that could add up $700 million of additional liquidity. And as you saw we're in discussions with M3nergy, the Malaysian industrial player, to acquire our Bertam FPSO which we own 100% and by the end of 2016, we complete that transaction that would add an additional liquidity of $200 million, so if we take the committed plus optional liquidity that would up to $1.65 billion, so a very strong position indeed to be in.

Just to conclude on the final slide before I pass across to Alex on the hedges we announced at the end of our Q3, we entered into a series of additional NOK hedges in relation to our Johan Sverdrup project. So from the second half of 2016 through to the end of 2019, we hedged around $890 million of U.S. dollars at an average rate of 8.4 NOK per U.S. dollars which remains currently outstanding and we have hedged a total of $1.07 billion at an average NOK rate of Brent $8.2 per U.S. dollar and our interest rate hedging position has remain unchanged.

So that concludes the financial part of the presentation, I'll hand across now to Alex and he will take you through the operations update.

Alex Schneiter

Thank you, Mike. Well, good morning everybody. I'm pleased to be here this morning as Mike briefly stated today we'll be relatively briefing presentation as you know this afternoon we have the Capital Market Day and so for those of you who assist the Capital Market Day will have more detail and of course for those of you who don’t assist the presentation this afternoon the presentation of Capital Market Day will be on the Web site early this afternoon.

So let's start with the highlights of 2015 starting with your production, we achieved an average of excess of 32,000 barrels of oil equivalent per day. This is a 36% increase compared to 2014. Our Q4 production was also within guidance in excess of 38,000 barrels of oil equivalent per day. For yearned 2Q reserves stands today at 685 million barrels of oil equivalent that's up 292% increase and of course this is due to the giant Johan Sverdrup. We approved development, which then allowed us to book the reserve at the end of last year.

Development wise, we brought on stream three projects, Edvard Grieg being the last one and I will talk about it later on in the presentation. Suffice to say at this moment that Johan -- Edvard Grieg very pleased with the performance hence we came on stream earlier than anticipated. And of course Johan Sverdrup now is the highlight going forward. We signed a PDO in August of last year and the unitization agreement was also signed last year. And of course now we have commenced the constructions. And you will later in my presentation one of the highlights on Johan Sverdrup is the cost reduction in this environment.

Our capital budget for ’16 is just in excess of $1 billion that's a 26% reduction compared to 2015, most of it is really related to a development budget $936 million which is very much led by ongoing development drilling in Edvard Grieg and the Johan Sverdrup project. Our exploration and our appraisal budget is 147 million and that's a 64% reduction compared to 2015. Of course we have to be mindful about the current environment. We reduced some of our oil exploration program but also it's fair to say that the current environment will allow us to take advantage of the low cost such as re-grades, which reduces our cost.

Our 2016 operating cost as Mike mentioned to you, it's below $10 and that's clearly due to the fact that we're bringing on stream new projects such as Edvard Grieg. And finally, as Mike just mentioned, the RBL, very pleased of achieving, or of signing a new reserves-based lending of $5 billion with, as Mike stated, a firm commitment from 23 banks of $4.3 billion. That gives us a liquidity headroom of $760 million. So in essence we are fully funded down to $30 and for 2016 and we have significant available option for liquidity going forward.

In terms of the 2015 productions, our latest guidance was 32,000 and so we were within guidance with a production achieved in excess of 32,000 barrels of oil equivalent per day and we mentioned our exit rate of 75,000. I'm pleased to say that those were achieved. In actual fact we went as high as 80,000 barrels of oil equivalent per day towards the end of January, at the time the third producers of Edvard Grieg was brought on stream. Perhaps worth mentioning that Norway production by end 2015 was about 64% of the total production of the Group.

But moving on to 2016 and our production guidance, we guided to 60,000 to 70,000 barrels of oil equivalent per day. Clearly our production guidance going forward in ’16 is very much driven by Edvard Grieg. And you can see from the slide on the right-hand side that Edvard Grieg in ’16 will be over 50% of our total production. And the guidance also reflects a ramp-up of Edvard Grieg, which is not related to the capacity of the wells we’ve got plenty, but it is related to the ability to bring water injection towards the, as we are starting now towards the second half of this year.

Pleased to say that so far we’ve achieved good performance. If you look at the graph on the left-hand side, you see that in January we averaged 64,000 barrels of oil per day for the whole month of January, which is ahead of the 2016 production guidance. So let’s talk about Edvard Grieg, since as I stated, this is 55% of our production in ’16, Lundin has 50%, it is the operator, and we have OMV, Wintershall and Statoil as partners. Our 2P reserves today stands at 206 million, which is an increase of 20 million compared to last year and that’s the result of the appraisal program of last year, so very pleased with that result.

Plateau production 100,000 barrels of oil per day, which will be achieved in the second half of ’16. And as I stated, we achieved first of all ahead of the schedule on November 2015. Total capital cost 26 billion and that’s within budget. So really Edvard Grieg was a class book example of how a project should be delivered and executed and we came ahead of schedule and on budget. We are now in the drilling phase of Edvard Grieg and this will continue until end of ’17. And as I mentioned, the result of this appraisal last year again was a success and led to an increase in reserves.

This is, our picture is really that I am very proud, very proud for what the Norwegian team has achieved. And you can see that is a strong initial facility of reservoir performance. Since we started end of November, we achieved an uptime of 95%. That’s not good it’s absolutely exceptional for a new field to come on stream with such a high uptime. But you can see that uptime was just part of the picture and in terms of sub-surface and well performance, we did also very well.

We’re now on stream with three wells and we went as high as in excess of 90,000 barrels oil per day in gross production in Edvard Grieg. This is a fantastic achievement. And obviously this gives us a great confidence going forward and particularly in our ability to achieve plateau production of 100,000. But this high production will -- it’s not sustainable until we bring water injection in the ground. So again the guidance is based on the ramp-up and is based on our ability to start water injection, which was as per the plan and as per the plan of development. In 2016 we will see five new wells being drilled, three water injection and three producers. And currently we are drilling our first water injection well.

So let’s move to Johan Sverdrup. Johan Sverdrup is obviously now the key development project for Lundin Petroleum. Phase 1 gross production of approximately 180,000 barrels of oil equivalent per day, field center with four platforms and 35 wells, first oil on target for end of 2019, full field with gross results between 1.65 billion to 3 billion and with a gross plateau production between 550,000 to 650,000.

The key point really Johan Sverdrup is the largest Phase 1 development in the NCS. It’s probably one of the largest projects in the world executed offshore. And as I stated before, the PDO was approved and the fulfill reserves are now booked and net to Lundin it equates to in excess 50 million barrel of equivalent. The big story and I will perhaps describe that in more detail in the next slide, obviously the reduced CapEx, and that has got a big impact obviously on the breakeven oil price. So, as we’re moving forward Johan Sverdrup is increasing in value.

So let’s talk about Phase 1 development, the project is progressing on to schedule, major contracts and are awarded and pre-drilling will be starting very soon in Q1 2016 with production starting in late ’19. As I stated, costs are coming down. Phase 1 CapEx on the plan of development was NOK123 billion, and today we are coming with new revised cost of NOK108.5 billion. That’s a saving of 12% compared to the PDO.

And I certainly believe that this not the end of the story. I certainly believe that in this current market we’re going to see further cost reduction. I used to say that Johan Sverdrup is really sitting right now on the perfect storm, at a time where the market environment is very favorable to award contracts, and that will generate further value to all of you, the shareholders and the company.

Also we came -- we’ve approved the de-bottlenecking measures which will increase the capacity of Phase 1. And finally, you see on the slide the split of the currencies. You can see that actually a major part of our investment are NOK denominated and when I talked about saving, those are market-related, it doesn’t take into account any NOK saving. And as you know today, the NOK is, compared to the PDO, were NOK6 to the dollar, and today we are more like NOK8.59, so further savings on currencies.

Phase 2, we are moving. And the highlight, I would say, is that by the end of this year we will be approving the concept selection, and the production for Phase 2 is due to start in 2022. As we move to concept selection of Phase 2, obviously costs are improving and we have a better definition of the project. And, as you can see from the slides, all costs full field have reduced and now standing between 160 billion to 190 billion so again that's due to the market conditions, but it is also due to the fact that we're optimizing now Phase 2 as we moving forward.

Let's move now to highlights of 2016 development activity, very much led by Edvard Grieg and Johan Sverdrup. In Edvard Grieg we will be drilling-- continue to drilling of development wells, and of course in Johan Sverdrup we are executing our project. Those two really are the majority of our capital expenditure as far as development activity. We will have also a development well in Malaysia, which will start end of the first quarter of this year, and then other projects, minor projects in France and Netherlands, but very much budget-driven by Edvard Grieg and Johan Sverdrup.

On the exploration appraisal, we will be active in our core areas, core areas being Utsira High where we'll be drilling a well; in the Southern Barents Sea, where we going to see further explorations. We're going to re-entry a well which we couldn't complete last year because of the winter season coming. And we will be also busy in the Sabah in Malaysia with two more exploration wells. So a very focused approach, a reduction in the budget, but as I stated before, this is also due to the fact that we're taking full benefit of the market condition today with very low rig rates.

And this is really a picture that summarizes our -- what we've achieved so far with our organic growth and the benefit that we see now. Four projects have been delivered in the last 14 months, Edvard Grieg being the last one. 2015, average production just in excess of 32,000, 2016 guidance between 60,000 and 70,000 which is double the production of ’15, and that trend will increase. We will have a full year of plateau production in 2017 with Edvard Grieg, and of course, later on Johan Sverdrup and the full field and plateau which will reach 150,000. And that increase in production while all operating costs will continuously go down from below $10 and then continuously getting lower from that level because of this new projects coming in.

So, my conclusion, 2015 production achieved according to guidance in excess of 32,000 barrel of equivalent per day, our production guidance ’16, 60,000 to 70,000. In January already achieved 64,000, ahead of the guidance, our 2P reserves increased by 292% on the back obviously of the booked reserves on Johan Sverdrup. And then cost deflation, definitely we see the benefit of the current oil price, lower oil price environment, and we see major benefit on the Johan Sverdrup project we see generating higher values as we go forward and as we reduce our cost, and as Mike mentioned, very pleased with the RBL refinancing of up the $5 billion, which is giving us current liquidity of $760 million. And of course organic growth has been the key strategy for us and that's has generated a lot of value to shareholders and that strategy will continue with a major focus on the Southern Barents Sea and Utsira High and in Malaysia in the Sabah province.

With that, thank you very much and I guess we open for questions

Maria Hamilton

Open for questions, yes. Good morning, everyone. I think let's start with questions from the conference call. Do we have anyone ready to pose questions?

Question-and-Answer Session

Operator

[Operator Instructions] And we have the first question coming from Alex Topouzoglou from Exane BNP Paribas. Please go ahead. Your line is open.

Alex Topouzoglou

On Sverdrup, could you talk a little bit more about this de-bottlenecking, and what potential production rates you believe could be achieved from Phase 1?

Alex Schneiter

Yes. Well, the de-bottlenecking, is what I can say is that this will increase the capacity of Phase 1. The exact numbers, I don't want to give numbers here. I think it's for Statoil to come up and give the more precise information in terms of the numbers in the de-bottlenecking.

Alex Topouzoglou

Okay, so I'll wait for that. But then would it then be fair to assume, or now that you're working on Phase 2 and so on, would it then be fair to assume that you would exceed the 550,000, the 650,000 guidance for the full field capacity?

Alex Schneiter

No. I think you have to assume the 550,000 to 650,000 as being the guidance for now.

Alex Topouzoglou

Okay. And so then moving on to Edvard Grieg, given the strong production you've seen from the first three wells, is there anything you can do, similarly to this de-bottleneck of Sverdrup, that you could do on that asset to increase production beyond design capacity?

Alex Schneiter

Yes, I think right now the key is water injection. In order to maintain high production level we should be focusing on bringing water into the ground to replace the voidage from the production. So that's number one. In terms of the capacity itself, historically we know that the capacity, there's a good chance that we can improve this capacity. But that's something we going to see later on in the year once we go to full plateau production, and then we will be able to capture the system.

Alex Topouzoglou

Okay, so it’s something that’s for the future. And then finally, maybe just going to the RBL, could you tell me a little bit more about how you access the accordion feature, like bringing new people in and so on? About how exactly you get to the additional $700 million, please?

Mike Nicholson

Yes. So the initial commitments of 4.3 billion are from the 23 banks that we have and this is very simple. Either those banks within the new facility can increase their commitments further or through time we can bring in new banks with new commitments.

Alex Topouzoglou

Okay. So it’s just, but then it’s not oil price dependent or anything like that, it’s just if you can negotiate with the, okay.

Mike Nicholson

No, just to be very clear on that point, the $4.3 billion is not related to the borrowing capacity of the assets. That’s capped at the committed facility amount. As I mentioned, if we run our models unrestricted and assume a $5 billion facility, then we have the option to access up to $5 billion through time from the asset base.

Alex Topouzoglou

And are there any covenants on this RBL?

Mike Nicholson

Yes. As I mentioned, we’ve reshaped a more flexible covenant package to reflect the growth profile of the company but we don’t disclose all the details on this facility.

Operator

Thank you. And our next question comes from Julian Beer, SEB. Please go ahead. Your line is open.

Julian Beer

Hi. On the CapEx side of things, was the 2015 overall capital spend lower than you expected and was that relating to a reduction of work programs or do you have some items to be expensed during 2016?

Mike Nicholson

Yes. Let me take that question, Julian. I mean there’s a mixture of both. One of the biggest factors which is the other side of the weak Norwegian krone, on average our capital budget, and you’ll see the full reconciliation later this afternoon at our Capital Markets Day, the big picture we were down around $300 million from our budget levels. And around $200 million of that $300 million was down to foreign exchange savings. Then the balance was down to phasing in changes and work program. But we’ll have more details this afternoon at our Capital Markets Day.

Julian Beer

Okay, great. Do you actually know that there is some amounts to be expensed during Q1?

Mike Nicholson

There's always some differences in working capital movements between the time and the value of work done and when we actually physically settle the bills. So some slight phasing differences in there as well.

Julian Beer

Okay, but nothing significant?

Mike Nicholson

Nothing significant, no.

Julian Beer

Very good. And then for the Brynhild and Bertam fields, you’ve impaired value. You’re using a lower test scenario by the look of it. What is your impairment oil price scenario?

Mike Nicholson

So what we’ve done, because those fields are short-term plateau producing fields in nature, we decided to take a fairly conservative approach. So what we applied for the first two years was the forward curve, as at the end of December, and then we've used the longer-term price deck in line with our reserve estimators assumption.

Julian Beer

Okay, that’s clear. Do you have any remaining book value for those fields?

Mike Nicholson

Yes we do.

Julian Beer

For both of them?

Mike Nicholson

Yes.

Julian Beer

Could you say how much?

Mike Nicholson

No we don’t disclose individual book values by field.

Julian Beer

Okay. All right, great. Then finally from me, for the year 2016 production profile, what sort of uptime are you assuming for Grieg in the second half? And if you could talk a little bit about how you see Bertam production profile during 2016 that would be good too.

Alex Schneiter

I mean, we don’t give detailed numbers in terms of uptime for Edvard Grieg. But as you know, we anticipated to reach 95% uptime by, pretty much, the summer of this year and right now we’re already at those levels as you’ve seen from the end of November to now, we’ve achieved an average of 95%. So that should give you a certain level of confidence of the, or ability to achieve a high uptime, so that’s in terms of Edvard Grieg. In terms of Bertam your questions, can you repeat Julian, I’ve forgot.

Julian Beer

Yes, sure. How do you expect the production to trend during 2016?

Alex Schneiter

Yes. I think the production will stay pretty much where it is. As you know we’re going to bring the last development wells, the A15 wells soon and that will allow us pretty much to halt the decline and stay pretty much on the current level.

Julian Beer

Okay, that’s great, looking forward to the presentations this afternoon. Thanks very much.

Operator

Thank you. And the next question comes from Teodor Sveen Nilsen, Swedbank. Your line is open.

Teodor Sveen Nilsen

Good morning and thanks for taking my questions. First a question on Sverdrup, you already booked 2P reserves on Sverdrup. Could you indicate what kind of recovery rate you have assumed for the reserves you have booked?

Alex Schneiter

Yes, it’s really an average. But on this type of 2P, you can assume an average of about 63%, plus or minus. So of course we expect these numbers to improve with time.

Teodor Sveen Nilsen

Okay. Can you indicate if you see different assumptions for the three-year licenses in Sverdrup?

Alex Schneiter

Three years?

Teodor Sveen Nilsen

There's three different licenses, PL265, [PL501] and --?

Alex Schneiter

No, no it's one. This is generic, it's one unit. The Johan Sverdrup is one unit, it doesn't change between one block to the other.

Teodor Sveen Nilsen

Okay, that's fair. And then just one question on the write downs, so you addressed those somewhat but could you indicate if the lower oil price scenario has reduced the reserves you have booked on Brynhild and Bertam?

Mike Nicholson

Yes, I wouldn't say there's been a significant movement in the oil price. As I mentioned in the answer to Julian's question, we took a forward curve assumption for the first two years to take a fairly conservative approach. But we've stuck with our reserve estimators' long-term price deck, so there hasn't been a huge change in our reserves on the back of oil prices.

Teodor Sveen Nilsen

Okay. And then just finally on the covenant package for the new RBL, is it fair to assume that it's some kind of net debt to EBITDA before expiration covenant or could you give some more details on the covenant package?

Mike Nicholson

We're not going to give full details as I mentioned on the overall covenant package, but what we have done is in the initial projection, given the growth profile that the Company's under, we've shaped the covenants to reflect that position.

Operator

[Operator Instructions]

Maria Hamilton

Okay, I'll step in with some questions from the internet. Madsen wonders is there a drilling rig secured for the Barents Sea drilling program 2016/2017.

Alex Schneiter

Not yet but of course we're actively looking. We stated before that we are going to look for a rig to start drilling in the southern Barents Sea and we have a lot of options in our hand so, contrary to two years ago, we're perhaps not in a hurry, but we will be contracting a rig soon.

Maria Hamilton

James Hosie, Barclays, has a question regarding the RBL. What is the current borrowing capacity of the assets?

Mike Nicholson

Well, the current borrowing capacity with this 4.3 billion committed, we can fully access up to the 4.3 billion. But as I mentioned if we exercise the accordion option and push that up to 5 billion, then our assets have the capacity to generate 5 billion of borrowing capacity.

Maria Hamilton

Niki Kouzmanov, Jefferies has a few questions also. The Norwegian exploration facility seems to have reduced, what are the drivers for that?

Mike Nicholson

That's quite simple; at the end of 2015 we actually received the cash tax expiration refund from the Norwegian authorities. It was a two-year facility so we used the proceeds to repay that part of the facility, so now the $250 million of availability represents the tax refund that was due in December 2015 but paid at the end of December 2016.

Maria Hamilton

Regarding Johan Sverdrup cost savings, how much, as a percentage of the original budget, were the contingency estimates and have they changed in absolute terms as part of the announced cost reduction?

Alex Schneiter

We're not releasing specific figures in terms of contingency. All I can say is that our contingency figures haven't changed and the reduction is pure market driven.

Maria Hamilton

Tony Dunfeld has a question regarding Edvard Grieg Production and he is wondering with a very strong production that we have achieved so far, will we see higher production than 100,000 barrels per day by the end of the year?

Alex Schneiter

Well I've just stated the plan and the guidance is based on ramp-up and the ability to bring water injection in the ground, and the plateau is 100,000 and that's the guidance we're giving. Now of course as we've seen in the past and from our experience, new facilities have the ability usually to increase their capacity but that's something we will be testing on the second half. So this time I will stand with 100,000.

Maria Hamilton

Question from Johannes Grunselius, Handelsbanken, could you indicate what interest costs you had on the new RBL?

Mike Nicholson

Yes, I think that was covered in the presentation so the interest rate is US LIBOR plus a margin of 315 basis points currently.

Maria Hamilton

Then a last question from Adam, is it feasible to connect Luno II and PL 338C on joint production with Edward Grieg and how soon?

Alex Schneiter

Yes, definitely it's feasible. We're currently doing our studies on Luno II and we'll be doing also studies on the latest discovery, south of Rolvsnes and so those are potential tie-back to Edvard Grief facilities, definitely. Now we have to do our studies, we're just starting so it's early days. In terms of when they're going to start, I think it's a bit - it would be early for me to give any specific dates, but it's definitely a potential tie-back to the Edvard Grieg facilities.

Maria Hamilton

Thank you. From the conference call, do we have any more questions?

Operator

There are no further questions registered on the conference call.

Maria Hamilton

I have no further questions from the internet either. So with that, I would say thank you very much for listening in to this morning's presentation and feel free to fire off any questions you may have to us afterwards.

Alex Schneiter

Thank you very much.

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