Tullow Oil's (TUWLF) CEO Aidan Heavey on Q3 2016 Results - Earnings Call Transcript

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Tullow Oil Plc. (OTCPK:TUWLF) Q3 2016 Earnings Conference Call January 11, 2017 4:00 AM ET

Executives

Aidan Heavey – Chief Executive Officer

Paul McDade – Chief Operating Officer

Analysts

Brendan Warn – BMO Capital Markets

Stephane Foucaud – GMP FirstEnergy

David Mirzai – Deutsche Bank

Rafal Gutaj – Bank of America Merrill Lynch

Michael Alsford – Citi

Dhersan Chetty – BlueBay

Caren Crowley – Davy Stockbrokers

Mark Wilson – Jefferies

Al Stanton – RBC

Duncan Milligan – Goldman Sachs

Joe Head – UBS

David Gamboa – Tudor, Pickering, Holt & Company

Brendan Warn – BMO Capital Markets

Thomas Martin – Numis

Saahil Dey – BNP Paribas

Stephane Foucaud – GMP FirstEnergy

David Mirzai – Deutsche Bank

Operator

Good day, and welcome to the Tullow Oil Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Aidan Heavey. Please go ahead, sir.

Aidan Heavey

Thank you all for joining us this morning. Before I start it, I'd like to thank you all for the messages and the well wishes that Ian has got, and his family; his treatment is going well, he's in good spirits. His family want to pass on his thanks to all those who've sent messages. Les Wood is with us here today, who will answer the financial questions. I'd like to just talk to you about the Ugandan deal and the Board changes and then I will hand you over to Paul who will take you through the trading statement.

The Uganda deal, it was a very important deal for us and I think if you look at the last few years when we were – we set about a process of resetting the business, of getting our cost structure down. And a key part of that was to look at the assets that we had, like Uganda, where we had a very valuable resource. But, really, the issue was how do we get that producing and how do we get it developed? And there's two aspects to that: it's getting done as quickly as possible, but also the huge amount of capital that would have been required by us to keep our third stake.

So, farming down to Total was the ideal choice. They're a fantastic operator and they will drive this project forward very, very quickly. So we saw this as a two-win for us. One is that we get the resources developed faster and better; and secondly, it takes out of our thinking a huge capital spend over the next three years. The impact of the deal is, obviously, we get $100 million up front and then $50 million at FID. But also, within the first 12 months, that will mean that we'll probably have a cash saving of around $300 million, which is the capital spend that we had originally budgeted for the project.

So, it's a very beneficial deal for us. It allows us now to really complete what we've started two years ago. And with that deal done, we can now set down and move forward, as a business, and look for capital growth again. We have the opportunity now to deal effectively with our banks in relation to our refinancing, and get the balance sheet in a fit state for the period of growth which we see coming forward.

With Uganda complete, we felt that the main task that we had set ourselves for the two years, as I say, has been done. And, as I said two years ago, I'll see through this cycle. And so we felt it was important that we started this whole new cycle with the new management team with a fresh way of thinking, with a fresh approach. And he Board went through a proper process of succession and, obviously, Paul was the outstanding candidate. It offers us a very good way of moving the business forward in a very smooth way. Paul, obviously, has – is known to most of you, and he has a clear understanding of the business, the strategy.

And, very importantly, in Africa and in the areas; our relationships are very important. And I think what we have now is a very smooth transition. I've agreed to step up to Chairman for two years to help in that transition. I think it's – the whole process is aimed, really, to capitalize on the strengths that we've had in the past. But also to have a whole fresh approach as we move forward into this period of growth.

On that, I'll hand you over to Paul who’ll take you through the trading statement.

Paul McDade

Thanks, Aidan. Yes, I really was going to just pick out the West African points in the trading statement, and then we'll pass over to Q&A. I think on Jubilee, just to report that the transformation of the vessel to a temporary spread-moored vessel is on track and we expect the vessel to be spread moored by the end of January. The next stage for 2017 is then just setting up the vessel for the long term as a spread-moored vessel.

We've indicated in the statement that it could be up to 12 weeks of shutdown to do the work that is necessary really to set up the vessel up for the next 15 to 20 years. However, we are hopeful that we can optimize that period and potentially reduce it. However, from a Tullow perspective, we've guided production – net production to us of just over 24,000 barrels a day; and our business interruption insurance, which will cover the losses due to the turret remediation work, to be circa 12,000 barrels a day, giving us a net of about 56,500.

Obviously, as we reduce the production – sorry, as we reduce the shutdown and then subsequently we see increased production, if that's what was to happen, we would be still the same at the total net, because for any barrels produced then they wouldn't be paid out as a BI. So, for Tullow particularly, we're insensitive from a revenue perspective to the length of that shutdown. However, obviously from a partnership point of view and from an insurance point of view, we're very focused on how to optimize that and reduce it. But really the conversion is going very well and we're looking forward to a good solid year on Jubilee in 2017.

On TEN, the commissioning work is now complete with all the systems fully functioning. We did a production test, short-term 24-hour production test on TEN in the last week and we averaged over 80,000 barrels a day for that test. In fact we hit levels of 90,000 barrels a day within the test. So the FPSO is operating very well and it's clear that the capacity of the FPSO is – it looks like it's in excess of the design capacity that we planned for 80,000 barrels a day.

With respect to the data we're getting from the wells, very happy with respect to that data from a reserves' point of view, all indicating that reserves are what we expected them to be in Ntomme and Enyenra. However, the forecast we've put out today for 50,000 on average for the fact that we cannot add additional production wells in the field due to the boundary dispute in the ITLOS ruling.

And on that bit, given that we can add wells, we have to work with the well stock we have through 2017. And we've decided from the data we have to take a prudent approach to that, certainly to start 2017 and produce the wells in a manner that we think will be sustaining around 50,000 barrels a day.

Now there clearly will be opportunities, we hope to improve upon that but we think 50,000 barrels a day is a good prudent guidance for the TEN field for 2017 at this time with limited number of months that the field has been on stream. So really that's the kind of main points that I'd like to get across from the trading statement and I'm sure we'll cover many of the other points that are in there in the Q&A.

Unidentified Company Representative

Okay, we'd like to turn the call over to Q&A now. We have over 100 people on the call, so as usual could I ask that we just have one question per person, we have a hard stop at 10:00 O Clock at the latest. Thank you very much.

Question-and-Answer Session

Operator

Thank you. [Operator Instructions] Let me now take our first question from Brendan Warn of BMO Capital Markets. Please go ahead.

Brendan Warn

Thank gentlemen and congratulations, Paul. Just one question. Just to clarify on TEN in terms of the Ghana CapEx budget, the $90 million that you split out. So I take from that there is zero CapEx committed to TEN and no assumption of any well even in the late fourth quarter 2017?

Paul McDade

Basically, the CapEx that's in there is really more associated with some opportunities we're taking while we're likely to have some shutdown periods within Jubilee, to do some upgrade work to the FPSO. So some of the capital is associated with that, some of it's just regular work that we'll be doing on those vessels. And there is CapEx there, because clearly our intention is to start drilling again in either Jubilee or TEN or both, as we move into 2018. And clearly there's capital required for long-lead items and preparation work in getting ready for startup. So that startup capital is within 2017 to prepare us for our January start in 2018.

Brendan Warn

And in a worst case scenario, if ITLOS has ruled against you what's the downside – what would be the average production from TEN in 2018 assuming no new wells?

Paul McDade

Yeah, I think in the terms of the ITLOS ruling there's a fixed schedule which will give a ruling in the kind of third, fourth quarter of this year. So the drilling moratorium has been put in place while the uncertainty over the boundary is there. Once the ruling is given, there will be then certainty over the boundary and that drilling moratorium will be lifted. So regardless of the outcome, we expect to be able to reach that drilling in 2018. And then, depending on performance in 2017, we'll then start to be able to build up the production capacity as we add wells in 2018.

Brendan Warn

Okay thank you. I'll leave it there.

Operator

We will take our next question from Stephane Foucaud from GMP FirstEnergy. Please go ahead.

Stephane Foucaud

Good morning guys and assuming the moratorium is lifted in Q4 2017 and things are according to plan and drilling restarts at TEN, where would you see the plateau production coming, being at TEN. Would you see things potentially up going to 80,000 barrel per day or would you say something a bit more cautious? Thank you.

Paul McDade

I think the fact that we've done the production test is very reassuring because what we've shown is the FPSO is capable of in excess of 80,000 barrels a day. So basically the determination for 2018 will just be a matter of working out where are we as we exit 2017 and how many wells do we require to add to get up to plateau and the pace at which we add wells. So we would really expect to get TEN back up to 80,000 barrels a day plateau. And the timing of that really will be determined by the exit rate of 2017 and the pace at which we add wells.

Stephane Foucaud

Thank you.

Operator

Our next question comes from David Mirzai of Deutsche Bank. Please go ahead. Please go ahead you line is now open.

David Mirzai

Good morning Paul. Sorry to drag it out, but you came to market back in July, you gave us guidance there that the production for 2017 on TEN was expected to be 65, although I appreciate we're going into the year with a lower production than you'd previously thought. I don't get how nothing has changed. I don't get how you can say now that you're being more prudent than you were back in July if the reserves are the same, you've drilled the same number of wells and the ITLOS ruling is still in effect?

Paul McDade

When we gave the guidance last year prior to the fuel coming on stream, we indicated that we'd made our best estimate from the static data we had from the field. Clearly as the wells came on stream, we started to understand the productivity and the injectivity of each individual well. And as we've now seen and we indicated in November that the early data we had, at the interim statement in November the early data we had was suggesting a little bit more downside from the 65 and certainly not upside. And what we've done is continued to test the reservoirs, so really what we see in Ntomme is productivity on the wells, in terms of injectivity and productivity, very much in line with what we expected.

And then Enyenra we're seeing the injectivity and productivity of the wells is slightly below what we anticipated. And the fact that we can add additional wells, as you would normally do, remember in Enyenra we only have six wells, three producers, three injectors. The development plan in Enyenra is to have 15 wells. So we're way short of the number of wells we had expected. So that's really what's changed, the productivity and injectivity of the individual wells in Enyenra are slightly below expectations.

Not a great problem in terms of the ultimate recovery from those wells, but it is a challenge in the short term because the ITLOS ruling says we can't add the additional wells we need.

David Mirzai

But again, Paul, you already knew that you couldn't add those wells and your number's gone down from 65 to 50. Now the way I look at it that means either two things; that means either those individual wells will produce less and therefore you'll have to drill more wells, which therefore isn't the same as the development plan and will be a change in 2P reserves; or those wells will produce over a longer period of time at a lower rate and therefore that would affect the economics of the project, as per my numbers, as per your original guidance.

Paul McDade

Yes. So the way maybe to look upon it is, if you look at wells, say, on Jubilee, on Jubilee we've got wells that have sustained 20,000 barrels a day and they're still pumping 20,000 barrels a day and we've got other wells in the same field that are down at say 5,000 barrels a day and they've been continually producing 5,000 barrels a day. When you add all up, that determines the number of wells you need at any one point. So in TEN we had anticipated that the injectivity and the productivity of the six wells we have in Enyenra were going to give us more oil in an instantaneous basis in the short term for 2017 than actually is the case.

So as I indicated, the injectivity and the productivity of the individual wells is lower and really we had always planned that we would have 15 wells in Enyenra. When we were told we had the ITLOS ruling, clearly we were then left that we would only have six wells through the initial period of 2017 as the field started up.

So really in a normal situation what you'd be doing at the moment is saying you've got lower rates from these wells but the plateau of each well will be longer. So ultimately the individual well will produce the same amount of oil that you anticipated, it will just take a little bit longer from that individual well. And then you would be requiring to hit your 80, an extra number of wells. And that's always an indeterminate in any oil field until you get the field on stream. So, reserves we're quite confident reserves have not changed but the Enyenra wells are producing a bit less than we anticipated.

David Mirzai

Lowest, longer I've heard that phrase before. Thanks kindly, Paul.

Operator

We will now take our next question from Rafal Gutaj of Bank of America Merrill Lynch. Please go ahead sir.

Rafal Gutaj

Good morning everyone, just a quick question on a similar theme, I'm afraid. Just on the new guidance number of 50,000 barrels a day on TEN, can you just give us a number of how much of that comes from Enyenra and how that compares to your previous number of 65,000 barrels a day? And then part B of that is just, are there any artificial lift options that you're exploring on that part of the field ahead of bringing a rig back in 2018? Thank you.

Paul McDade

Yes. The split on Enyenra and Ntomme is something that we're still moving around, in terms of we're really – because we continue to optimize the wells and we've got multiple layers and multiple layers in each of the reservoirs and we're looking at continually trying to optimize. But at current levels, it's probably around kind of 50/50 from Enyenra and Ntomme, but not exactly. And that will continually evolve as we optimize the production injection from the two reservoirs and all the individual wells. These wells wouldn't benefit from artificial lift and it would be a very expensive short term – or quite capital intensive short-term fixture to accelerate some oil from 2018 and 2017.

So really, as I stated before, the real challenge here is more ITLOS and just the ability to add wells. If you go back to the original development plan, at this point in time we would have had more wells available to us in Enyenra to meet the plateau.

Unidentified Analyst

Great thanks. That’s clear.

Paul McDade

Thank you.

Operator

The next question comes from Michael Alsford of Citi. Please go ahead.

Michael Alsford

Yes thanks for taking my question. So maybe changing gear a little bit, just wanted to get a couple of comments on the Uganda sale. I suppose from my perspective it was probably a bit earlier than expected in terms of securing the deal and I'm just wondering if you could give a bit more color as to whether this was a competitive process, whether there was other interested parties and why maybe you didn't wait maybe to try and structure a deal where you saw a bit more cash up front, rather than the deferred consideration? I guess I was expecting perhaps Uganda would help to reduce some of the debt position that you have today, but there was only a small improvement on that, given the only limited upfront payment.

And if you don't mind, sorry, just a second part. Just a quick clarification on Kenya. What would you say is the P90 case today and what do you think you need to get to in order to secure the banking financing to commercialize the project? Thanks.

Aidan Heavey

I'll take the first part of that and I'll give the second part to Paul. I think the – we looked at Uganda and we basically felt that the best way to get the reserves moving and get to FID faster – to first oil faster, was to sell part of our stake to Total. So it was not a competitive process. We did talk to Total because we felt that they were the best party to drive this forward and the bigger stake that they had in this project, we felt the better for the project. Also the fact is that it's – you have pre-emption rights within the licenses and you needed government approval and taxation approval, et cetera.

So we felt that by moving this way we were going to get the project moved faster. And it was in everybody's benefit, both Ugandans and ourselves and our partners, that we streamline that position between all the parties and that we get a share of the pipeline, et cetera, so we're all aligned. In relation to the actual cash versus – upfront cash versus a carry, it really was a toss-up. We felt that the amount of cash that we were getting and the savings that we were getting in capital spend were ample for us. The most important thing for us was to drive this project forward and see a very clear line of sight through to getting 23,000 barrels of oil a day in a low cost field. And that leaves us in a very strong position, as a Company, with very little capital expenditure going forward and at a greater position to refinance our balance sheet.

Paul McDade

Just picking up on the second point on Kenya. Clearly we're back to exploration drilling in Kenya because we want to understand the full extent, and are quite excited about that northern area after Etom-2. I don't know that we've actually publicly stated a P90 number but I know in the Africa Oil Competent Person's Report, off the top of my head, I recall the number being around the 250 mark, 260, that sort of level. Clearly we would like to see the P90 level come up. At P50 we're very commercial in Kenya already, without any additional barrels from the new exploration wells. The exact number as to you need to sanction the project to P90 is a moving feast, in terms of as we look at costs, look at pipeline costs and look at the financial structure around the deal.

So I think our view is, we do want to try and push that P90 higher, we don't feel it has to go substantially higher than where it is at the moment, and especially in the case where we see oil prices starting to recover.

Michael Alsford

Okay, thanks Aidan and thanks Paul.

Operator

Our next question comes from Dhersan Chetty of BlueBay. Please go ahead.

Dhersan Chetty

Hi good morning. Just a quick question. Given that Uganda's probably realized less upfront proceeds than you'd expect in relation to the earlier comments around it being a major catalyst for your balance sheet restructuring, I was just wondering, with TEN production also being guided lower, Uganda yielding less, would you consider a rights issue to cure the balance sheet? And maybe you could provide us a bit more detail around what exactly is your deleveraging process from here?

Aidan Heavey

Yes, we were very clear for the last few years what we started doing and that was a process of self-help and basically we wanted to use the opportunity of this downward cycle in the oil industry and these low oil prices, to reset the business and to have a business that was very effective and worked well at low oil prices. And part of that process is to make sure that the assets that we have match the Company and match the balance sheet and match what we want going forward.

So, our first target was to get the Company right. We did that – or we completed that last year. The next thing was to start looking at the assets, the assets that – we have two types of assets; we have development assets and we have production assets. The development assets, we wanted to make sure that the capital that we – the cash flow that we had, was not all going to be ploughed back into long-term development.

So we needed to get that out of the way and – but also at the same time to make sure that, as we said, that those assets produce as quickly as possible. So it was an obvious decision to go and talk to Total, give them a bigger stake. We felt it would be easier to get approvals and do it early this year so that they can achieve their target of FID at the end of this year. So that was an obvious thing to do and it had an obvious fix to us as well because over a 12-month period it had a positive effect of about $300 million to us.

We have other assets where we have 50% and when ITLOS is out of the way we will look at other disposals. But we're in good shape. This was the key one and this is what we needed to get on. And it's something that, when we're looking at the redetermination with our banks later on this year, they view things like this incredibly positively.

So I think it takes the pressure off us and it allows us to get on with the capital growth and changing the business from a restructuring of business and resetting it to a business that's now finally going forward again.

Dhersan Chetty

Okay all right. Thank you.

Operator

Our next question comes from Caren Crowley of Davy Stockbrokers. Please go ahead.

Caren Crowley

Good morning. Thanks for taking my question. Sorry to go back to TEN again but, Paul, I was wondering, with respect to the remaining 13 wells that have yet to be drilled, can you reposition those wells, in other words tinker with the field design so that those remaining wells possibly could be optimally positioned to recover more than they were originally intended to recover, and in that way try and maintain the capital efficiency of that project?

Paul McDade

Caren, I think if you go and ask the reservoir engineers who've got more of an eye on data and optimization of positioning wells, I wouldn't say that they're happy that they're not having to drill the wells yet. But their point would be, we're going to have a year or 15 months' worth of data and that absolutely is going to allow them to position the wells optimally. I think in the end that will be what it will be and we'll look at the performance of the field, and for sure there will be a benefit, the fact that they're not having to make those early decisions early. Obviously if we had freedom of choice then we would be out there drilling the wells because we know roughly where we need to.

But your point is correct that the wells will be more optimally positioned given the fact that we'll have 30 months or thereabouts of data, when we have to select those well locations.

Caren Crowley

Okay, so you're not committed to defined well sites, Paul?

Paul McDade

No, we have complete flexibility. The subsea architecture is quite extensive and we have complete flexibility about where we can position those wells within the reservoir.

Caren Crowley

Okay, thanks a million and congrats.

Operator

Our next question comes from Mark Wilson of Jefferies. Please go ahead sir.

Mark Wilson

Hi good morning guys. Well done on the Uganda deal and the retained carriage stake. Can I ask, though, what the farm-down of Uganda contingent resources may do to the RCF? And also is there any tax payable on that deal? Thanks.

Aidan Heavey

Well, it should improve the RCF. It was – the RCF was partly secured by it. It will have an effect on the quantum of it but what's left of the RCF will be better secured so we could probably extend it. And in relation to tax, the deal is structured in a way that there should not be any tax.

Mark Wilson

Okay, very clear. Thank you and good luck in the new roles.

Aidan Heavey

Thank you.

Operator

The next question comes from Al Stanton from RBC. Please go ahead.

Al Stanton

Good morning, sorry to stick with the TEN field. Just a couple of things. I can't remember the timing of the wells and the ITLOS ruling, but when you drilled these six wells, did you know that they were going to be the only six wells? Or did you start drilling the campaign and realize then that you had to stop and actually if you knew you were only going to drill a handful of wells you wouldn't have drilled these particular wells?

Paul McDade

I can’t remember the exact detail but we effectively went through a campaign of drilling and then a campaign of completion. So I'm guessing a little off the top of my head but a number of the wells would have been drilled and in fact – actually, let me correct myself. All the wells would have been drilled because the ruling was we couldn't drill any additional wells, because I was just thinking the activity. So basically we were allowed to complete the wells that we were doing and we were allowed to go on and do completions because the ruling was, you cannot add any additional wells, you can't do any additional drilling. So I correct myself there. So we had – the wells were predetermined when the ruling came.

However, I think if the ruling – if we had known about the ruling, I don't think we would have put the wells in necessarily different places. I mean as you know, these types of reservoirs, they can have variation in terms of the productivity. They are quite prolific reservoirs. But as I said before, in Jubilee, depending on the well and the location and how it turns out, we've got wells that are producing incredibly well, like 5,000 to 8,000 a day, and wells that are sustaining 20,000 barrels a day. It just depends on how the reservoir performs and how it's been supported by the injectors.

Al Stanton

Can you give some guidance on what we just should expect within the year? I mean to some extent, some people are probably thinking that it's going to start at 80 and finish at 20 and average 50. Or actually having tested 80,000 to 90,000 barrels a day, have you reined it back into 60 and you're going to average 60 over the course of the year? What's the profile going to look – on a half or quarterly basis through this year?

Paul McDade

Yes. So what we've done is we've been spending quite a bit of time in the latter part of last year testing the wells and testing the various zones and we've basically pulled the wells hard for the production test because it was really about the capacity of the FPSO and seeing how far we could push that. And then, now what we've done is we've dropped the wells back down and we've taken the approach that we want to try and best estimate what is a sustainable rate. You know yourself, these wells, once you set them at a certain rate, they can run for a number of years at that rate before you get any water breakthrough or any gas breakthroughs. Some wells in Jubilee are still producing at the rate that they started and still haven't seen any reduction.

So the approach we've got is – I'm going to say that the profile will be absolutely flat but we don't expect a decline in profile, we expect to set off at a level of around 50,000-odd barrels a day and maintain it there for the year. If we get encouragement, we'll turn that up, and that's where we're kind of hopeful we can continue to optimize the position through the year.

Al Stanton

Thanks, Paul.

Operator

Thank you. The next question comes from Duncan Milligan of Goldman Sachs. Please go ahead.

Duncan Milligan

Good morning. Thanks very much for the question. I was just wondering, with a fewer number of wells producing, does that mean that the water injection rate at the FPSO is proportionally reduced or are you injecting the full capacity of the FPSO at the moment?

Paul McDade

The facility – we've tested the facility because we can test the pumps on recycle, et cetera, so the facility can produce at the maximum rates required. So that's all tested. As I mentioned in one of the earlier questions, it's not just about the productivity of the wells; it's about the injectivity. So the amount of oil that comes out of the ground is determined as much by the amount of water you put in the ground. And we're finding the injectivity a little bit lower per well and then that had a knock-on effect that the productivity will be a little bit lower. So from a facility point of view we have the capacity to inject at very high rates. From a well stock point of view, we have a limited number of wells and therefore we're limited in the amount of water we can put in the ground. That will change when we add additional wells.

Duncan Milligan

And are you able to just say roughly what percentage of the water injection capacity is currently being used, and what upside there is to that?

Paul McDade

Well, in terms of the – if we say we're going to produce 50,000 barrels a day, we would be injecting about 70,000 barrels a day, and we've probably got capacity to inject 150,000 or 170,000 barrels a day. So we're only using about 50% of injectivity capacity. So there's plenty of capacity to turn up, once we have additional wells.

Duncan Milligan

Thank you.

Operator

The next question comes from Joe Head of UBS. Please go ahead.

Joe Head

Thank you. And one question on Uganda from me. I think previously you had talked about bringing external equity partners into the pipeline; the language in Monday's release, however, seems to suggest it's going to be funded by a combination of equity from the existing partners and project financing. My question is, is there a certain level of Tullow equity participation you need to be sure that you are able to access the full $700 million of development carry from Total? Has that driven the decision to move away from looking for external equity partners?

Aidan Heavey

No, the actual deal is structured in a way that there was an alignment between all the partners. So, for example, assuming government buy-back, we would have 10% of the upstream and 10% of the pipeline. And that basically means that the pipeline will become – you'll treat that the same as a capital cost to develop the field. The way that the partners are looking at the pipeline is that it would be financed about 60%, 40%; 60% debt and 40% equity.

Joe Head

Thank you.

Operator

Our next question comes from David Gamboa of Tudor, Pickering, Holt & Company. Please go ahead.

David Gamboa

Hi, thanks. Good morning. I had a question around Jubilee. You mentioned in the release that you're still determining if the FPSO will require a rotation and you expect to reach a decision and approval in the first half of this year. I was wondering if you need the decision and the approval before starting works on the up to 12 week shutdown, or is that independent? I'm just trying to figure out the timing of this potential shutdown. Thank you.

Paul McDade

Yes, thanks. Basically that is an important decision for us and we would take that decision ahead of the shutdown, because the shutdown, were we to rotate some of the work that we do during that shutdown, would be about the rotation, there's other activities that we also have to be doing during that shutdown. So, I think the best way to think about it is, in the first half of the year we'll be finalizing the actual activity set that we're going to do in the shutdown, including whether we rotate or we do not rotate. We'll be putting in place the normal partner and then government approvals for that work, and then we'll execute the work towards the end of 2017. So the shutdown period is likely to be more towards the end of 2017.

David Gamboa

Thank you.

Operator

[Operator Instructions] Now we will take the follow-up question from Brendan Warn of BMO Capital Markets. Please go ahead.

Brendan Warn

Thanks guy. And sorry for a follow-up question. Just with Uganda, what else actually needs to be done for the partnership to take FID, is FEED finished, have we got further environmental work to be done? How much of a stretch is it for Total to say it's ready for FID by end 2017?

Paul McDade

It's Paul here, Brendan. In terms of the further work, a lot of the environmental work, which is obviously, or normally on the critical path, a lot of that work has been done, it continues but it's well advanced. All the pre-FEED work on the pipe and the facility, the processing facilities in the upstream project, has been done. We're – actually there was an announcement locally, I think, yesterday or the day before, about the award of FEED for the pipeline. And also the expectation is we'll very soon award FEED for the upstream as well. So we're in that kind of very final stages of FEED. And if everything was to run smoothly, it's tight between now and the end of the year for sanction and FID, but it is possible, given the schedule we have, if it goes to plan on both the pipe and the upstream.

Brendan Warn

Okay, perfect. Thank you.

Operator

We will now take our next question from Thomas Martin of Numis. Please go ahead.

Thomas Martin

Hi, I wonder if I could ask on the disposal strategy, obviously you've disposed of your stake in Uganda. You've previously spoken about selling down stakes in both Uganda and Kenya; you also have the big stake in TEN, so you've got lots of opportunities within the portfolio. And I think Aidan mentioned also you've got 50% stake in West Africa, earlier on in this conference call. Could you talk a little bit about your prioritization for, let's say, sell down of Kenya versus sell down of your stake in TEN and how might the production, let's call them issues that you're facing at TEN, feed into that process. Presumably you'd want to get those resolved before you got the best price for a stake sale in TEN? Thanks.

Paul McDade

Yes, as Aidan said, I think the big deal to get done this year was Uganda, given what we just said about moving swiftly towards – FID towards the end of this year. I think the next point of focus is very much Kenya; we're back to drilling, both exploration and appraisal, we're kind of excited about, as I said for that Norrland [ph] area, given the Etom-2 – the very positive surprise we got at Etom-2 and what the 3D is starting to show us.

So I think our focus in Kenya is, what we've got to do is kind of really work out how big the Lokichar business and what's the prospectivity to north and then get the development advanced. We have a very major stake in Kenya, we've got 50%, so there is space for us to reduce our equity at some point in Kenya if appropriate, so that's something that we will continue to consider. But it's not our focus at the moment; our focus at the moment is very much pursuing Kenya, moving it forward, getting E&A done and getting the full field development ready and progressing towards – through FEED. And obviously we've got the early oil which we're pursuing this year as well, which will give us more data and more information and fully understand what we've got there.

And then I think, as Aidan said earlier, within Ghana, really we've got the ITLOS ruling to come at the end of the year. And once we're into 2018 when both fields are pushing back up towards plateau, then we can always give some consideration to what we do within Ghana. So no short-term plans at the moment, but plenty of opportunities as we head towards – through 2017 and then into 2018.

Thomas Martin

Thanks.

Operator

The next question comes from Saahil Dey of BNP Paribas. Please go ahead. Saahil Dey of BNP Paribas, please go ahead. Your line is open. [Operator Instructions]

Saahil Dey

Hello, can you hear me? Hello?

Paul McDade

Yes, we can hear you.

Saahil Dey

Good morning guys. Just wanted to – given the amount of strong liquidity you have now on your balance sheet, how are you thinking about your existing bonds and whether you're thinking about – and does that tie in regarding your refinancing discussions, when you have your RBL determination coming up in March? How are you guys thinking about that?

Aidan Heavey

Well, bonds have always been a part of our financing strategy. And the bond market has been closed for a while. But, as you are probably aware, it has opened again and bond rates are coming down. So it is something that we've done in the past and it's something that we could do in the future but it's part of our strategy.

But the thing about Tullow now is that, our period of building that is gone. We're now in a period of reducing our debt and converting the debt that we want to keep into long-term debt, so bonds are part of that. So it is something that we will do in the future, but there's no immediate plans.

Saahil Dey

Okay. Thank you.

Aidan Heavey

Thank you.

Operator

And the follow-up question comes from Stephane Foucaud of GMP FirstEnergy. Please go ahead.

Stephane Foucaud

Guys, I have a technical question on the tax treatment for Uganda. So I understand that the cost oil or the theoretical cost oil for Tullow, you only spent by Total remain in benefit, [indiscernible] cost oil. But from a purely capital – corporate tax perspective, would Tullow Shell costs which is carried by Total, Shell that cost for Tullow, can that be offsetable on profit? Thanks.

Aidan Heavey

Yes.

Stephane Foucaud

Yes, okay. Thank you. That's useful.

Operator

And the next follow-up question comes from David Mirzai of Deutsche Bank. Please go ahead.

David Mirzai

All right. Thanks for taking my follow-up. Just on your West African production. I am aware that your CapEx is right down for 2017. But I was surprised with a couple of the fields and the depth of decline in them. To point out, Okume, which is forecast down 33% next year and Congo Brazzaville, M'Boundi is down almost 50% next year. Is that down to some type of planned maintenance or is that the actual decline if you don't drill additional wells? And I suppose on that fact, how much danger is there of other regions suffering in 2018?

Paul McDade

Yes. If you look at the assets you mentioned, Congo B, previously we were – we had a pretty much continuous infill drilling program. And with the reduction in capital, that stopped and therefore you have a knock-on effect and production will come down. And the same is true in Okume. We have been doing cycles between Okume and Ceiba of infill programs over the last four or five years. And in the last couple of years we've really ceased that activity. And what you're seeing is a knock-on effect.

I think we had pretty much guided, if you look at the documentation we had put out before on results, the sort of levels we're announcing today is what we've guided previously. So it was as expected, so there's no surprise in there. However, I would say that the capital we've been putting into those assets is down as low as I think about $50 million in 2016 whereas it had been originally $200 million. So it is a very substantial reduction, you know, 75% reduction in capital invested.

However, as oil price recovers a little bit and we have some more flexibility, and what we are seeing is some of the operators of those non-operated assets starting to think about restarting infill programs, then we are hopeful that we can flatten out the rate of decline and maybe even reverse it a little bit. So that will very much depend on the operators and how much capital they spend. But the opportunities are there in a number of the fields to restart infill programs. And that would have the opposite effect from what we've seen with the decline in capital investment.

David Mirzai

Thanks, Paul.

Operator

And our final follow-up question comes from Mark Wilson of Jefferies. Please go ahead.

Mark Wilson

Okay, thank you. I just wanted to confirm the $400 million of Uganda charge is within $700 million you guided to today for FY 2016? And also, Paul, you mentioned you tested the FPSO facility using recycle? Would you be able to say what capacity you've actually had out of the wells?

Paul McDade

Sorry, just to – I'll take that just now. No, in terms of the production tests, it wasn't recycle, it was straight production. So the wells instantaneously averaged over 80,000 barrels a day for a 24-hour period. And we had instantaneous periods where they were in excess of 90,000 barrels a day within the test. So that was straight production from the wells.

When I mentioned recycle of ore, the injection pumps, we have a huge amount of injection capacity on the facility. Obviously we don't have the well stock to put that – to test all those pumps running at full capacity. So on the injection side you can go into a recycle mode where you can actually test all the injection pumps at full capacity, just to prove, were the well capacity there, you could actually pump that amount of water down the wells today. The recycle was very much to do with the injection, not the production.

Aidan Heavey

And the question on the charge, yes, it is included. It's under – if you look at note 6 under exploration write-off, you'll find the detail in there.

Mark Wilson

It's in there, it's in that bit. Okay, thank you.

Aidan Heavey

Yes.

Operator

Thank you. That will conclude today's question-and-answer session. And now I would like to turn the call back to Mr. Aidan Heavey for any additional closing remarks. Over to you, sir.

Aidan Heavey

No, I think that's it. And thank you all for taking the time this morning. I'm sure Chris and the IR team are available if there are any further questions. Thank you very much.

Operator

Thank you. That will conclude today's conference call. Thank you for your participation, ladies and gentlemen. You may now disconnect.

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