Tullow Oil PLC (OTCPK:TUWLF) Q2 2016 Earnings Conference Call July 27, 2016 4:00 AM ET
Aidan Heavey - CEO
Ian Springett - CFO
Paul McDade - COO
Angus McCoss - Exploration Director
Chris Perry - VP, IR & Communications
Dan Ekstein - UBS
Brendan Warn - BMO Capital Markets
Al Stanton - RBC Capital Markets
Rafal Gutaj - Bank of America Merrill Lynch
Stephane Foucaud - FirstEnergy Capital
Mark Wilson - Jefferies
James Thompson - JPMorgan
Michael Alsford - Citi
Dragan Trajkov - Stifel Nicolaus
Charlie Sharp - Canaccord Genuity
Thomas Adolff - Credit Suisse
Anish Kapadia - Tudor Pickering
Henry Steel - Odey Asset Management
Good morning and welcome to the half-year results presentation. For those who don't know, that's a photograph of the TEN FPSO, lit up like a Christmas tree, but Paul will take you through where we're with that, but it's actually getting very close to first oil. Just to take you through, you've seen this slide, it's slightly different to last year. We moved, as we've said before, pretty early in 2014 and 2015 to start resetting the business; cutting the costs; cutting the CapEx; and to refocus the business of Africa and especially around the low cost areas and start building a strong balance sheet. 2016, it started off a pretty tough year, as well know, with the oil prices collapsing again in January.
We also had a hiccup in relation to the Jubilee turret issue. But despite those, the effects of the cost cutting and the reorganization we've done, it meant that the business was profitable even with those problems. Now that we're about to start production in TEN, it's a step change, again, in the business and we're in pretty good shape moving forward. We'll have free cash flow we'll generate in the second half of this year and Paul will take you through the solution that's been put in place for Jubilee. Really, what we wanted to do and we're a bit ahead of schedule in doing that, is really having a business that is fit for the new oil era, whatever that is.
The oil price seems to have fairly well stabilized around these levels. I think, from the oil industry's point of view, oil can't stay at these levels. I think what we've seen over the last two years, is oil companies can adjust and be profitable at these sort of levels, but when it comes to major developments going forward, we definitely need a higher oil price. If we look at the projects that we have, it's only really East Africa, as a development, that will work at these oil prices, because it doesn't have the major capital programs up front. I think the problem is really going to be the financing that's available for major projects. So our belief is that, while you can be profitable at these levels, for the industry really to expand and move forward and get new investments, you really need an oil price closer to $75.
However, what we set about doing is making Tullow work and, in the areas that we work, make it work at these prices and we've done that. One of the things we felt was very important because of, again, the uncertainty in oil prices, is have a very flexible portfolio and we set ourselves a number of projects to actually do that. I think today we have a very flexible portfolio with major growth potential throughout the whole portfolio. We see today we have profitable, low cost cash flow from West Africa and that will increase and is growing. That will be the engine that will grow the business for quite a few years to come. We've a number of low cost development options, both in West Africa and obviously in East Africa.
We have reset the exploration programs and our portfolio there to make sure that we have a very attractive exploration program going forward that is low cost and that works in low oil prices. But then again, with the uncertainties, we wanted to make sure that we had the ability to max our CapEx with whatever the oil price environment was; so if the oil price falls lower, we can adjust our CapEx down; if it goes back up, we can adjust our CapEx. Flexibility really was the key to what we wanted to achieve in the business and I think we have done that. The guys will take you through that in their presentation. Obviously, the balance sheet is very important.
We decided to take a lot of the uncertainty out in the current market with a convertible bond which gave us a lot more headroom in relation to the liquidity. What we will see going forward now, is with TEN on stream, with positive cash flow, our balance sheet will naturally deleverage anyway. Eventually when the M&A market opens up and right now it hasn't opened up; I think it will take a resetting of the oil price and a rebalancing of supply and demand before you see a proper M&A market and we see that as probably into 2017.
But once that market is there and is competitive then we will sell down some of our assets, as we have planned. But there is no pressure on us to do that unless we get proper prices. I think that overall, I think we're in good shape; I think we've done the hard work. After a year and a half or two years of really going sideways, we're now in the position where we can start to move forward again and look at capital growth opportunities.
On that, I'll hand you over to Ian, who'll take you through the finance. Thank you.
Well, thanks very much, Aidan and good morning, ladies and gentlemen. On the finance side I think it's, first, worthwhile just reflecting and highlighting some of the things we've achieved over the past few months in terms of a proactive financial management. As Aidan was saying, we took some early action; it's really coming through now reducing our costs; our gross G&A, it's the cost of all our people and their related costs, down 32% in the first half of 2015. Our net G&A, our admin expenses $69 million down 31% from the first half of 2015.
As Paul will show later, a good progress in our operating costs. Our underlying operating costs are actually showing a good positive trend. CapEx perspective, our CapEx, as we've previously said, target for the year around $1 billion. That includes about $35 million for the Jubilee costs on the turret, but coming down 41% lower in the full year of 2015 and, of course, post the TEN project a significantly lower run rate going forwards. Pretty resilient set of results, given the challenges, given the low oil price, the operational challenges, we actually made a profit in the first half of 2016. And then, of course, looking forwards with TEN coming on, that'll increase our profitability, increase our cash flow. Also, underpinning that we have both the continued benefits of our long term hedging program.
We also have the insurance in place, the Jubilee turret. I'll talk more about the hedging, but $320 million plus mark to market at June 30, 2016. At the same time, it's all about maintaining flexibility. We have in our CapEx and I'll come onto that, but our CapEx - our base level of CapEx probably for 2017 is something like about $270 million; maybe about $500 million depending on the market conditions and other factors, if we can spend up to that much. But that in itself is a very significant reduction on the $1 billion for 2016 and a very significant reduction on 2015 and before. Bank facilities, we worked through our redetermination first half 2016.
Our RCF facility is extended. Of course, as Aidan mentioned, we also tactically decided to increase the diversification of our debt, in order to supply some extra liquidity by issuing a convertible bond recently. Overall, we've taken pretty decisive action. We're sort of working through on all fronts, managing our costs; we're hedging our volatility; diversifying our sources of debt and, at the half-year, at $1 billion in liquidity, shortly after with the addition of the convertible bond, more like $1.3 billion. I think the results, very much, the numbers are the numbers.
Again, I would really point to the fact that despite the lower prices and the lower Jubilee production, we're making a profit in the first half. My next slide really just takes us through a little bit more as to how we've managed to do that. So what this slide's got on it is really the first half of 2015 on the left-hand side, on the right-hand side $30 million profit for first half to June 2016. There's also a box and a little bit that talks about what the impact of Jubilee, the turret issue and what would have happened if that wasn't there, but I'll come on to that in a minute.
So basically, through oil price, oil price down about $10 a barrel on last --first half of last year, a big impact. Interestingly, the benefit - the actual - whilst the realized oil price is down $10 a barrel, the actual oil price was down more like about $20 a barrel in the market for the first half of 2016. So that's $60 a barrel probably more like $40 had it not been to the benefit of the hedging. Our volume clearly down because of the Jubilee issue. Primarily $175 million of that $196 million is the Jubilee turret issue. Offsetting that we have benefits of our time value gains on our hedging, $55 million, cash operating costs, $30 million better. That incorporates an $18 million additional charge for Jubilee turret costs. The underlying increase is about $48 million. DD&A $109 million better. Why is that? Two factors. One is obviously there's less DD&A on Jubilee, because there's less production, but a bigger element, actually, is the fact that actually impairments that we took last year in 2015, now create a lower asset base and therefore lower depreciation going forwards.
We talked already about lower admin expenses, result of our cost-cutting projects. We had restructuring costs last year lower; lower levels of exploration write-offs; lower levels of exploration activity. Taxes lower, because we had the Uganda settlement last year offset by higher Norway tax rebates last year, about $63 million better than last year. Financing is improved, because of Forex gains and the higher capitalized interest. Other is very - a variety of things but mainly under-lift on Jubilee. Overall, it's a gain of about $100 million from the first half of 2015 to the first half of 2016. And then if you look at the impact of the Jubilee turret then the volumes; the higher operating costs offset by reduced DD&A; reduced taxes that would've been about an $85 million impact on the first half and the numbers would've been more like $115 million had Jubilee not occurred. A little bit around insurance on Jubilee; tell you where we're.
Paul's going to talk quite a bit more in his slides about the operational impacts of the Jubilee turret issue. I'm just going to talk about one or two main points from an insurance perspective. I think the first point really to make is that the basis, if you like, for the cost side of it, the hull and machinery cover in terms of CapEx and OpEx, we've now got some reasonably good estimates of what those costs will be. Those estimates will no doubt change over time, but these are good ballpark numbers for the spread more option. I think these numbers are clearly a lot less than might otherwise have been if there's - a sail away option was adopted.
On the business interruption, we set out and Paul will talk about this in more detail, where we need to have some sort of shut-ins to effect the repair work and when our average gross production is expected to be, including both the shut-ins and the lower production, slightly lower production we get from the revised offtake procedures rather than what otherwise might have been. That will become the basis, if you like or agreeing with the insurers as to what the right production forecast would otherwise have been and what the insurance claim ultimately will be. But I think the main point to note on insurance is that, in our view, we will be able to recover our costs and also the business interruption insurance will cover the value of the lost production.
On timing, we expect that the insurance receipts for what - the impacts in 2016 we're hoping that - we have good progress so far in conversations with insurers, we're hoping that that will turn into receipts for 2016 impacts by the end of 2016 and that costs and lost production in 2017 and 2018 will be effectively refunded to us on an as-incurred basis. I'll stop there in terms of insurance and then Paul will talk a bit more about some of the more operational elements to the Jubilee turret project going forwards. In terms of hedging, our hedging program I think has really done its job over the last couple of years or so. 2015, we had a benefit of about $385 million; in first half 2016, around $200 million. We've got $322 million mark-to-market, going forwards.
This is a program which really stood us in good stead. It's one which we continue. We do it on a very simple basis. As you can see we have good color for the remainder of 2016, 38,500 barrels, hedged at just over $74 a barrel. I think, quite distinctively, we have cover into 2017 - substantial cover into 2017 and also into 2018 as well. From a balance sheet, debt diverse and liquidity perspective, a key point here is $1 billion of liquidity, enhanced by the convertible bond, to $1.3 billion, just after the half-yearend. The real point, I think, as always here, is liquidity is key. We always take the view that early action to secure liquidity to diversify our sources of funding, are important. We always address things pretty early.
The slide sets out, on the left-hand side, the actions we've taken around the RBL, the corporate facility, the covenants and issuing the convertible. We believe we're managing those relationships and those actions well with our banks. Going forwards, it was important, I think, as Aidan said, that the --the convertible was a piece of tactical funding. But we think it was an important thing to both help our source of debt, going forwards; provide some extra liquidity. Who knows what volatility may come in the future, with price etcetera. What we do know is that we've done a little bit of tactical business, just in case. That's a good piece of business. So I think overall, strap line there, balance sheet liquidity underpinned by diversified debt capital structure and also good and supportive long term bank relationships. On CapEx, as we said our forecast for 2016 is $1 billion. Within that there's about $35 million before insurance refunds, for the Jubilee turret project.
So underlying CapEx probably approaching $950 million and within that of course, there is the $600 million for the TEN project. I think what's important, as you look at that slide, 2014, 2015 to 2016 in total, going into 2017, is the shape of the trajectory. Really, with the TEN project over then we're looking at much lower levels of capital going forwards. We talked to you before about having the ability to get our CapEx down to around $300 million in 2017. We're actually saying $275 million here. We could even go lower than that, if we really had to, in a low oil price environment. That would be - we show the split there, West Africa $100 million; East Africa $100 million; exploration $75 million.
We show the yellow bar and the estimated Jubilee project costs which we expect to refunded. And then depending upon the market conditions, we hope and expect, actually, in a place where it makes sense to get on with Jubilee infill drilling, progressing East Africa and getting exploration spend more like up to $150 million. Angus will talk later about some of the things that are in those numbers. Overall, that gives us a clear expectation that at $50 a barrel we'll have positive free cash flow in 2017, even at that higher CapEx number which is - and after taking into account all taxes, interest and other costs as well. So, main point being I think, again, that we have both flexibility to adjust our capital in 2017.
But the main point is don't forget that CapEx is so much lower than it was and when you combine that with the additional cash flow from TEN, then it puts us in a very strong position going forwards to naturally de-lever organically, anyway. This is my final slide and really just building on that, our strategy - financial strategy really is to get the basics right; to anticipate issues that need to be addressed; and then provide a solid platform for future growth. In terms of financial resilience, we've driven down CapEx and OpEx. We've got hedging in place. We've got the CapEx flexibility, with the projects, Jubilee turret project; again, Paul will talk more about it being managed well. The insurance is in place. TEN to come on stream imminently. Deleveraging still remains obviously a priority for us. Free cash flow, positive from 4Q 2016.
We will continue to pursue portfolio management options and, when market conditions allow, that's something we'll be keen to do. We still maintain the notion over time and it will depend on things like oil price, portfolio, etcetera., etcetera., as to when that will be, but the direction of travel is clearly we want to get ourselves back to a place where our net debt/EBITDA is less than 2.5 times. In terms of managing liquidity, we've got a pretty good place at the end of the first half. We expect to generate surplus free cash flow, going forwards, from the fourth quarter. We have a pretty good set of assets which the banks recognize, the diversified capital structure and because of that we receive pretty strong support from our bank. So again, provide a solid foundation, anticipate issues coming up and then flexibility in both liquidity and capital to enable the business to grow in the future.
And with that, I'll hand over to Paul.
Thanks, Ian; morning, everyone. First half 2016 pretty busy, progressing production development, assets. And also consolidating the work that Aidan talked about through late 2014 and 2015, in terms of the actual business and the organization and then we obviously had the additional challenge of Jubilee which I'll talk about. But we've made progress across the board. We'll talk about TEN and the progress there. Jubilee turret, very significant progress made in a very short time, we'll talk about that The decision in East Africa, around the pipelines, has given us great clarity and that actually has led to a kind of acceleration of progress there.
And then overall, the streamlined and more efficient organization that we have today, relative to where we were before, is starting to feed through in terms of both costs, but also I think performance. Also in terms of safety and environmental performance, I think the whole efficiency of the organization and the streamlining of the organization is actually leading to better results there, as well. We're exceeding all of our safety and environmental and social performance targets. On production, whilst overall, production has been impacted by the Jubilee turret, the team have been working real hard through the year, to try and maximize, safely, production from Jubilee. That's leading to a projection or a forecast for the second half of the year, of about 85,000 barrels a day, for Jubilee. That's within the constraints I'll talk about when I come on and talk about the Jubilee turret project.
And then I'll talk about the constraints and the actual implications on production, in a little bit more detail. So whilst we have insurance coverage, not all of the partners within the partnership have that insurance, the BI insurance coverage. Therefore, as you'd expect, we as a team, are trying to do everything we can to maximize the barrels through the facility, while we work through that project. TEN will start imminently, we'll talk about that. We expect that to start to ramp up in the second half of the year, reaching capacity or thereabouts, towards the end of the year. And then, as you know, we've got the ITLOS ruling which means we'll not be drilling in 2017, but we do expect, even without additional wells, to be well above 60,000 barrels a day in 2017. Central West Africa, you probably notice has got a higher decline than you would have seen in previous projections. That's really just a direct correlation with the amount of capital we're spending.
If you recall, we used to spend about $200 million a year. That has been - we basically choked that back to about $100 million. We were projecting $100 million. Actually, in reality, our operators have pulled that right down to about $50 million, so right now this year, we're spending about $50 million in Central West Africa. We expect similar expenditure next year and of course, as you'd expect, that feeds through to a higher decline rate. The important thing to recall is that we do have the ability to turn that around, because there are plenty of incremental projects there. Overall, you can see from the project, when we take into account our expectations with regard to the business interruption coverage, then we're heading to a guidance of 62,000/68,000 barrels this year for West Africa and heading up towards low 90,000s, as we get to 2017 and 2018.
In terms of cost, both operating and capital, first point really is on OpEx per barrel. This chart has, for Jubilee, stripped out what Ghana latterly, but Jubilee at the moment, stripped out the costs associated with the turret which we expect to get covered by insurance, to try and understand the underlying operating costs. As you can see, we're probably a little bit ahead of where we thought we might be. This first half, we've been - had operating costs per barrel on Jubilee of about $9 a barrel - just below $9 a barrel. So we're very much on track to hit the $8 a barrel we're targeting in 2018. Mainly that has just been due to really hard work on contract renegotiations and efficiency improvements. That's both operational efficiency and organizational, whether it's here in London or there in Ghana. Really, building on what Ian said, in terms of West Africa, talked about the non-operated portfolio, currently down around $50 million; expect to stay at that level in 2017 and then in 2018, the base case is that level but with significant opportunity to enhance that.
When we look at Ghana, obviously in TEN, we're coming to the end of the TEN expenditure. As we go into 2017, the capital expenditure on TEN will be very low next year, due to the fact that we will not be drilling infill wells. On Jubilee, we don't expect to start any infill drilling, certainly in the first half of Jubilee, as we work through the turret project. But we do have the option to start infill drilling in the latter part of 2017 which is some of the incremental investment we highlight there. And then as you go into 2018, there's opportunity to invest across the whole portfolio of Central West Africa, Jubilee and TEN, from an infill point of view. Looking at the Jubilee turret. Really, in the fairly short order, if you think this issue only arose in February of this year and I think the team have done a fantastic job of really taking what was a major issue at the time and carefully transferring it into a normal operating state offshore.
We're now in a different, but a steady state, offshore, in terms of operations; and then, importantly, on the project side just really taking that issue and transferring it into what is now just a significant project for the Group to execute over the next 18 months to 24 months. That has all been done with kind of safety and environment at the forefront. And pleased to report that there has been no increase, in fact we're exceeding all of our safety and environmental targets offshore in Ghana. Overall, we've got three phases. Between now and the yearend we'll actually be spread mooring the vessel in its current heading. All of the equipment that we need for that is already procured and there's quite a bit of fabrication going on, at the moment. We expect to be out there in the fourth quarter executing that project and we'll have it in place by December which means that we will remove the tugs and a lot of the risks that we have offshore.
And then as we go through the first half of next year, we will then move the vessel to its optimal heading and then permanently spread moor it in that optimal heading by first - the end of the first half of 2017. And then we're looking at the need for an offshore loading buoy to basically ensure that we have maximum efficiency in terms of cargo offloads. We'll decide on that as we go through third/fourth quarter this year. If we decide to proceed with that we will proceed and then that will be executed and installed early in 2018. I've laid out the gross costs associated with that project here. As you saw in Ian's slide, he's then taken that and shown what it means to Tullow from the net perspective in terms of our insurance coverage. In terms of production, we don't expect any shutdowns associated with the project this year, but we'll have some curtailment over a three-week period later in the year.
And then, we do expect shutdowns in the first half of next year and then early in 2018 and I've laid them out there. We're currently working under a constrained position. At the moment, due to the off-take procedures, our maximum off-take from the vessel is about 100,000 barrels a day. So whereas before we were up and in any day we had the capacity to go up to 115,000, 117,000, today maximum capacity is about 100,000. Once we get the permanent spread mooring in place, we're looking at ways to increase that up to above 100,000, maybe up to 110,000. Then, as we get the deep water buoy in place, that will go back to the 120,000 it was before. Again, I've laid out the expected production.
So in terms of execution of the project, we've got complete alignment in the partnership; we've got support of the government; we're just working through the formal approvals. We have the approvals in place for the phase 1, the temporary heading spread moor and we're working through the approvals for the rest of it. Obviously, from a timing point of view, we've got a very experienced project team, I'll come on and talk about TEN, who have done an excellent job over the last three years. They are migrating on to the Jubilee project and will be executing that project and will leverage all the team and the processes that have led to such success in TEN. Important to note, that the underlying asset and reservoir of wells are completely unaffected by what's going on, on the surface. Looking at Jubilee and the underlying asset, basically production performance as shown; gas exports continue.
With regard to the Jubilee full-field development plan that we've talked about before, we've kind of agreed with the government we'd put that on ice. We submitted the plan, the plan has the support of government. There's some things we need to negotiate through around gas and some other small areas. We've agreed with government we'll focus on that next year. Looking to get the plan approved by the middle of next year which would then give us the flexibility if we do want to go back to infill drilling in the second half of next year, that would be possible. And then, we shouldn't lose sight of the additional resources that lie potentially around Jubilee and TEN, not just the upside within the fields, but actually the upside around the fields. Our exploration teams in Ghana continue to look for exploration potential in and around the existing asset and, more broadly, within Ghana.
So, a long, long future ahead for the Jubilee and the TEN asset. On TEN itself, startup is imminent. Over the next couple of weeks, we'll be starting first oil. All the subsea infrastructure is in place and completed. The wells are ready to start and we're just doing some final commissioning work on the topsides. I think the team have done an exceptional job here. This is industry leading execution performance that they've delivered over the last three years. At no time have we been out with budget or off schedule for a three-year period which is quite astonishing given the external environment and, actually, our internal environment where we have gone through a lot of organizational change.
So a truly outstanding performance, we're all looking forward to celebrate in first oil with that team down in Ghana later next month. I think the key ingredients have been having a very focused and empowered team in a Tullow environment which is enabling. Then we have very strong alignment across the partnership and very strong support and relationships with the government of Ghana and it's those ingredients that have led to the success. As soon as we get it on stream, what we can do is actually start then focusing on the upside in and around TEN and not only getting up to plateau, but then extending that plateau for the foreseeable future.
As we look to East Africa, the big event obviously over the last few months has been the clarity on the pipelines, the decision for Uganda to export to Tanzania through the Tanga port; and for Kenya to go with the standalone private line from Lokichar through to Lamu. That clarity has been helpful. It's allowed us to now move ahead on both projects. In Kenya we're now focused on getting back to appraisal. A lot of work has been done on the appraisal, that's allowed us to upgrade to 750. Angus will talk about some of the activities we've got planned on the appraisal side. On the development side we've got some more injection testing. We've just come off the back of some very successful extended well testing. All of that has led to the upgrade to 750 and we're looking forward with the additional drilling to take it further than that.
We're working with the government of Kenya on an early oil production schemes. We're looking at the combination of truck or rail to export oil to Mombasa port, starting off at a nominal 2,000 barrels a day, see how that goes and then looking at the potential to expand that. What's very important is it will provide a lot of very useful data from a reservoir point of view for the full-field development. But, also importantly, it actually gives you a lot of implementation experience working with government; working with the county government; working with the local communities. It may seem small, but actually you still have to go through many of the same commercial issues, social issues, environmental issues. So it's a real learning curve.
It's got a lot of benefits beyond the oil value in itself. And then on the full field, targeting 80,000 to 120,000 barrels a day. Kenya remains a very attractive low cost onshore development. Really, we're making good progress with the government. As you saw, we signed an MOU; submitted a joint development agreement on the pipeline. What does that mean? Well, that means we're now agreed with the government how we - because it sits outside the upstream. We've sitting with government and we've agreed how we'll progress the pipeline to FID from a technical perspective. Then that will help us work with the government to look at how we bring third parties into finance that pipeline within Kenya and that's leading us to kind of think about the upstream FEED starting in early 2017.
We go on to Uganda, again as with Kenya the clarity on the pipeline has been very helpful and it's allowed all the parties now to focus on progressing the project. In the upstream we're working with Total and CNOOC. We've had plenty of time in Uganda; we've got a very well-defined resource of 1.7 billion barrels. We've got a well-defined upstream project which is very low cost; we're selling just now about $5 a barrel. Upstream development costs and some of the work we're doing is showing that we can maybe even reduce that further, given the current climate. All of that's leading to a full cycle when you consider CapEx, OpEx and tariff of sub $25 per barrel overall cost and we will be moving the upstream to FEED in early 2017.
On the pipeline side, obviously, route Hoima to Tanga about 1,400 kilometers. Total and the Government of Uganda and the Government of Tanzania are taking the lead on the pipeline project. In terms of the implication for Tullow, we expect a tariff of somewhere around the $10 to $12 per barrel. The parties that are leading the project are making real good progress. There's a very supporting environment, both in Uganda and Tanzania with regard to land excess and the fiscal framework.
Again, we expect the pipeline to move towards FEED in early 2017. So, in summary, a busy six months; progress across the board. We really sit with a very strong low cost production asset set that is going to sustain very high levels of profitable production, regardless of oil price, moving forward. We've got, on West Africa, plenty of incremental investment opportunities which are attractive even at current prices. And then, in East Africa, we're sitting with some very material low cost development assets which again look attractive in the current environment.
So with that I'll hand on to Angus.
Thank you, Paul. Morning, everybody. Exploration has also been very productive, very busy. Our teams have been leveraging minimal spend for maximum impact in the current environment. Our strategy continues to steadily evolve - subtly evolve. We continue to be central to Tullow's value growth strategy. We're focusing very much on material, low cost plays adapting to the current environment, but staying focused on that long term upside.
We've got exciting exploration program launched in Guyana-Suriname and I'll talk a bit more about that. That's been given a boost on the back of the major discovery by Exxon last year in the Liza-1 discovery and I'll explain how that's relevant. We've got drilling to commence in Kenya, four plus four wells in the South Lokichar Basin starting to drill in the fourth quarter and I'll tell you more about that.
Meanwhile, our teams have been maturing and replenishing our portfolio. We've been generating high-impact drillable prospects for future growth from our existing 3D seismic surveys and 2D seismic surveys, we continue to work those hard; and also been adding attractive exploration acreage, particularly suited to the low oil price environment. So let's go straight to Guyana-Suriname, our offshore position there; an excellent strategic position in a new oil province. We were a first mover/early mover in this basin. The Liza-1 oil discovery, as I said, has significantly de-risked the basin and Tullow's regional acreage.
Now, you can see on the map on the left - center left a little, you see the Liza-1 and 2 well results flagged in green. We had oil shows in green at Jaguar. There are oil shows in Aitkanti and there's an oil field onshore in Tambaredjo. What this is demonstrating is that this oil charge has made its way from the basin center through the shelf edge, across the shelf and up to the beach at the edge of the basin. So we're in a very good position here. If you think of our acreage position it's, actually, a bit like a baseball catcher's mitt. We've got ourselves fully wrapped around the kitchen catching the oil that's coming up through the reservoir fairways into our acreage.
I just want to highlight one of prospects which continues to rise to the top of the list, is the Araku prospect. You see that in the cross section on the right hand side. Araku is a major prospect in Suriname and Block 54. It's a 500-million barrel premium in a four-way closure with good seismic amplitude support with seismic amplitudes fitting to structure. The well costs are low. The Araku estimated well cost of around $14 million, one four, net to Tullow. We're the operator there with 30%. We've got a lot of follow-up potential there; multiple, high-quality prospects identified for follow-up in 2018 plus.
These really are game-changing low cost prospects. Just zooming in a bit on the Guyana side of that acreage position, on the map on the left you see our two main licenses, Kanuku and Orinduik. An outboard of that you see the Liza discovery. You see our orange prospects, I've flagged one there, Kaieteur, for instance. On the cross section on the right, you see how Kaieteur, our prospect, sits up-dip of Liza-1 and it's in the same stratigraphic interval. The thesis here and it's a pretty compelling one, is that the oil that is charged at Liza, that system, that charge, also has a good chance of being present in the reservoir's up-dip in the Kaieteur prospect.
The advantage of the Kaieteur prospect is that it's in shallow water. It's only 100 meters of water, so we're looking at very low costs in our environment compared to the ultra-deep water setting further offshore. So, Kaieteur for us, our estimated well costs is of the order of $15 million net to Tullow. Again, a non-op - this is a non-operator position at 30%. So the key activity for 2017, later this year, is to get after the 3D seismic survey acquisition across our acreage position to firm up drilling candidates for 2018, 2019 and so on. Lots of prospects pairing up with the outboard positions, so this isn't just a single shot; this is a play fairway.
So, switching to Africa and to East Africa. You've seen this map before. This is the regional overview of the acreage position that we have in East Africa. A commanding acreage position with two live oil basins, obviously, South Lokichar and Lake Albert. South Lokichar, as Paul said, we've been able to increase that resource base to 750 million barrels of oil on the back of exploration appraisal work done recently. But we still see over 1 billion barrels of upside potential in that basin. There are other basins. The Kerio Valley Basin, you recall recently, Cheptuket-1 found 700 meters of oil shows in that basin. Today, we still are of the view that there's an opportunity to open one or two more basins in this commanding portfolio.
Now, zooming in on the South Lokichar Basin in Kenya, where we have made nine oil discoveries, found nine accumulations so far; 750 million barrels of resources; over 1 billion-barrel basin potential; and many more leads yet to drill. Let me show you where those leads are. The map's currently showing the nine proven oil accumulations. We had a successful well, you might recall, Etom-2 which drew our attention to the high prospectivity in the northern area. We have these exciting northern prospects, where we see un-risked potential of about 300 million barrels of oil; risked, that's about 100 million barrels. So that's one way to get to the 1 billion barrels through success in the north, but that is hedged, if you like. We've got more opportunities. We've got the east flank prospectivity; we've got the flanks and the deeper parts of the western play; and we've got a basin center play. Taking any of these routes, we can get quite comfortably to the 1 billion-barrel basin potential.
So what we're going to do is we're going to recommence the E&A program at Q4 this year with a campaign of four firm wells and four contingent wells and I'll show you where the candidates are. If you look in the north you'll see the Etete location near Etom, that will be the first well drilled in the fourth quarter of this year. We will then jump to the north to Erut. Erut is a riskier well that Etete but the objective of jumping up to the far north of the basin is that if we find oil in the far north then it de-risks - substantially de-risks the prospects between Erut and Etete, such as Ebenyo and Ekadeli.
We've also got opportunities in the south to appraise Ngamia and Amosing. This is going to be a step by step campaign, we'll drill the first two, Etete and Erut and then decide from these options, that I've highlighted there in red, as to what's going to be well three, four and then make the decision whether we do the other four wells in the contingent program. Sorry, I should just mention as well that the well costs here are low. We're looking at $4 million to $6 million net for Tullow; again, low cost oil play here. Africa is our core continent. We continue to build up exploration positions there for the long term future upside with an eye on portfolio replenishment. We have material acreage positions in plays that we know well. In Mauritania you'll recall we shifted to the low cost self-edge plays.
We've introduced a new position to the portfolio with PEL 28 in Zambia which is an extension of the East African Rift Basin Play. Reconnaissance has started there and we hope to be doing FTG shortly. This will be very much a staged exploration campaign, but an exciting one with a chance to replicate the success we've had in Uganda and Kenya. In Namibia we've got material turbidite plays in a low cost shallow water setting, in a way somewhat similar to what I was showing you in Guyana.
In Ghana as Paul mentioned, we continue to support the production development teams with near field and exploration potential in Ghana, in TEN, in Jubilee and in around those assets to extend the production plateau there. So I' just going to leave this slide up with you as I hand back over to Aidan to wrap up. But just if I might summarize this, we really are leveraging minimal spend for maximum impact in exploration. Exploration is central to our growth, but we're adapting to the current environment.
With that I'll leave this slide up and hand over to Aidan for wrap up.
Thanks, Angus. Well, just to finish off, there's a huge amount of work has gone into the business over the last 18 months to adjust the business to what was a - quite a dramatic change to the oil industry and one that nobody really expected. But I think what you see now is that Tullow and virtually every other company has adjusted very, very quickly to it. It shows a resilience of the oil industry and, if this is the new oil environment then, we'll cope with it and move forward.
But I think it's - one thing that we needed to do was get the business right, get the projects right. But really for moving forward you do need to be exploring and that still remains the key area where you can add value to shareholders, so in the second half of the year we will start the programs again.
I'll leave it with that and open to the floor to questions. Thank you very much.
A - Chris Perry
Can I just ask we go for one question a person, so that we can get around everybody this morning? Thank you.
It's Dan Ekstein from UBS. Could you elaborate a bit on the potential timeframe for an East Africa transaction, I think when we sat here at the full-year results it was very much a priority for this year and some of the language you used earlier suggested that that might not be possible given the market environment? And then secondly on the convertible bond issuance, the equity was trading above £2.60 in the days preceding that and with the convertible you've effectively agreed to issue equity at a similar level, at some point in time, but with a 6.5% yield. Could you explain the decision-making process there? Thanks.
Okay, well, I'll take the East Africa one and Ian will talk about the convert. I think East Africa was - it was quite complicated with the two countries and a pipeline going through both areas. What we felt that that was - would be the cheapest tariff area - or tariff way. The timeframe for getting an agreement between the two countries was an issue. I think when the governments decided two separate pipelines and go independently it actually created two very distinct projects rather than one. I think it's actually - it works out easier projects to actually manage and get done.
We felt that the - we now had two projects or two separate areas and the CapEx programs in those projects for the next 12 months or so is actually quite small. The urgency to farm them out was not there and we felt we were better off waiting until the market has improved a bit or we're closer to FEED. And that - when there is a competitive M&A market which there hasn't been for two years, I think we now see that the M&A market has started to pick up again, but it's still not in full flow. I think it's we're no urgency to actually do it, so we're not going to sell assets in a bad market. I think it's just prudent to sit and wait. There's no big capital programs. I think what we're doing in Kenya is low cost and high value and it's well within our means to actually do those. Ian, do you want to?
Yes, I think on the convertible, the primary purpose first of all, the convertible, was to diversify our source of debt and for the short term provide some additional funding and we're operating in pretty uncertain times still. As we can see, actually and with the share price, whilst we expected, as indeed always happens when you issue a convert, the share price goes down and then it recovers. But, actually, since we issued the convert the oil price has come off by a good $4, $5, $6 a barrel and that's really what you're seeing happening with the share price.
We believe and therefore for that reason alone, but also more importantly I think as we look forwards, refinancing is coming up etcetera., etcetera., we always rather prudently like to get our ducks in a row and do things when we're able. Issuing a convert, we saw just a very tactical thing to do to access some different funding from another source. As we go through our refinancing, as we go through what still could be volatile times with the oil price, we just think it was a smart and prudent thing to do. So I'll buy that decision.
Why not equity--?
Well, I think our view was it's about diversifying the source of funding. It's about actually - we've always said, Aidan has always said that issuing equity is something that we want to be demonstrating that we can manage the business appropriately. We're bringing on TEN; we're reducing our CapEx; we're creating flexibility; etcetera., etcetera. Fundamentally, you often say it's easy, but it's not as easy as you think to raise equity. Actually, the cost of equity is a lot higher than the cost of debt. So I think from our view is that let's do the sorts of things which we think, ultimately, are in the best interests of maintaining quality and the best interests for our shareholders.
It's Brendan Warn from BMO Capital Markets and I won't hold myself to one, sorry, Chris. So just two questions if I may. I guess with the balance between paying down debt and additional CapEx in 2017 and obviously with the market conditions being quite volatile, can you just talk about what sort of oil price expectations and what's the priority in terms of your net debt/EBITDAX? And then just also, can you talk about the constraints around the accordion and where would you need to either call upon that or play the accordion, if I can use that phrase? And then just lastly are all impairments behind us, just looking at the current forward curve?
So I think first of all, when we say paying down debt is our number one priority, it's not the only priority but, clearly, it's something that we want to actually achieve. It's also important that we're able to manage our debt but, at the same time, create the space and the ability, for example, for Angus to do his four - restart the exploration program in Kenya with his four-plus-four contingent wells. To also have the ability, as we showed on that CapEx slide, to do things like Jubilee infill drilling, to begin to progress FEED studies, etcetera., on East Africa as appropriate. So it's about, I think, Brendan, getting the balance right. In the short term it's getting the balance right between paying down debt and being able to grow the business. And then, in future time, you also bring into play the discipline also further down the line that a dividend would bring, so we want to get that place. We want to target and it depends on things like oil price, what we do portfolio-wise, etcetera. We still want to get our debt back down to 2.5 times or less. But we do see our debt as something now which we're looking at just the pace of reduction in a sensible way that gets the best balance between reducing that debt, but also being able to grow the business.
I think the accordion on the RCF really is just an additional feature. We used to have an accordion on our RBL. We're not planning on using the accordion, but it's just a nice little add on. And I wouldn't really call it any more than that. I think on impairments you can never say never. But one of the reasons why that D&A charge was - come down was not only just because of lower GB production, but because we had actually impaired a number of our assets in 2015 and, therefore, the base is much lower. So I think big impairments should be behind us.
Al Stanton from RBC. On the insurance, Ian, can I ask how the accounting treatment should be presented? In terms of the interruption payments you get, should that appear in the revenue line? And therefore, how is it taxed? And then also on the sewer maintenance, that's effectively negative OpEx. So how will that appear in the accounts as well?
I think, Al, that the revenues will be what they are. And then there'll be a separate line for insurance which will get taxed at the due day at the 20% kind of rate. As regards OpEx and CapEx, they should actually - we'll have our OpEx and CapEx and insurance will come in as offsets to those amounts.
Yes, then, can I ask a follow-on question, sorry, Chris. Paul, is there any reason we can't use the CapEx profile you provided for Uganda in Kenya?
With regard to Kenya, the shape is very similar. The reason we've got it in there is percentages. So I think using a similar percentage shape for Kenya is fine. It's not dissimilar.
It's Rafal here from Bank of America Merrill Lynch. Just looking at the insurance side of things, can you maybe just run through the mechanics of how the business continuity and the hull and machinery insurance is going to work from a cash-flow perspective? How we should be thinking about that. And then could you maybe - you presented a very good outline of what the plan is for fixing the issue. But could you paint a similar timeline for what we should expect to see in terms of your discussions with the insurers and what the progress has been there? Thanks.
I think that in terms of capital first of all you should expect in 2016, 2017 and 2018, that the capital costs and the operating costs, effectively - are, effectively, paid for by insurance in those years. I think if you're trying - so if you're thinking about how do I model this and I think you model the CapEx as an in and an out. We still need to work with our insurers as to what is the right level of production and, indeed, find out what actual production actually occurred to determine then what is the claim, if you like. I think the best way to model your production is to look at what you had previously before this incident occurred and to say that, actually, that will be recovered through insurance.
And then defining business continuity when should we start to see it reflect the successful?
So this is all our expectation and it clearly depends on the conversation with the insurers which as I said earlier are going well. But what we're hoping and again it's set out on that slide I had earlier, was that the - both the business interruption and the hull and machinery, our expectation is that we will get to a place where, by the end of the year, so sometime during the second half of the year, that we'll effectively get compensated for what's happened in 2016.
Stephane Foucaud from FirstEnergy Capital. Some questions on Kenya. At the time of FID, what sort of oil price would you like to see in order to press the button to sanction the project? You talk about the cost, but oil price may be a different question. There is also a lot of exploration activities. As a result, would you expect, if some of this is successful of the ongoing program for the overall plateau of production to go up and perhaps looking forward, to have a larger pipeline? Or whether it is just about expanding the production plateau?
And lastly on the farm out, I think coming back to a previous question, earlier this year you had perhaps some interest. Do you still see those interest even if you don't want to transact? And back to the comment around increased level of M&A, would that level of pricing be better or the level of interest being increased compared to January or February when you presented the full-year results? Thank you.
In terms of oil price trigger, I think the important thing to recognize in both Kenya and Uganda is that the actual underlying full-cycle price of CapEx, OpEx and tariff is very low. Therefore, I think we're working through. We'll do FEED next year. We'll prepare for a sanction which is likely to be 2018 and we'll see what environment we're in. And then I think any decision is made up of a combination of the cost of the development which obviously is very favorable at the moment. We're seeing further downward pressure as we're looking again at Uganda, the fiscal terms in the oil price.
I think with the underlying project I think the good news for both Kenya and Uganda is the combination of the three can be made to work even at low oil prices. So I think the oil price will be where it will be when we get to say, a 2018 decision point. The only important thing to consider is what is the combination of the fiscal, the oil price and the cost combination at that time?
You could press a button today, I think on future we're back to appraisal and some exploration. You saw in Kenya I think we've said we're confidently above 80 and with the current resources we could be up to 120. I think you will see us - we could choose to ultimately sanction at 100,000 barrels a day for longer or - these are just optimizations you'll do with the data at the time of sanction. So I think any additional resources, if the 750 was to go to 1 billion, you could probably think about the plateau rate going up and some combination of maybe extension of plateau 1 and higher rate.
I think one of the other very important things about the current appraisal program that's ongoing and the work we've done today, a lot of it is about mitigating the downside as well as acknowledging and recognizing the upside, so that's very important. The extended well testing we did earlier in the year was incredibly important for the mitigation of the downside. The water injection testing we're doing later in the year is similar. Then the appraisal and exploration is again added volume, bringing the downside up which is just as important as what your high side could be.
And then I think on the farm out we kind of talked about that before. I think our view is in Kenya 50%, there is no pressure on us at the moment to reduce. I think the most important focus on Kenya is getting this project ready to sanction in 2018; getting through a better understanding of the upside. I think in Uganda we're very clear. We've had plenty of time to appraise the fields in Uganda. We're clear where the upside is and it's well in excess of 1.7, but it's reasonably well defined.
I think I would argue that in Kenya, the upside in Kenya is not well defined. I think that's going to be something we're very focused on over later in 2016 and through 2017 which would set us then up well if we decided to drop our equity in Kenya ahead of our sanction in 2018.
I think we've seen over the years plenty of interest in East Africa, both Uganda and Kenya and as Ian said, we now have something that's a little bit different which is two separate projects. They're not connected which opens up different avenues.
Mark Wilson from Jefferies. Just one question, regarding - could you take us through the steps, the physical steps you'll take in the first half 2017 to rotate the FPSO and how that plays off against obviously a turret designed - turret moor design?
Very simply, right now we're well underway with the fabrication of all the materials we need to actually spread moor the vessel in its current location. The big advantage of that to do it early is we get rid of the tugs and we get back to a more stable operation. That's why we're accelerating that through this year and the team have done a fantastic job to think that we've only decided and we'll be executing what is quite a significant project very quickly.
In terms of the rotation, there's another piece of engineering, so we'll be working on the turret. There's modifications we will make to the turret which will allow us to effectively rotate the turret. Without getting into two much technical detail it's - rather than have a turret that rotates as its normal modus operandi, what we want is a turret that can make a one-off rotation and we've got engineering designs that we can put in place to do that. The second stage of the picture is actually installing that equipment and then once that equipment is there, installed and ready we will choose a date to then rotate the FPSO and reset, effectively, the anchor chains at the stern of the vessel. It's quite complex underneath, but it's as simple as that.
James Thompson from JPMorgan. Just a quick couple of questions on the Kenya early oil project. You've laid out a project today about 2,000 barrels a day. I think in the past you've talked about potential for a much bigger rail project. I just wonder if you could talk about how you might be able to scale that up from late in 2017. And then, just if you could give us a bit more detail on the project itself. Will it just be in Ngamia which fields will you be using for it and what costs are associated with it? Thanks.
We haven't changed our view on the ability to scale up, certainly on the upstream which is very much within our control we have views of how you could scale it from 2 to 4 and upwards to higher numbers, so that's not a big issue. I think one of the very important things for us is to understand the midstream, so the kind of road, rail and export tankage and export elements at Mombasa.
Very much our focus is let's try this at 2,000 barrels a day; let's prove to ourselves that the midstream can work and it can work efficiently and get to understand it. We don't operate those parts, so we need to understand them better before we're willing to really commit capital. The 2000 barrels a day is using existing wells with pretty much existing equipment in the field and the upstream is really just installing some rental equipment to produce at those sort of levels.
Absolute de minimis CapEx, single digit CapEx kind of levels, that would get us up and running. The rest is really tariff. Then, if that works well, then we're already working on expansion ideas, but we wouldn't enact them unless we could prove that the midstream system works.
No, there's no particular bottleneck, it's really - it's about making sure the road, the rail and the storage, you've got component parts. What you wouldn't like to do is go and make a big upstream castle commitment in the hope that all those components work which are not totally within your control. Much more appropriate to go for a lower volume where there's a de minimis CapEx and exposure and prove all those components work and then in a measured way, if appropriate, start to basically increase the offtake risk.
Michael Alsford from Citi. Apologies to come back to insurance, but I just wanted to clarify a couple of things. Have your insurers on both the hull and machinery and business interruption, confirm that you have a valid claim? And then just secondly, I know there's ongoing discussions around obviously quantum and cost, but have they confirmed that the plan you've laid out is fully recoverable, for example the offloading buoy is that essential in their view to getting production back up and running again? And then just a follow-up on Uganda, we've been waiting quite a while for the production licenses to be awarded and it’s always been quite shortly. But I just wondered what's holding that up and what are the timetable for that? Thanks.
I think as you know with insurance whether it's your car or your house or anything else, it takes a while for the claim to be processed, but every indication is that those conversations are going well; very receptive conversations with insurers. Right now, it's all about establishing the facts and all these sorts of things. But we maintain that we have insurance in place for precisely these sorts of things and that is what the insurance is supposed to cover. And equally, the quantum and cost, if you - you may recall that the hull and machinery insurance in total is cover for $1.2 billion and if you added up the gross numbers on Paul's slide it's far less than $1.2 billion.
Equally, the business interruption insurance that we, Tullow, have is for a period of three years or $900 million whichever cuts in first and that is far greater than we expect to claim under this policy. So it's going very well and the claims are well within, a number of [indiscernible] below the cover that we have. So it is a big issue, but it is very well covered.
I think maybe to build on Ian's point and then I'll come on to Uganda is that what we've been doing is the insurance team and the technical teams have been working very closely together, so the insurance interest and stakeholders and parties that are interested in this claim are heavily involved through quite direct mechanisms in our decision-making process. Every time we move to another step and we make a decision that has an implication on the quantum of the claim or some aspect of the claim, we've got a very efficient process set up that they then get involved and fully understand and have time to comment on, if they think we're heading off in the wrong direction.
I think, so far, we feel that's working pretty well and we have the full support of the insurance side on the direction of travel in terms of spread moor and then thinking about the necessity of a buoy, etcetera. I think on the Uganda production licenses, I think, the production licenses only really become important as you head towards an FID. As I say, there is quite a bit of momentum at the moment, having the decision been made on the routing.
What we see locally, at all levels locally, there's a lot of focus on the project and moving the project forward, more than I've seen in the last six/seven years and quite high level activity and engagement around the pipeline between the Tanzanian Government and the Ugandan Government. Our belief is that that will lead to imminent award of the production licenses, but we'll see.
This is Dragan Trajkov from Stifel. I was just wondering if you can help me out on the decommissioning costs coming up in the next couple of years. I'm reading from your annual report, it seems like from 2016 to 2018, you've listed $400 million of decommissioning between Mauritania and the UK. You're guiding for about $60 million this year or $40 million this year, something like that. So leaving about $360 million in next two years, 2017 and 2018. Are those real or are they going to be pushed back or can you give us some guidance on what this means and can you confirm that this is beyond the $270 million CapEx that you've guided for 2017?
Yes, I think first of all, decommissioning costs are very much built into our forecast and, Paul, you might want to comment on this or just the operational side a little bit. But those numbers are numbers which continue to be deferred as well, so you won't be seeing, I don't think anything like those sorts of costs over the course of the next two or three years and that $60 million or so is more indicative of the sorts of ranges per year.
Yes, no, I think the numbers we tend to have on our books on the commissioning side tend to be conservative and as we get into the action of them, they tend to come down rather than go up, is our experience to date on some of the work we've been doing in the UK. But again, the timing's likely to be much more spread.
Charlie Sharp from Canaccord Genuity. Just a question on TEN; can you tell us what sort of milestones to look out for in terms of the production ramp-up to 80,000 at the end of this year? And in terms of next year's expected 65,000, can we assume about a 20% decline rate beyond that if there is limited investment in TEN?
In terms of ramp-up, always hard to define. You know start point of zero and you know the end point of the capacity. The great difficulty is trying to judge how quickly it will ramp up. So I have to say I'm not sure I can give particular milestones. But the way it will work, is we effectively - we've got a number of risers and we bring on each riser, you know risers might be 20,000/25,000 barrels a day. You'll bring that on; you'll get that stable; you'll make sure the system's working. If there's no hiccups which often there is and you shut back down and then have to re-start it again, if that system's working then you're likely to then bring in another 20,000/25,000/30,000 barrels a day.
So it can, if it moves smoothly, it can ramp-up fairly quickly. If you have a number of hiccups, as you often do with commissioning in a new complex topsides, it tends to be a series of kind of stop/starts rather than layering on, you know we know we're going to get 15,000 barrels a day here and then another 5,000 barrels a day - it tends to be large blocks. The pace of those blocks coming in just is how smooth the final commissioning with hydrocarbons is going.
And then the second question on, really our intent, I can't see a scenario where we won't start to infill drill on TEN. These wells, they have large capacity; we're estimating next year that, even with the limited well-stock we have, because the wells will produce 10,000 barrels a day to 15,000 barrels a day, some up maybe as high 20,000 barrels a day. What we would intend to do is look at what these wells produce. We would have preferred to have had some flexibility, that if they don't meet the plateau, we could have added a well or two. We don't have that, but at least it allows us to sit and watch the performance of the field which means that, when we do come to infill drill, we'll actually have a significant amount of data to make those decisions on.
So I think it's much more likely that we will see performance from the field; we're estimating that to be in the mid to low 60,000 barrels a day for next year. Then as soon as that loss is decided, we would add, you know even one or two more wells, we'd then start to ramp you back up and head back up towards a full year of plateau as you get through the second half of 2018 and into 2019.
Could we see if we've got any questions on the conference call please?
We will now take our next question from Thomas Adolff from Credit Suisse. Please go ahead.
I have two questions please. Let me start with the easy one on Wisting; you had some good results recently and I wonder whether you can give an update on the resource range, if any? The second question is going back to asset disposals. During the call you did highlight that you only want to do it at the right time and really who knows what the future brings?
But just to be clear on Uganda, I just wanted to double check that your intention is still to farm out part of your equity ahead of FID? Clearly, the lessons you've learned from TEN was that you shouldn't take FID until you've right-sized your exposure. So really the question is what if 2017 and 2018, oil markets are still in the range of, let's say, $50 to $60 and the disposal market remains tough and Uganda is a project that is driven by Total and they say we're going to go ahead with FID? What are your options there? Thank you.
Thomas, Angus here. On Wisting, the Wisting well was a success, the long-reacher horizontal well, 20-meter oil - 22-meter oil column and a long section of pay, 1,250 meters in net pay. Those numbers are being used by the venture to determine the volumes. That work is still going on. We expect the operator to submit new volumetrics to the - or revised volumetrics to the regulator in the last quarter of this year.
On Uganda, we don't know what the oil price is going to be, as we said, but as Paul said, it is viable at the current oil prices. What we've tried to do is to make the Company as flexible as possible that we can adjust to whatever the environment is. If the M&A or the farm-out market isn't great by the time we come to FID, you can see from the cash flows, it is well within our capability to stick with Uganda at 33.33%.
So, I think it's not an issue for us. We would - the cash flow from that to first oil is quite small or sorry, the cash outflow, but we believe that Uganda and Kenya are some of the best projects out there currently in this sort of environment and that they are very attractive. To make the point earlier on, when we were looking at maybe farming down the two projects together, we had a lot of interest.
But, in fact, actually, there's more interest now, because they're two separate projects. What you have with them over the next 12 months as we move towards the FEED studies, is the biggest single issue that was affecting the ability to capitalize these projects was, when first oil was and there was a lot of frustrations in relation to Uganda and making - the decision-making process to get first oil.
So the uncertainty about getting to first oil wasn't there. I think what we have now is we have two projects where we've a lot more certainty when you can get the first oil and, therefore, people can put a proper valuation on it. We're pretty comfortable at the appropriate time that we will do it. But, as I say, if you look at the cash flows and look at the individual things we can well afford the current cash flows. So we're not going to be pressurized into selling them cheaply.
We will now take our next question from David Gamboa from TPH. Please go ahead.
It's actually Anish Kapadia from Tudor Pickering; a couple of questions. One on cash flow and one on exploration. In terms of cash flow question, you've got trade payables and current provisions of over $1 billion and in the first half of 2016, we saw a higher cash out flow with reduction in accruals. So just wondering what's your expectation of how the trade payables and provisions position will trend over the next year or two and, hence, the associated cash out flow potentially?
And then secondly on exploration opportunities just wanted to try and understand why Tullow didn't take an opportunity to farm into Liza in Guyana or SNE in Senegal pre-drill. What was it that, I suppose, put you off those and just kind of thinking of that in the context of Tullow being a leading acreage holder in both the Guyanas and in West Africa as well and having missed out on two of the very significant finds in the region.
Also thinking about it from a finding cost perspective, I think Tullow in the past has targeted a $5 per barrel finding cost. It seems like in the market now, we've seen recent transactions this year, oil barrels selling for $1/$2 of discovered resource. So just how you think about exploration versus buying resource, given it seems so cheap at the moment? Thank you.
Okay, it's Ian here, I'll answer the first part around trade payables and current payables. Really, there's two elements to that. The first thought is the trade payables which largely but not wholly, is around CapEx and other programs. But you've got to remember there's an offset to that on the other side of the balance sheet which is cash cooled and debtors around our partners as well.
The net of those two is more like about $200 million and you would expect always to have some sort of balance there, but that $200 million could come down over the course of the next months and in time consistent with lower activity levels. But just to make the point there that the exposure if you like is more of a $200 million exposure and not a $700 million exposure.
Secondly, in terms of the other element of it that is really regarding the timing of our next levels of amortization, of our RBL debt facility. But, actually, the expectation is that we will only amortize a further $245 million of that in October and then, before any further amortization, we will re-finance the facility, so that's really the explanation there.
On the regional exploration question, why are we not in Liza, why are we not in SNE. We're focused very much on low cost oil plays, so we were certainly aware of the oil potential in Liza in the ultra-deep water. But as you might remember two or three years ago, we made a very clear strategic move away from complex drilling to low cost wells in shallower water. What we've been able to do is target the Liza play in 100 meters of water and thereby offer Tullow investors access to the Liza play in a shallow water setting. So it was a very conscious choice to take the shelf, rather than the ultra-deep water in the Guyana.
On SNE, it's a nice discovery. We're on the same play, same trend in Mauritania. We've got a long north south tract of acreage which follows the same shelf edge play system, so we're very well placed for that play as well. I don't feel we've missed out on that play overly. The other guys have done well to find it, but we've got similar acreage in Mauritania. On M&A versus organic exploration your numbers are quite right, quite valid observations.
What we do feel though is that our exploration activities going forward are lower cost. Certainly, the $5 a barrel you mentioned is a historical number. We would be looking to be exploring well under $3 a barrel and even some of our East African exploration we'd hope to be under $1 a barrel. We do have quite unique positions and access to low exploration, low costs.
Versus M&A, that's a big question always in the industry. But the advantage of finding your own oil means that when you make a discovery you've got your own beginning of life cycle, young fresh light oil field which you can plan and monetize through its life cycle. Whereas acquiring someone else's oil you might inevitably be locked into programs that you would rather not have locked into in detail and you might be much closer to abandonment. So we prefer to find our own oil if we can.
We will now take our next question from Henry Steel from Odey. Please go ahead.
Just two quick questions. One is on liquidity, probably for Ian. So I notice that you guys tapped into the RCF rather than fully utilizing the RBL. The last $300 million on the RBL, the junior part, could you give us an indication of what the interest costs would be if you did draw down on that and what your decision was for moving into the RCF rather than fully drawing on the RBL?
Secondly, is on the pipeline tariff in East Africa, the $10 to $12 a barrel. Given the size of the CapEx needed, what kind of IRR are you assuming for the capital providers for that pipeline?
Okay, so I'll answer the first part. There's a choice obviously between the RBL and the RCF and the RBL would be - the senior part of the facility is the one that we routinely use. The junior part is more for a contingency part of the facility. We tend to naturally favor going to the RCF after using the RBL and, obviously, we've got the convert in place now. We don't really have any plans to draw down on that junior part of the RBL which does have a 1.5% to 2% higher interest rate in that. But it's not something that we plan on drawing down.
I think on the pipelines for Kenya and Uganda, there's just an underlying assumption of a utility-type IRR. These are relatively low risk investments for the appropriate investor where they'll be tied up with take-up-type arrangements.
We will now take our next question from [indiscernible]. Please go ahead.
So first to understand on the RBL refinancing. You say that you are going to do this ahead of the next amortization and this is less than a year away and, of course, this is a large facility. Can you give us a bit more color on whether you have already engaged with the banks regarding the full refinancing and what the initial feedback is in terms of the sizing and the cost? So that's on the re-fi.
And then moving back to insurance; conceptually, how should we think about the Company being compensated for business interruption? Should we think about the number of lost barrels at the current price or it would be lower, given the fact that production has effectively deferred rather than lost and the barrels stay in the ground?
And third on the CapEx, can you give us a bit more clarity how should we think about the cash outflow related to CapEx? Of course, for H1 you have reported the CapEx of $589 million versus the actual cash impact of $781 million. So when you are guiding to $1 billion CapEx for the full year, is this the impact on the net debt for the end of the year or the impact would be higher than that?
Okay, Ian here. So I think the first point is on the RBL redetermination. We routinely have a redetermination every six months with our banks. We plan to refinance the RBL sometime before the - so we have an amortization in October which we've always stated that we plan to let happen. But the next amortization would take place in March of 2017 and we plan to refinance the RBL before then. When we have the redetermination conversations in September of 2018, that will be the start of the process and, indeed, leading up to that process, we will be market sounding with our banks as to when is the appropriate time to refinance in that period.
So that's very much ongoing. The banks know it's coming. The diversification we did with the convert, etcetera., is all helpful in that regard. So this is not a surprise to the banks; it's a piece of business to be done which they are expecting. I think, secondly, to say it real simple, the business interruption insurance, the lost production is compensated for at a fixed price which was set some time ago, of $60 a barrel.
Thirdly, on the CapEx, as you said, we report our accrued CapEx and sometimes obviously there are differences in the timing of that between accrued, what's accrued and how the cash flow is actually paid in terms of timings over yearends. That's just a fact. Clearly, the accrued CapEx is what's reported as CapEx. The cash flow element is the one that, as you rightly said, turns up in the cash flow.
Okay. I think we'll draw the Q&A session to a close. Thank you very much for coming. If you have any further questions, feel free to get hold of myself, Nicola or James. I think it's important to keep James very busy in his last few weeks in Tullow, so I would encourage you to do that. Thank you.
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