Tullow Oil Plc Edited Transcript of TLW.L earnings conference call or presentation 29-Jul-15 8:00am GMT by 24hGold

	Edited Transcript of TLW.L earnings conference call or presentation 29-Jul-15 8:00am GMT

	Half Year 2015 Tullow Oil PLC Earnings Call (UK/European) London Jul 29, 2015 (Thomson StreetEvents) -- Edited Transcript of Tullow Oil PLC earnings conference call or presentation Wednesday, July 29, 2015 at 8:00:00am GMT TEXT version of Transcript ================================================================================ Corporate Participants ================================================================================ * Aidan Heavey Tullow Oil plc - CEO * Ian Springett Tullow Oil plc - CFO * Paul McDade Tullow Oil plc - COO * Angus McCoss Tullow Oil plc - Exploration Director ================================================================================ Conference Call Participants ================================================================================ * Jamie Maddock Morgan Stanley - Analyst * Mark Wilson Jefferies - Analyst * Dan Ekstein UBS - Analyst * David Mirzai Societe Generale - Analyst * Alwyn Thomas Nomura - Analyst * Stephane Foucaud FirstEnergy Capital - Analyst * Brendan Warn BMO Capital Markets - Analyst * Al Stanton RBC Capital Markets - Analyst * James Hosie Barclays - Analyst * Alex Topouzoglou Exane BNP Paribas - Analyst * Richard Griffith Canaccord Genuity - Analyst * Michael Alsford Citi - Analyst * Thomas Martin Numis - Analyst * Ed Maravanyika BofA Merrill Lynch - Analyst * Anish Kapadia Tudor Pickering Holt - Analyst * Thomas Adolff Credit Suisse - Analyst * Gerry Hennigan Goodbody Stockbrokers - Analyst * Peter Ofus Ironshield Capital - Analyst ================================================================================ Presentation -------------------------------------------------------------------------------- Aidan Heavey, Tullow Oil plc - CEO [1] -------------------------------------------------------------------------------- Good morning and welcome to the half-year results presentation. The results are pretty much in line with expectations. They don't fully reflect, yet, the resetting of the business that we mainly completed in the first six months of the year. They are, obviously, impacted by the falling oil price. We believed that this unstable oil price and this environment may stay slightly longer than most people anticipated. We decided last year to reset the business to be competitive at a low oil price environment and we picked, at that time, around $50. That resetting of the business has been completed. We now feel we're competitive at these levels. We have completed a major cost cutting exercise. The quality of our assets at a low oil price environment has meant that we've been able to get some additional funding and headroom and liquidity from our banks, and Ian will take you through that. We're comfortable with that, going forward. We've a very strong high margin cash flow from our assets, and we've underpinned and secured that by our hedging program. Quite importantly, at a time like this, is making sure that your major projects are on time and on budget, and a lot of focus has been done on that. As I say, we have reset the business. We're pretty comfortable that we are competitive at these levels. Obviously, we have no idea when the oil market will change or when there will be some stability back in the market. You obviously need stability, and you need a fair view on the long-term oil prices before you will make any major strategic decisions. Right now, it's keep the ship tight; keep it well run; focus and continually focus on costs; and make sure that you get the best rate of return on your major assets. That's what we are doing currently. I'll now hand you over to Ian, who'll take you through the results. -------------------------------------------------------------------------------- Ian Springett, Tullow Oil plc - CFO [2] -------------------------------------------------------------------------------- Thank you, Aidan, and good morning, ladies and gentlemen. I think, as Aidan said, we took a number of steps in the fourth quarter of 2014 to reset the business around $50 a barrel. In particular, we allocated capital to high margin projects: Jubilee, our non-operating West Africa production; the TEN development. And equally, took capital away from exploration and we did not pursue certain development projects like Banda and Kudu. We targeted delivery of cash savings internally through efficiencies, and simplification with our $500 million the next three years cost reduction program. We suspended the dividend, and we also took action with our banks on liquidity management. I think the first probably is just to look at how we're doing in that regard. This slide suggests we've made some pretty good progress in the first half of 2015. Our underlying production, our West African production, strong performance, slightly ahead of 2014, which is good. Our hedging enabled us to offset the lower oil price, a $146 million benefit from our hedging programs in the first half of 2015. And a further $300 million at the moment mark-to-market, positive position for the future. Our operating cash flow: whilst oil prices were down around $51 a barrel, our operating cash flow only reduced by $26 a barrel. That really was a function of the combination of those hedging benefits I talked about, but also, at lower oil prices, the benefit of increased PSC entitlements. Our capital budget also, we reduced our budget, as you're aware, to $1.9 billion. And we remain very much on track to come in at that number or below, and perhaps we'll come in a little bit lower than that. From a cost and liquidity management perspective, we're looking to see our operating costs overall for the year down on last year. Our cash overhead costs, we are on track for delivery of those $500 million cost savings over the next three years. We have made some very significant staff reductions, which were an outcome of our simplification efficiency project. Some two-thirds we identified reductions from that project have already left the Company in the second quarter. The balance, remaining one-third, will be largely [the third], and the project will be complete by end of year in terms of staff reductions. From a bank perspective, we actually increased our facilities by around $450 million. We maintained our debt capacity with a redetermination, as well as getting a relaxation of our debt covenants. In terms of exploration write-offs, lesser activity set, and very significant saving on the level of exploration write-offs. Also in the first half, we put the Uganda CGT litigation behind us. Overall, our focus very much on production, getting those hedging benefit, actions to reduce capital costs and dividend, and that provides us good liquidity beyond TEN first oil. Looking at the financials, I think they very much speak for themselves. And the key themes of those which we'll just expand on a little bit more in terms of income and cash really, are those benefits of hedging, the impact of lower oil prices, the reduced exploration write-offs. And so I'll move on and actually talk about the net income comparison between the first half of 2015 and the first half of 2014. You can see there the loss we made in the first half of 2014, potentially further exacerbated by the drop in oil prices, but offset by the hedging, and offset by the benefits from higher oil volumes and the additional volumes we obtained through increased PSC entitlements, partially offset by the reduction in gas volumes, which themselves are largely related to gas disposals. But also, you can see there, the big benefit of reduced exploration write-offs, as well as lower taxes as well. And so overall, before we take account of the provision of the Uganda CGT and the restructuring cost, a positive net income for 2015, first half of 2015, and then slightly lower when you take those accounts into effect. Looking at the source and use of funds, I think it's actually important on this slide to maybe look more at the, rather than the bar chart but actually the numbers on the left-hand side. And what you can see there is that the net loan drawdown, actually in the first half of 2015, at $684 million, was actually lower despite lower oil prices than the first half of 2014. In any event, we normally expect the first half of the year to be higher than the second half-year, due to the timing of taxes, tax payments in the first half and things like the Norway tax rebate occurs in the second half. But as you can see there, despite the lower operating cash flow offset by the hedging, we had benefits of lower CapEx, of lower cash tax paid, lower finance costs, etc. So actually, it begins to show that on a cash basis, and in these current market conditions cash is very much king, that actually our cash outflows are significantly reducing. This slide looks at our CapEx, as usual. We are saying here that actually whilst our $1.9 billion CapEx is still our target for the year, we split it slightly differently: $250 million for exploration, $1.65 billion for D&O. It's our target to have exploration around $200 million in making the big reduction from circa $800 million the previous year, one or two costs just a bit sticky in terms of getting them out of the system, so we're currently at $250 million, we think. But nevertheless, the $1.9 billion is a number which we believe will be achieved or beaten. And when I say beaten, beaten in the right way, i.e., we'll come in lower than that, not higher. I think it's important also to recognize that in our CapEx, of that $1.9 billion, around $1 billion of that is for TEN. In 2016, there's about another $500 million net to go in 2016. So we put on there, actually, our 2016 CapEx guidance, if you look at it from $1.9 billion, the $1 billion we're spending on TEN in 2015 and $0.5 billion in 2016, that $1.9 billion will probably maximum of $1.4 billion and probably even in the range of $1.2 billion to $1.4 billion. Equally, when TEN is done, then in the second half of 2016, in the run rate in the second half of 2016, there's probably only about $400 million for the second half of 2016. So you can see that our CapEx program, while significant in 2015, is coming down, and that will also, obviously, impact our future cash flow positively. Moving on, looking at our debt position. I think important there to say that we have $2.3 billion of facility headroom as we speak and expect to have circa $1 billion of debt capacity at current -- if nothing else change in terms of current oil prices, no other activity in terms of portfolio or anything else, then expect to have $1 billion of debt facility around mid 2016. Looking at our hedging, just to mention there that I think the point is not only have we benefited the first half of 2015, $146 million, but also we have this mark-to-market position going forwards. And not only does the hedging benefit our revenues, but it also benefits our debt facility as well. The banks take into account our hedging programs as they're valuing our future cash flows, which gives us additional debt capacity. And I think the point also to make here is that remember that, when we put our hedges in place, whilst we do downside protect, we do use collars so actually we do retain access to upside as well. And we are putting in place hedges not just for 2015, but also through 2016, 2017 and into 2018 as well. So final slide, in summary, is that we've taken some proactive measures in terms of our strategy, in particular our financing strategy, in the fourth quarter to manage the business in an oil price environment. We have quality assets which are generating good margins, despite lower oil prices, and benefits via the hedging programs, which gives us some financial flexibility and headroom. And that's enabled us with our banks, for example, to gain both additional debt facilities and to also manage our covenants as well. And our financial strategy, going forwards, is to further deleverage the Company and actually deleverage it beyond the natural deleveraging that would occur from TEN first production in the first half, when it comes on stream at the end of the first half of 2016. So we're going to continue to focus very much on our business and our investment and maximizing production with our hedging, our costs and capital management. We'll look at active portfolio management and farmdown activity. We're going to manage our East Africa development CapEx. Paul will talk later about how we're looking to -- how those development costs, which are future costs in East Africa, will benefit from the low oil price environment in terms of timing. And, just like all our assets in our portfolio, nothing is sacrosanct in terms of some portfolio activity as well, so the potential to potentially reduce our equity in East Africa as well. Overall, through the medium term, we're looking to get ourselves down to a target net debt to EBITDAX ratio of less than 2 times. When we're in that position, that gives a lot of financial flexibility. In any event, we're very well positioned if and when oil prices recover, having reset the business at $50 a barrel. So that deleveraging will then enable us to reinstate the dividend, which we think is an important thing to aspire to. We'll do that when the time is right, when we have the financial capacity to do so. And also to correct that tension which we think is a healthy tension between dividend and capital spend. As well as, again, when we have the capacity to do so, looking to increase our exploration spend, probably just saying more like a cap of about $400 million. And I think, as we look back over time, that certainly we probably did some of our best exploration when we were spending around $400 million a year. So I think about $400 million, and no doubt Angus will talk some more, but in terms of the right level of spend on exploration and one which will enable us to get involved in some interesting and exciting exploration projects. So that's the strategy summary. I think, overall, action taken and in good shape for the future. I'll hand over, with that, to Paul. -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [3] -------------------------------------------------------------------------------- Morning. Thanks, Ian. Whilst it's been a rather challenging six months from a macro perspective, it's been a pretty positive six months with respect to progressing, picking up assets and development, and the overall performance of the producing and development assets. And also in ensuring trying to move forward our production assets, the developments. We've also been looking for ways in which we can benefit from the external environment, mainly through scheduling and improvement in development costs. In terms of production, very strong first half. As you're aware at the trading statement, that led us to upgrade our guidance for the year to 66,000 to 70,000 barrels a day. And whilst we've had the recent issue, I'll talk a little bit about it in a future slide, around Jubilee and, therefore, we've had to revert Jubilee. We had upgraded it from 100,000 to 103,000; we're reverting it back to 100,000, given the issue we had with the gas compression. We're still confident we can deliver within the upgraded Group guidance, given the strong performance of the other West African assets. That guidance includes a contribution from the Onal fields which were on track to complete a deal with the government in the second half. This then leads us on to 2017 and achieving the target of 100,000 barrels a day as TEN comes on stream, which we'll talk about. And then with respect to the European production, it's pretty much all delivering on track. The only adjustment made, which we did at the trading statement, was to revise guidance down by 1,000 barrels a day, which was due to the successful sale of some of our Dutch assets. So no change on the European. Just before I go into the assets in detail, just thought it's worth getting a quick overview relating to the 100,000 barrels a day, and then what other potential's in the portfolio. So if you wander round the development portfolio: TEN, we're going to talk about that, on track delivering roughly 35,000 net to Tullow in 2017. Jubilee: okay, I'll be talking about performance of the field how it is currently. But we're also well advanced on the full field development, the greater Jubilee area, which will provide us with a sustainable 40,000 barrels a day, when we look at Jubilee, as a minimum. West African portfolio continues to deliver circa 30,000 barrels a day. So you put that together, we're well on track to achieve that 100,000 barrels a day in 2017. And then on East Africa, I'll talk about progress there, but just again flagging that there is momentum gathering in the development with East Africa, and our net share is circa 100,000 barrels a day to Tullow. So really a solid asset set, fairly young and immature assets so they have a long life ahead of them. And it gives us significant potential for portfolio management as well as cash flow. So just going through the assets in a little bit more detail. Nothing significant to report in West Africa, other than a very strong first half, and the outlook for the second half is equally as strong. You can see we've, over the last four or five years and looking out to the future, oscillating around that 30,000 barrels a day. This year is benefiting from last year; we had a lower year because some of the capital programs were slightly delayed. That's having a knock-on benefit this year where we're taking that benefit. Expecting to spend about $200 million this year and that will set us up well for 2016 and then into 2017 as we look at what level of expenditure we'll see then. All of this includes the Onal field which, as I mentioned the discussions with government going very well, and we're very confident of securing that license and getting that back in the portfolio in the second half of 2015. If we move on to Jubilee, the field had a stronger first half than we anticipated. That was mainly due -- we'd been a bit cautious about the gas export and the sustainability and the uptime with regard to gas export. As it happens, the onshore plant was working well and the first half ramped up more quickly and was more stable than we anticipated. Before we had this recent challenge with the offshore compression we were sitting around 80 million, 85 million standard cubic feet a day. The knock-on effect of that was, we were then injecting less gas and we were starting to see that positively impact reservoir performances; we put less gas in the ground. So that really resulted in a stronger first half, which was about 105,000 barrels a day; led us at the trading statement to upgrade the full year from 100,000 to 103,000. So since the trading statement, we have had our main gas compression go down offshore. We had all the parts on for that machine; we're in the process of replacing all the internals. That's well underway and we're highly confident that we'll have that machine back up and running, fully commissioned by the middle of August at the latest. And so we will lose some -- we're running about 65,000 barrels a day at the moment rather than 105,000 to 110,000 barrels a day. And as I say, we'll ramp back up as we go towards middle of August and get back on track. With regard to costs, we are starting to see a little bit of downward pressure within the Jubilee operating environment. That's something that is a slow adjustment through the year and we're highly confident, you'll seen the fact book and as I focus here, forecasting an OpEx per barrel below $10 for Jubilee. And then, of course, as I've highlighted before, the next step is when you bring on TEN in 2016 and get it ramped up in 2017, that will have another downward pressure point for Ghana operating costs. So we'd expect to see the medium-term operating cost in Ghana to be below $10 a barrel and be below the yearend figure of circa $9 when TEN starts to contribute to the denominator. We're planning to drill a couple of infill wells this year just as part of an ongoing program. One is done, we'll be tied in, in August, and the second one's planned for the second half of the year. But more importantly, we're really making some serious progress on the greater Jubilee full field development planning. The key thing there really is, we're talking to Kosmos about integrating the whole MTA area and submitting one development plan to government. That will be submitted by yearend, and that plan will really look at optimally developing not only the reserves within the Jubilee unit, but the surrounding reserves as well. And again, as part of that plan, we'll be looking at the optimization of gas export and also what is the optimum size of the facilities offshore; should we put major capital investment to upgrade the FPSO, or do we go for a longer plateau. And that's something we're working on at the moment to look at the optimum, and will be part of the submission of that development plan as we go towards the end of the year. TEN: thankfully, nothing new to report really since the trading statement. It's on track, on budget. The FPSO is 92% complete; they're just going for mechanical completion and final commissioning, and that's very much on track to sail to Ghana around the end of this year. Subsea fabrication, all the kit that we're putting on the sea floor, is 95% complete. A lot of it's already sitting in Ghana waiting for vessels, and the rest of it is pretty much on route to Ghana, and will be there as we require it as we start to ramp up installation. The installation has actually started already. A part of that subsea fabrication was local content. Often, there's a kind of concern about the local content side, well actually in terms of the time, how it impacts schedule. What we found, and our contractors have found, that we've done substantial local content down in Ghana and it has gone incredibly well. So a lot of the kit has been built within Ghana and it is sitting there in Takoradi and Sekondi ready to be installed. And then on the drilling side, as you're aware, all the wells that we need for startup have already been drilled and we're completing the third of the development wells as we speak. So very much on track for first oil. Then if we wander across to East Africa, first of all really just the Kenya appraisal program. It's been very successful, both from an operational perspective and a subsurface perspective in terms of the data we have been collecting. Really, the wells that we've drilled now have confirmed our views of the volume of oil in place, of all the major discoveries there. And the dynamic testing has shown good strong productivity. The other thing we've done is, we've just completed the Amosing EWT which has shown, and importantly we did this successfully both offshore Ghana but importantly onshore Uganda, has shown good and large connected volumes, which is very important for your water flood and your recovery factors. So really confirming that we can assume water flood recovery factors within onshore Kenya. And really, I think a lot of that success was built around the early decision to shoot a 3D seismic survey across the Lokichar basin. So the use of the seismic survey has made the appraisal program more successful than it would have been if we hadn't had that data. So we're now well underway in terms of putting together the development plan; we're already discussing the development plan with government, and those will be submitted before the yearend. So overall, the work to date has very much underpinned the 600 million barrels that we thought in the main discoveries. And as Angus will point out, we see that some of the lower productivity zones and some prospectivity could enhance that 600 million as we progress our understanding of the basin over the next year or so. When we look at the slightly broader picture in East Africa, the big topic in discussion between the JV partners and the governments at the moment is the route of the export pipeline. We had already done all the work to be able to properly assess both the northern and southern route. The governments got on board their own independent advisor. That conversation is getting very mature and we expect to see an outcome from the conversation about which route the governments are going to select this quarter. That would allow us to then move on from a pipeline perspective into FEED in early 2016 and progress the FEED for the pipeline, and get onto more detailed commercial discussions, and our financing structural discussions, about how that pipeline company, or pipeline companies are going to be set up, and how they interact with the JV partnerships, in terms of the suppliers of feedstock. And then in the upstream developments, as I said, Kenya has now pretty much caught up with Uganda. Both will be in a good place to move to FEED to early 2016, for both upstream developments, given the progress we've made in Kenya. And really, the pipeline FEED is the trigger, that's the critical path, so therefore, when that gets going, we will then trigger the upstream FEEDs and move them forward. Other important studies such as environmental studies are ongoing at the moment. ESIAs are starting to be prepared. So overall, working hard. There's a lot of work to be done between now and the end of 2016, early 2017, which is our current ambitious target for FID. Another big, important point, though, is the overall capital cost in the current environment. As I said, we continue to look for ways to benefit from the current environment. We did a fairly extensive independent study. Obviously, the real test will be when you go into the market and tender all these major contracts, but ahead of that, trying to understand what is happening with CapEx deflation. We've done a study across onshore activities, and that independent study suggests to us that we should be anticipating CapEx deflation of around about 20%, on an already low $6 a barrel for Uganda. So major value enhancement from CapEx deflation, and then obviously, the work that we're doing on the integration of the pipeline between Uganda and Kenya. So overall, things are progressing well. We're well on track to meet our 100,000 barrels a day. And we're well on track to get East Africa progressed to the point where, as Ian highlighted, we can then use that as something that will ultimately provide cash flow, but provides opportunity for portfolio management as well. So with that, I'll hand over to Angus. -------------------------------------------------------------------------------- Angus McCoss, Tullow Oil plc - Exploration Director [4] -------------------------------------------------------------------------------- Thank you, Paul. Morning, everybody. As you've heard Aidan, Ian and Paul say, the business has been reset for the $50 oil price environment, and exploration is obviously doing its part in adapting strategy to that current environment. So I'd just like to run through with you how we are adapting to mitigate the risks and the expenses that we face. Then also to reassure you that we have still that consistent, long-term focus on high impact exploration, through a very strong and competitive portfolio. But first on how we're adapting to mitigate the risks and expenses. First of all, reducing that cost exposure, that's a corporate objective. And in exploration, we achieved that through farming out early to spread the risk. We've had some good success so far this year, with some dilutions to our positions in Mauritania, both C3 and C10 dilutions. And dilutions in Norway, most notably diluting the position in Zumba pre-drill. On revised risk screening, a corporate objective in exploration, we're taking a much tougher line there, tougher decisions thresholds, on what we do and what we don't do, as we high grade our exploration programs. An example of that would be us pulling out of the sidewinder activity in Mauritania. You've heard me, a year ago, talk about how important we felt it was to avoid complex wells. That very much continues in adaptation to the current environment. We'll be targeting normally pressured oil plays, avoiding those complex over-pressured situations, so for example, stopping the Zaedyus type of play, and focusing on onshore and simple offshore settings. We're focusing our talent, our human resources, deploying our geoscientists where they can really make an impact on portfolio rejuvenation, taking these countercyclical opportunities to get into some low holding cost, high value positions. And to focus our staff and our talents on oilfield development. So many of our geoscientists, at the moment, are actively supporting the TEN development and making sure we get to that TEN first oil, hold that plateau in TEN, hold that plateau in Jubilee, and extend the plateaus in Central and West Africa. So those are the adaptations, but there's some consistent, long-term backbone to the strategy and the program. We continue to remain focused on conventional light oil, that's where we see the value; focused on materially valuable core play campaigns. The campaigns bring us synergies and allow us to apply cost effective technologies. Particularly the emphasis is on non-seismic technologies. FTG, we were successful with that in East Africa, but also ambient enhanced imaging, which I've talked about before. These sorts of technologies and passive technologies are about one-tenth of the cost of the traditional seismic methods. But we are, indeed, seeing the traditional technologies cost structure coming down. Inversion technologies, Ji-Fi, which we've developed with our technology partner, Ikon Science, also helping us to achieve our ends in a very cost effective way. Focus still on Africa and the Atlantic; that's where our in-house geological expertise lies, and we stay focused on that geography. And that's where our strong above ground relationships are, so we leverage those. Then really two activity sets: one around the infrastructure led exploration, and the other about finding the next hub. Infrastructure led exploration is building on our West Africa success, and building on our East Africa success, adding to these positions, leveraging the infrastructure positions that we have, and that we will soon have there. And then on finding the next hub, we've reorganized ourselves as part of this simplification project that you've heard of, streamlined the way we work. And we have a very competent and capable team, looking out for, and getting after, frontier new venture positions to open new plays and new basins. So we continue to invest for our future, drilling these high graded trigger wells that come from this activity. You might remember the importance of these trigger wells in our history: Mahogany-1, opening up Jubilee; Buffalo-1 opening up Uganda; [00-1] opening up TEN; and Ngamia-1 opening up the South Lokichar basin. These happen, on average, about every 20 months in our history, and we continue to expect that to be the case, as we focus on high grading the inventory, going forward. Trigger wells coming up. We've got Cheptuket, in the Kerio Valley Basin, which I'll talk about in a moment, and Tausi in the North Lokichar Basin. And we've got other trigger wells lined up for future years in Surinam, Namibia and Mauritania. So how do we go about our new venture activity? Obviously, we have to impose much tougher screening criteria in this current business environment. You'll see, on the left side there, a list of what we consider to be off limits for exploration in the current business environment. I shan't read through that whole list, but just pick a couple, or two or three as we go through. Deepwater gas is obviously not something that we would want to get involved with, neither shale oil. Overheated bid rounds, complex wells, we've talked about. Significant over-pressures, all of these lead to very complex, high cost activities. So they are off limits, and we're very strict about filtering them out. So having screened those out, then we go ahead and screen on commercial aspects. Testing our opportunities of $50 oil, looking for low cost supply opportunities, ones that are certainly value accretive. We screen on capital and risk. We want to look for that low capital exposure. It means managing our equities. We need to get the right balance of equities for the reward, and control that through joint venture partnering and make sure that we have control over the joint venture spend, either through operatorship or through our joint operating agreements. And then of course, fundamentally, the geological screening has to be solid. We need good quality rocks, we need the materiality, and we need campaigns which have net present values in excess of $1 billion; something that will really move the needle. And it's really having applied these types of screening in the past, and certainly, going forward, with the increased rigor, that's how we've landed up with the high margin oil portfolio that we have today, in the onshore rifts, in the simple offshore positions in Africa, and in our production heartlands. So just to give you a bit of an operational update on exploration, albeit a reduced activity set this year, but we have been able to consolidate and firm up our views on the basin ranking in East Africa. Clearly from top to bottom here, in order of maturity, right up at the top obviously, the Lake Albert Rift Basin, the green colored basin, 1.7 billion barrels of recoverable oil discovered in the bag. South Lokichar, nine out of 11 of our wildcats have been successful there, discovered 600 million barrels recoverable Pmean resources with new plays and prospects to be tested. One of the interesting things that's come from not only the 11 wildcats that we've drilled, but we've now drilled some 30 wells, including the appraisal wells that Paul talked about, and the 3D seismic, have shown us that we have a world-class source rock in the South Lokichar basin over 200 meters thick, and really is absolutely a world-class source rock, very rich in organic content. And from that, and from our basin modeling, we compute that that source rock should have expelled about 25 billion barrels of oil. Now, when we look at the oil that we've discovered so far, it's about 2.2 billion barrels stoip, of which 600 million barrels are recoverable, that 2.2 billion barrels stoip is less than 10% of the oil expelled from the source rock. We would typically expect, in a new basin environment, to be able to find 20% of the oil expelled from the source rock to be trapped in viable traps. So we think there's scope to double the volume that we've already discovered in South Lokichar basin through further exploration. So we're very active on that, and I'll come on to that in a minute with some examples of prospects. It also tells us something about the region. It tells us that we have a very rich source rock in the South Lokichar basin and, therefore, our expectations that there are other source rocks in this basin trend remains positive. And whilst we have had a dry hole at Kodos and a dry hole at Engomo, there are many independent plays away from the basin margins that are untested and, therefore, we remain very excited about the opportunities on trend in this exciting acreage. We have undrilled basins coming up to be tested Q3 2015 through to the end of next year, including the Cheptuket well in the Kerio Valley basin, in the south of the acreage, and the Tausi well in the North Lokichar basin. Just zooming in a bit on the Kenyan acreage, in the middle map there you see the South Lokichar basin. Up in the northeast corner four new prospects: Erut, Elim, Ngorok and Kori, which are causing a good deal of interest in the exploration team, particularly when we reflect on the high expulsion rates from the source rock. We're still very interested in that basin center play and we have a good prospect at the southern end there, Lopara, which we'll be addressing in future programs. On the left-hand map, you see the area just to the north of the South Lokichar basin. It's called the North Lokichar basin and the Tausi well should try to open up that basin in a basin center position. And then on the right-hand map you see the southernmost part of the acreage, the Kerio Valley basin, where we target the Cheptuket well to test the scope for that basin. But, again, in each of these basins, you see lots of follow-up potential. So the game is very much on in Kenya. And then our last slide, just as an example of some of the other activity that's going on in the new ventures team, the Caribbean-Guyanas Atlantic Margin position we've built up. It's turned into an industry hot spot. We were there ahead of the game; we continue to evolve our position there. We have acreage around the margins of three oil-prone basins: south offshore Jamaica; the Guyana basin offshore Suriname; and the Eastern Slope basin offshore French Guiana; proven oil systems. We've shipped it to the shelf to protect ourselves from these higher cost environments and the complex drilling and the over-pressures. We've got Spari drilling at the moment; should have a result from that in middle of August. But it's a story that's bigger than Spari; it's a story that's bigger than any individual prospect. This is a regional commanding position that we have in three oil-prone basins, and it's just one of the examples of the long holding options that we have in our exploration portfolio as we reset the business. So back over to Aidan for some conclusions. -------------------------------------------------------------------------------- Aidan Heavey, Tullow Oil plc - CEO [5] -------------------------------------------------------------------------------- Thanks, Angus. Obviously, a big issue is the oil price and where it is and I have no idea where the oil price is going to settle and, one thing for sure, nobody does. But people say this has happened before. I've been around for 30 years; this certainly hasn't happened before, and if anybody says they have experience of this current environment, they haven't. But one thing for sure is that there's a few fundamental things that you do when you are in a very unstable area and that is, you cut deep and you cut fast and we have completed that. We did it early and there's a lot of work that you can do to make the Company better, to make it more streamlined, to make it more efficient. Cutting costs for the sake of cutting costs is one thing, but you actually have to end up with a very efficient and well-run organization at the end of it. And we think we have achieved that in a very short space of time. We've managed to keep all the key staff; we've got a better system in the organization; we've got a better system of communication; we've got a better system of decision making. We have got a superb portfolio of assets, and those assets are profitable at very low oil prices. So while this uncertainty is there and, as I say, we have no idea when the market will stabilize, but one thing's for sure, it will stabilize at some stage in the future and you want to be prepared, to capitalize on that and to benefit more than anybody else. And I think we have done all the hard work; we've done the heavy lifting. There's a lot of things that are ongoing, and will be ongoing. We will continue to challenge costs: OpEx cost, CapEx cost and general overhead cost. We will continue to challenge and make sure that all the projects that we have get the maximum rate of return, and these are all obvious things that we need to do. It's a very difficult time for the investors, to look at when to actually invest in resource companies with this uncertainty. But all you can actually do is look at the companies that manage themselves in the best way possible and focus on cash. Very rarely do I comment on notes of analysts, but I thought James Hosie wrote there a few weeks ago was a really good note for shareholders to look at, what companies are doing in the current market. And the elephant in the room, it was a good mark of companies of what companies should be doing in their strategy, until such time as you have a stabilized market when you can sit down and put a proper strategy in place to move forward. We feel that the market will improve. We believe that the oil industry needs a higher oil price. We have been at the forefront of exploration in a lot of areas over the last few years. Oil is harder to find; it's in more difficult areas. The costs are not what they used to be, even with cost cutting. And the day for exploration will come again; it's not now, but it will come again. But I think we have to be prepared for it and be flexible, so when the market changes we will capitalize on it. All right, I'll hand you over to questions. Thank you. ================================================================================ Questions and Answers -------------------------------------------------------------------------------- Unidentified Company Representative [1] -------------------------------------------------------------------------------- Just as a reminder, can we have one question first and then we'll come back to questions at the end if there are further questions. -------------------------------------------------------------------------------- Jamie Maddock, Morgan Stanley - Analyst [2] -------------------------------------------------------------------------------- Jamie, Morgan Stanley. Just a point of clarification, and I appreciate that the hedges mean that you're less sensitive to the oil price, but is it safe to assume that we should use the forward curve when back-calculating that $1 billion of liquidity that you see at mid 2016 when TEN comes on stream? Is that a fair assessment? -------------------------------------------------------------------------------- Ian Springett, Tullow Oil plc - CFO [3] -------------------------------------------------------------------------------- Yes, I mean, if we look at our future projections, we use the forward curve as adjusted by the hedges we currently have in place. -------------------------------------------------------------------------------- Jamie Maddock, Morgan Stanley - Analyst [4] -------------------------------------------------------------------------------- So just to be clear, it was just when you say $1 billion of liquidity, clearly, the hedges desensitizes your future operating cash flow from results of the -- versus the forward curve. But if we were to use the forward curve and use those hedges, we would get to $1 billion-ish of liquidity from mid next year. -------------------------------------------------------------------------------- Ian Springett, Tullow Oil plc - CFO [5] -------------------------------------------------------------------------------- Absolutely correct. -------------------------------------------------------------------------------- Jamie Maddock, Morgan Stanley - Analyst [6] -------------------------------------------------------------------------------- Okay, great. Thanks. Cheers. -------------------------------------------------------------------------------- Mark Wilson, Jefferies - Analyst [7] -------------------------------------------------------------------------------- Mark Wilson, Jefferies. Can I just [pull] about the TEN plateau rate of 80,000, just exactly how you have confidence over that from the five producer wells you'll be coming on, and when do you need to start drilling again to keep that? -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [8] -------------------------------------------------------------------------------- So the base plan for TEN was that we would have the wells which we've drilled available to us to start up. In fact, we've got one; we'd planned on 10 wells and we've got 11 wells available to us as startup. And then the idea was we'd run the completions, as we're doing. And, depending on -- we've said startup will be around about the middle of 2016, and there's obviously a window around that, which I think, as we get to final results, we'll be in a better place to narrow that window. And the plan was that we would run out the completions on the West Leo rig and when we've finished the completion of all those wells, we would then restart drilling. But we wouldn't do a drill complete/drill complete. We would then drill a batch of two or three wells and then complete a batch because it's a lot more efficient from a capital perspective. So you run that out, the base plan said that we wouldn't have any additional wells until 1Q/early 2Q 2017, depending on how that program ran, how smoothly it ran. So if you then say, well, that's the plan, we plan to continue with that, and it's on track, then we expect to be able to ramp up, come on stream around middle of 2016 and with those wells, ramp up to plateau. Now, our ability to sustain plateau will then, obviously, depend on the performance of those initial wells, there's obviously a range around the performance potential, which we'll understand better when we start to see the wells perform, and then the timing of adding the additional wells. So if you're then take ITLOS into account, there's an early outcome -- well, there's three things that could happen. First being the Cote d'Ivoire and Ghana. We'll come to some sort of resolution ahead of ITLOS, which would allow us to then carry on with the drilling program. Obviously, it's not interrupting the project, it's not interrupting the completion program. So that's one opportunity, which means that I'd be highly confident. The second one is that ITLOS has a schedule which says you'll have an outcome, either early-ish in 2017 or late in 2017, depending on how that program runs within ITLOS, and that could be followed on the website. If the outcome is in the early part of 2017, then I do think we'll be able to, all things being equal and the wells perform as expected, we'll be able to ramp up and sustain. And then chances are we won't go to batch drilling. We'll drill one well, we'll complete it and get it on stream as quickly as possible to continue to maintain productivity. So I think we've got a reasonable chance of sustaining. We might have a minor dip, but more or less we should sustain. Clearly, if ITLOS outcome is late in 2017, our ability to sustain really relies a little bit on over-performance from the existing well set. And if that's the case then we may have a dip, but then we'll be able to get back to drilling later in 2017. And again, within 60 days of the announcement, we'll probably have another well on stream. So that's the facts, and how it plays out will not be clear until we see the performance of the wells and we understand how ITLOS outcome happens. -------------------------------------------------------------------------------- Dan Ekstein, UBS - Analyst [9] -------------------------------------------------------------------------------- Dan Ekstein, UBS. Just to clarify Jamie's question on debt headroom; could you tell us what your covenant headroom is under the same set of parameters, because they might be slightly different? -------------------------------------------------------------------------------- Ian Springett, Tullow Oil plc - CFO [10] -------------------------------------------------------------------------------- We have what we call a sculpted covenant, so we have projects of where, if you like, our EBITDA ratio will be, and then the covenant is on top of that. And I think it not entirely appropriate to [disclose], but that covenant excess is significantly above our current projection. So for example, when debt is at its peak, say, for example, in the middle of 2016, that covenant ratio is around 2 times greater than what we expect our net debt to EBITDA ratio to be at that point in time. It's a sculpted rate, so it kind of follows it up then follows it back down. -------------------------------------------------------------------------------- Dan Ekstein, UBS - Analyst [11] -------------------------------------------------------------------------------- Okay. And then just on Kenya, we're talking about a water flood development in fairly arid part of the world. Could you talk about the challenges there in terms of sourcing water, whether the aquifers will be sufficient, and some of the environmental sensitivities and how you mitigate those? Thanks. -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [12] -------------------------------------------------------------------------------- Yes, so both in Kenya and Uganda, the supply of water is an important aspect to the development. Actually, over in Uganda, when you look at the throughput of Lake Albert, it's massive relative to what we require. So really, the issue in Lake Albert is not a technical one, it's really one of perception. That's something we'll manage very carefully. The volume of offtake we require is a very tiny fraction of the throughput in terms of what flows in and out of Lake Albert. And we're looking at aquifer opportunities there as well, so Uganda is fine. In Kenya, the work is still ongoing. The Turkana Lake is more sensitive and different to Lake Albert. But there are other sources of water not so far away. So those aquifer sources -- and some of the geological work that Angus's team has been doing out there looking for water and mapping the aquifers has actually dramatically -- one of the problems we had early on in Kenya was just finding enough water to supply the rig. Now we've got wells which are easily supplying the rig, and they're producing dramatically higher water rates than we saw before. So we've seen a big step up on the subsurface, so we're looking at that and how far can you push that in terms of [failing in Africa]. And also, there are some other supply areas that are not so far away and wouldn't, in terms of the overall cost per barrel for CapEx, wouldn't then have very much in terms of bringing water supply in. And if we were actually to decide to bring water supply into the region, I say we don't see it as having a major impact on development cost. It has a broader kind of social, potentially positive aspect that you wouldn't just bring in what you need, you'd probably bring in excess of what you needed, so there was some positive benefit to the local environment. So I'd say in that area that we think of it as, elsewhere if you're sitting offshore Ghana, water injection is not a problem. There it is a major part of the development consideration. But we don't see it as a barrier to the development. It's just something that has to be managed incredibly carefully and thoughtfully. -------------------------------------------------------------------------------- David Mirzai, Societe Generale - Analyst [13] -------------------------------------------------------------------------------- David Mirzai, Soc Gen. I suppose a question for Ian and Aidan on just your final slide, where you're setting the business for lower oil price. On the one hand, you talk about net debt peaking next year probably in and around $5 billion; you're targeting net debt EBITDAX ratio of less than 2 times. On the other hand, on that slide if you're 100,000 barrels a day net production in and around that time, back of the envelope I'd say that you need a net back of $70 a barrel. So that's probably oil prices of $85 a barrel to meet your EBITDAX ratio of less than 2 times. I suppose the question is, what else would have to happen to the balance sheet if the oil price stayed at around $50 which is what, at the moment, you're planning for? -------------------------------------------------------------------------------- Ian Springett, Tullow Oil plc - CFO [14] -------------------------------------------------------------------------------- The first thing, David, we're not saying that we're going to get our net debt EBITDA ratio down to 2 times by the middle of 2016. What we are saying is that, as a business, having a net debt to EBITDA ratio of 2 times is saying that we've found an appropriate way to run the business in the past and we believe an appropriate way to run the business in the future. It gives us flexibility and headroom and an appropriate level of gearing. Periodically, there are times and conditions when you need to go above that and clearly, with the TEN development we needed to do that. But through a combination of managing the business and portfolio activity, then over the next two to three years, it is absolutely our intent to actually get that net debt EBITDAX ratio back down to those sorts of levels, and, to be honest, the quicker the better. And so our efforts will be very much focused around delivering that. -------------------------------------------------------------------------------- David Mirzai, Societe Generale - Analyst [15] -------------------------------------------------------------------------------- But the question remains, in a lower oil price environment your net backs wouldn't be high enough to be able to bring that down sufficiently in the next two or three years. -------------------------------------------------------------------------------- Ian Springett, Tullow Oil plc - CFO [16] -------------------------------------------------------------------------------- It's not just through ongoing cash flow from the business; it'll also be through portfolio activity as well. -------------------------------------------------------------------------------- Aidan Heavey, Tullow Oil plc - CEO [17] -------------------------------------------------------------------------------- We've an active portfolio management and that's part of the business. We've always said in the past, and it's not just oil sales and selling oil on a daily basis. We've a big portfolio of assets, and we've big percentage interests. It was never our intention to have a big percentage interest long term. -------------------------------------------------------------------------------- Alwyn Thomas, Nomura - Analyst [18] -------------------------------------------------------------------------------- [Alwyn Thomas, Nomura]. Just following on from the portfolio management, can I ask what level of capital you're willing to commit to East Africa on the Uganda and Kenya development, and perhaps how you see portfolio management around that? -------------------------------------------------------------------------------- Ian Springett, Tullow Oil plc - CFO [19] -------------------------------------------------------------------------------- I'll just say, generally, I think the decision on East Africa, and I think Paul's got a slide which he can show in terms of both the absolute amounts, I think you'll find both in terms of absolute amounts those amounts are going to come down. But obviously, the timing of those amounts is quite important to understand. Paul, do want to do a [background slide]? -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [20] -------------------------------------------------------------------------------- In slide 21 in the pack, we included -- obviously we've guided already on Uganda CapEx of $8 billion, which is the $6 a barrel and [a point or two] deflation should take that down by around 20%. We're still working so we haven't given clear guidance on Kenya capital yet, because we're still working that as we've got the appraisal results in. On the slide what I've tried to show is really the percentage build up. If you take a total 100% of full lifecycle expenditure, capital expenditure, on year one you're only spending about 10% of that. Year one and two you're spending about 30% combined of the total, [so] the ramp up. I suppose the point we're making there is that through a combination of reducing the absolute exposure, and then the timing, what it says, even if we were able to sanction at end of 2016 that's an ambitious target, but it's something we want to hang out there and get everyone to drive towards to. Then we'll see where it ends up and see how fast the politics move. But really, let's say you get it sanctioned in the first half of 2017, for example, what you're saying is it's not really until early 2018 that any serious amount of capital starts to build up, and even that [huge amount of] capital 10% of the total. So there's a long time between now and cash going out the door for us to look at opportunities to manage how we manage that capital exposure, and part of it is portfolio management. It's not something that's pressing, we need to get done in 2015. We will be putting a lot of energy into it over the next 12, 18 months, but time is not pressing. We've got quite a long timeframe before there's any significant amount of capital going out the door for East Africa. -------------------------------------------------------------------------------- Stephane Foucaud, FirstEnergy Capital - Analyst [21] -------------------------------------------------------------------------------- Stephane Foucaud, FirstEnergy Capital. You talk a lot about resetting the business on the low oil price; it seems it's a bit a waiting game until things get better. Are you considering things a bit more proactive in term of maximizing shareholder value today, which is perhaps shareholder [rotation], capital restructuring, some sort of corporate transaction one way or another. Could you perhaps provide some color? -------------------------------------------------------------------------------- Aidan Heavey, Tullow Oil plc - CEO [22] -------------------------------------------------------------------------------- The first thing you obviously do in resetting the business is get the cost structure and get the structure of the business right. From that point on, you look at every opportunity out there. But right now, it's such an uncertainty in the market that you really have to wait for some stability in the market and some understanding of where the oil price is going to go in the future. I don't think anybody is going to make any major decisions right now; it will be stupid. It's take what you have and make the best out of what you have right now and be efficient on it. Then when things stabilize fine, we'll look at where we are in the market and what the market looks like, and where we think it's going to go. But making long-term decisions like that now would be madness. -------------------------------------------------------------------------------- Brendan Warn, BMO Capital Markets - Analyst [23] -------------------------------------------------------------------------------- Brendan Warn, BMO. I think most of my questions on East Africa are answered, so I'll switch to another one. The $500 million you talk about over three years, is that all you can do; is that just the fat? What else could be implemented, and what sort of rig commitments roll off over the next 12, 18 months, or is that factored into the $500 million? -------------------------------------------------------------------------------- Ian Springett, Tullow Oil plc - CFO [24] -------------------------------------------------------------------------------- I'll start on the $500 million and Paul can talk about rigs and stuff. I think, Brendan, first of all the $500 million, just to be clear, the $500 million are, if you like, substantially Tullow internal costs. So they're costs of people, costs of things that they do in terms of whether it be using consultants, or travel expenses, all those sorts of things. But it's fundamentally costs attached to Tullow people as opposed to external costs. I'll let Paul talk about the external cost piece. We did approach that very much from a perspective of, let's look at what we can do to make the business more efficient, the business more simple. And then an outcome of that, to give a bit of granularity, is the $500 million and, obviously, a large number of people leaving the Company. That $500 million is spread over three years and it, effectively, benefits our operating costs, to an extent the internal costs are charged to operations. And already we can see some benefits of that already even in the first half of 2015. It benefits our net G&A, and already we can see that our net G&A for the first half of 2015 is less than it was for the first half of 2014, even though those numbers haven't really kicked off yet. It also benefits to an extent those costs or allocated CapEx, because when we talk about G&A, it is the total people cost of the Company for everybody, whether you're somebody who works in the head office, whether you're a driller, whether you're a geologist, a geophysicist out in the field, so it's a total people cost. We believe that what we've done there is both significant and appropriate. But we will still seek to manage costs at the margins, certainly around the external costs that those people attract and things like whether it be consulting costs or information systems costs, computing costs, so all those things. So I think that we've taken some pretty big steps in that regard on internal costs. And then, Paul, maybe you can talk about external costs? -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [25] -------------------------------------------------------------------------------- Yes. It's very important to clarify these are two different things, and they're both contributing to overall reduction in our OpEx and CapEx and the cost of doing business. So I think on the operating cost side, obviously part of our production of 30,000 barrels a day are other operators. So there, what are we doing? Well, we're sitting in OCMs and TCMs and pushing our other operators. And actually, we're not having to push that hard, because they're working as hard as we are at trying to find contractual savings and service cost savings, and marine savings and aviation savings. So that's ongoing. And as you'd expect, that's exactly what we're doing as an operator, and our partners are pushing us within Ghana. So that any cost that we save from our aviation or marine, or offshore chemicals, are very different to the $500 million, and they're in addition to the $500 million that Ian's talking about. And then, I think from the CapEx, obviously, as we've said fairly clearly, on something like TEN where you're fully contracted for the main part of the capital cost, there's a real limit to what you can do. So when I said at the beginning, what you're doing with something like that is saying, well, if I can't save money on TEN, how do I somehow benefit from the current environment. And so what we're seeing is, I was down in Singapore at the Jurong shipyard just two weeks ago, and Jurong's not as busy as it would have expected to be. So there's a lot more people on our vessel, trying to get the mechanical completion, which increases the chances of that sailing away, not just on time but with absolutely zero carryover. And if you can get it away from Singapore with zero carryover, it means all 120 beds on the vessel are available for the installation, so you can then start to accelerate [the rig]. So that's what's happening on TEN. It's not a cost game, it's more a schedule game, and how do we benefit and remove risk from the schedule. And then, I think we chose East Africa to highlight we have been looking at the development costs. We're looking at West Africa, because we've got a Jubilee full field development. When we start doing that, the rig capacity that we have will have completed its contract. So we'll be out looking at new rig contracts; we'll be looking at absolutely new service contracts. So what we've got to do is, if we're going to assume a $50, $60 barrel world looking out, we've got to make sure that the capital costs we're putting into the economics reflect that world. So we've done some independent studies to give us that data. And I've just flagged one part of that, which, on East Africa, this independent study says, if you go tender East Africa in 2016, early 2017, that sort of time, you should expect to see about a 20% or maybe more reduction in your capital tenders than what you would have seen if you'd gone out last year. Yes. -------------------------------------------------------------------------------- Brendan Warn, BMO Capital Markets - Analyst [26] -------------------------------------------------------------------------------- Just a follow-up question on that point. Would you be willing to pause the project before filing down, or would you actually take the cost savings and actually move into that project still at your 50% in Kenya, and 33% equity in Uganda? -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [27] -------------------------------------------------------------------------------- I think the job of work at the moment is to make sure we've got the option to sanction as soon as we can. And I think that should be our focus; we shouldn't worry too much beyond that at the moment, because I think if we don't have that option, we won't have the choice, and we won't have to worry about that question. So our job is to get it there and have it as an option. And then, I guess, as an executive management team and then a partnership, we'll sit and look at the project and decide, as a partnership and as an executive management team, whether we move ahead or we don't move ahead. But the key thing at the moment is make sure the option's there. -------------------------------------------------------------------------------- Aidan Heavey, Tullow Oil plc - CEO [28] -------------------------------------------------------------------------------- But FID is a fully financed project, and that means at the appropriate equity interest. I'm not quite sure we were fat now. We were slightly overweight, but we're aiming to become a finely tuned athlete. -------------------------------------------------------------------------------- Al Stanton, RBC Capital Markets - Analyst [29] -------------------------------------------------------------------------------- Al Stanton, RBC. In terms of the finely tuned athlete, and also the cash is king comment, is there any aspiration to ever generate free cash flow? The $400 million of exploration spend, is that driven by a percentage of cash flow, or is that driven by a number of wells? How do you now drive your budgets, going forward, based on the cash that's actually coming in? -------------------------------------------------------------------------------- Aidan Heavey, Tullow Oil plc - CEO [30] -------------------------------------------------------------------------------- The ultimate aim is to get a lot of free cash flow. And we have a very good portfolio of assets, as you've seen there in Paul's presentation, the mixture of assets that we have between West Africa and East Africa. They will throw out a lot of cash and a lot of free cash on production. And there will be some portfolio management, so it may not be that 200,000 barrels of oil a day that we actually keep. But we will throw out a lot of cash flow. And what we're saying is that the overall policy of the business is to get the gearing down to 2 times. That's what we're comfortable at as a long-term position. And we feel that the most efficient exploration program will be around $400 million. In the way that we model it, I know you guys model it slightly differently, but the way we model the business, which is an active business with active portfolio management, with active decision making, our business will throw out a huge amount of cash flow, once all these projects are on stream. And that will go back to shareholders. -------------------------------------------------------------------------------- James Hosie, Barclays - Analyst [31] -------------------------------------------------------------------------------- James Hosie, Barclays. Just a question on the 2016 CapEx guidance you've given us this morning. How much of that would you describe as committed at this point? And also, does that fully reflect the impact of the indirect cost savings you've outlined? -------------------------------------------------------------------------------- Ian Springett, Tullow Oil plc - CFO [32] -------------------------------------------------------------------------------- I think within the range, $1.2 billion to $1.4 billion, profit of $1.2 billion is probably more reflective of cost savings, James. I think if you look at the elements in that, finishing the TEN project off, the $500 million that you spend on TEN, by definition, is committed. The next piece of expenditure is circa $200 million, perhaps a bit less, on maintaining our non-operated West Africa production. So whilst not necessarily totally committed, I'd say that was kind of committed. You then move on to spend to maintain production and stuff at Jubilee, which is probably another $150 million, $200 million a year. So that's not really committed as such, but you tend to want to do that. And then you've probably got in the range of $150 million, $200 million to keep moving along predevelopment work for Uganda and Kenya. And the other $200 million is the exploration. So really the big chunk that's more formally committed is the $500 million for TEN. But once you've spent that TEN, you start to get into some reasonably discretionary spend. -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [33] -------------------------------------------------------------------------------- I think maybe what I'd add is that the other $200 million that Ian mentioned, so in West Africa, if we see another fall in oil price, then you would question that $200 million. So it's not committed in a way that you'd have to spend it all. I think we just see it, even at $60 those projects are profitable, so you'd probably look to try and do them. But in a more dramatic situation, we could choke back further. You can't choke the $200 million back to zero, but you might be able to get it back to $75 million or $100 million. So there are still levers to pull within that, if you chose to do so. And again, in Jubilee, you could choose not to add infill wells. We've got quite a lot of well capacity, and you just maybe take a little bit more risk on your well capacity. So there's choices out there. -------------------------------------------------------------------------------- Alex Topouzoglou, Exane BNP Paribas - Analyst [34] -------------------------------------------------------------------------------- Alex Topouzoglou, Exane BNP Paribas. So just coming back to something you were talking about earlier, about cost deflation; clearly, there's a lot of talk of cost reductions in the industry at the moment, generally focused on cost deflation. But do you see a further opportunity from simplification or reengineering of some of your projects to get savings beyond that 20%? And then on that, if you were to apply all of that to, say, to your MTA costs, where do you see those falling versus where they were 12, 18 months ago? Thanks. -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [35] -------------------------------------------------------------------------------- Yes, so with respect to, say, East Africa and I'll talk about Uganda because that's where we've given guidance, if you recall we were guiding originally about $11 billion for East Africa. And through fairly massive reengineering, we've brought that down to $8 billion which, if you divide it by the resources that will develop in that first full phase of about [$1.3 billion, $1.35 billion], you've got $8 billion divided by [$1.3 billion] gives you about $6 a barrel. So is there another phase of reengineering? You'll always optimize, but whether we could get another significant reduction I think we've done maybe the majority of that. You'll always look try and optimize it, so maybe some phasing you could do on timing. So I think I based at the $6 plus a 20%. The question is, is 20% aggressive enough, and some of the data we've had back would suggest it could be even further than that. I think a 20% is probably sensible position to take at the moment. We've got the independent data for West Africa and we're working that at the moment, so as I said, I don't really have numbers. But, if you look at Jubilee, if you say an incremental well drilled and completed in the world we were in was circa $90 million or $100 million, and that was on a rig rate of, say, $610,000 $615,000 a day. Deepwater rig rates at the moment are sitting around $300,000 a day, and so that $90 million is directly correlated. Your service costs, that took the [$600 million] to maybe $1.1 billion, so let's call it $600 million and $600 million and make life easy. The rig rates come down by 50%. The service costs have not come down by 50% but maybe they've come down by 25%. So if you factor that into that's the new day rate and then multiply it by the same number of days, that gives you the answer for the incremental wells which are a major part of FFD. A big part of it is just adding wells, so they could be 40% down, 35%, 40% down on costs from where we've been. And then I think the subsea market is still settling. I see we've got some data on it, but I think we've got maybe another six, nine months to truly understand where costs will go in the subsea market, which is timely enough for us in terms of looking out on Jubilee and the further expansion TEN. So it'll be material. -------------------------------------------------------------------------------- Richard Griffith, Canaccord Genuity - Analyst [36] -------------------------------------------------------------------------------- Richard Griffith, Canaccord. I think you've just more or less answered my question which is, BP yesterday talked about Mad Dog Phase II, which I know is deepwater, it's a lot of rig components. But they've taken 50% of the capital out of that in two cycles of rephasing, reengineering and deflation. But they have sacrificed about 10% of the resource. So I get the impression from just your last comments you're already going through those steps. I'm just wondering how much further can you go because they talk about deflation continuing through to mid 2016 which would suggest that, from their point of view, they're not going to sanction anything probably until sometime after they see what they believe is the bottom. So from your planning point of view, can you get any more phases reductions, and I think you've already said that? And secondly, does that mean you're not really going to sanction anything until probably 2017? -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [37] -------------------------------------------------------------------------------- I think the two big pieces we've got are really Jubilee, full field phase, full field, and East Africa. And I think Jubilee, we will be submitting the development plan late this year, and then we'll be in some discussion with government. So really, that's not going to sanction until well into next year anyway. And, I think, the data we suggest is not dissimilar to what you say, that it's coming down, and I say I think there's more of a lag on the deepwater and the subsea than there is on some of the onshore, by chance. So I think the timing of our projects are such that we're not going to have to delay them to capture most of the cost, I don't believe. But, again, I think we'd say the same as BP; if you could see another 15% cost saving by delaying by six months, I think you'd absolutely delay it by six months. -------------------------------------------------------------------------------- Michael Alsford, Citi - Analyst [38] -------------------------------------------------------------------------------- Michael Alsford, Citi. Just a question on East Africa. I guess one of the key events to derisk and increase the viability of Kenya and Uganda is the pipeline route. You mentioned in your comments that you think Q3 is when the governments will agree on that pipeline route. Can you give us some view on that confidence on that timeline? When you talk to partners across the fence some have different views as to which pipeline route is the most viable. And so can you give us confidence on that timeline and what are the key issues that are still outstanding? Thanks. -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [39] -------------------------------------------------------------------------------- The confidence on the timing is a hard one in East Africa, as history would tell you. So all I can say is that all the data is there and all the analysis has been done, and that's both by the JV partners and by the governments' independent consultant, so there's really no more work in analysis that's required. All that's required is a decision. The challenge with certainly a decision means that it could be a decision tomorrow, or they may decide to delay that decision for various political reasons because there's political discussion for another month or another two months. So it's difficult to call, but what I would say is I don't see any more work or data required to submit to the government to allow them to make that decision. I think it's more a political dialogue between Uganda and Kenya about really what is the most appropriate for the region. With regard to our view, as Tullow, we see both routes as viable, and really we present it that way to government, that both are viable. Actually, the cost base for both routes is very similar so, therefore, we feel it's probably more likely to be a political decision rather than one that the JV partners are going to make, so we'll await the outcome. -------------------------------------------------------------------------------- Michael Alsford, Citi - Analyst [40] -------------------------------------------------------------------------------- Just on that, Paul, I know you're in both projects but other partners aren't, so what happens in a scenario where one partner in, say, Uganda doesn't want the northern route, and another partner in Kenya wants the southern route? How does that get solved? -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [41] -------------------------------------------------------------------------------- We look at it from both sides. We've got the benefit of looking at it from a Kenya side and a Uganda side, and I would say that Tullow Kenya part, of me or the Tullow Uganda part of me, has the same view. Both are viable and actually from a cost base, both, it doesn't make much difference. If you're sitting in Uganda you could go north, if you go south and actually the cost to you in Uganda is similar, and if you're sitting in Kenya you can link down to a line in the south, and it's not so different either. So I don't think there's a great difference between a Kenya JV view and a Uganda JV view. There might be some different views from the individual parties, but I think ultimately, our view is that what's important to us is that we see both as viable, and there's no cost detriment to the partnerships by going with one or the other; therefore, we feel ultimately it's going to be in the hands of government to determine, and then we're going to have to work with the outcome. -------------------------------------------------------------------------------- Thomas Martin, Numis - Analyst [42] -------------------------------------------------------------------------------- [Thomas Martin, Numis]. Just had a very simple question really on Jubilee on the compressor issues. Can you tell us a bit more about what exactly has happened and how you stop this from happening in the future? Is it a maintenance problem, is it an operational problem? And I think you've got two compression trains there, so how did they both end up getting affected in one go? -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [43] -------------------------------------------------------------------------------- I'll try not to go into too much [depth here], but effectively the compression trains they're made up of various components. As the gas goes into the compressor it gets cooled in a cooling system. Now, we had some problem with the cooling system. The A cooling system has been running fine, we got that. It just so happened right now, the B cooling system is down as we are going through some maintenance, and we're awaiting some long lead items to change out both to upgrade both cooling systems. So we were sitting at the trading statement with the A train running both compressors available, but only the A cooler system available, if that makes sense so you get two [parts] of the trains. When the A compressor went down, what was the problem with the A compressor it just came down on high vibration so there was some misalignment of the internals. And when we tried to restart, the safety system stopped it from restarting. So we looked at it and decided the quickest thing to do was just to do a major overhaul, take the inside out, put a new inside in and restart it. And we have all those spares available to us. So all we've been doing over the last two or three weeks is mobilizing the people, mobilizing the kit and we're well advanced. And the old one's out, the new one's in and they're starting to bolt things back together again. And then we'll restart and they will be up and running. We won't really fully understand why we had that high vibration until we do the forensic analysis of the stuff we took out the center of the compressor. So I can't answer the question as to why did that compressor -- but it can happen, which is why you have a whole set of spares sitting on the beach ready to go. These are fairly highly sophisticated, highly tuned pieces of kit. So that's the answer that I can give you for the compressor. And the whole idea of having two trains is that if that one fails, you start up the other one. Unfortunately, the cooling system was down on the other one and it will become available again, but not in time to allow us to run the B train rather than the A. -------------------------------------------------------------------------------- Thomas Martin, Numis - Analyst [44] -------------------------------------------------------------------------------- So there's no (inaudible)? -------------------------------------------------------------------------------- Angus McCoss, Tullow Oil plc - Exploration Director [45] -------------------------------------------------------------------------------- No, as I say, generally when things fail, you go and do the forensic analysis and you understand why they failed. And then it might lead to some opportunities that you fine tune it and you run it slightly differently. But there's nothing -- these are just fairly standard high pressure gas compressors from one of the major vendors. There's nothing particularly special about them. -------------------------------------------------------------------------------- Ed Maravanyika, BofA Merrill Lynch - Analyst [46] -------------------------------------------------------------------------------- Ed Maravanyika, BAML. It's a question more for Ian. For 2016 first half, what does your entitlement sales hedging look like? And have you been adding to the hedge book during the first half of this year? -------------------------------------------------------------------------------- Ian Springett, Tullow Oil plc - CFO [47] -------------------------------------------------------------------------------- Yes, the answer is we're always adding to the hedge book. We do it on a very kind of ratable basis. So our view is that what we're trying to do is protect volatility, protect ourselves against volatility, give ourselves debt capacity to both protect against the downside, but also give us access and not lose the upside. The barrels that you see on slide 12 are, effectively, the barrels that we have in place at the moment. And these are entitlement volumes on slide 12. So in 2016, we've got 31,257 barrels we precise hedged. And the downside protection of that is just over $79 a barrel. And we are just beginning to start layering in volumes in anticipation of TEN production, so that's what we're doing. But it's very much an ongoing program. It's not a stop/start program, and even though oil prices are low, it still absolutely makes sense in our view to continue that hedging and create that collared position. -------------------------------------------------------------------------------- Operator [48] -------------------------------------------------------------------------------- (Operator Instructions). Anish Kapadia, TPH. -------------------------------------------------------------------------------- Anish Kapadia, Tudor Pickering Holt - Analyst [49] -------------------------------------------------------------------------------- Just a couple of questions. You've got a pretty significant decommissioning liability, over $1 billion. And given the lower oil price scenario, I was wondering if this may accelerate decommissioning with assets like Chinguetti in the UK North Sea. And how do you and your lending banks think about this and the potential costs over the next few years? And then the second question was just on the exploration side of things. We've seen some discoveries in and around some of your current and previous positions in Senegal, Mauritania, just wondering what your thoughts are around those and whether you're reevaluating any of your geological models for the areas. Thank you. -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [50] -------------------------------------------------------------------------------- Maybe if I pick up on the decom timing and then Ian can talk about the financial side of it. The current price -- Chinguetti is close to the end of its field life anyway, so there might be some minor impact on a six-month basis around Chinguetti but nothing too major. All the other fields that we have are either young fields, with a long life ahead of them, and the West African portfolio is all pretty mid-mature. And even the maturer part of that is actually mainly onshore Gabon, where we're still infilling and adding capacity, so there's nothing really there. And then within the UK sector, we're actually decommissioning the older part of that as it is, which is the Thames area. That's ongoing successfully. I didn't mention it today, but that's successfully going on in the background. And the CMS, gas pricing has been relatively stable, so I don't think it will really change much timing on the CMS area of the North Sea. -------------------------------------------------------------------------------- Ian Springett, Tullow Oil plc - CFO [51] -------------------------------------------------------------------------------- And I think in terms of cost, we did quite a detailed study last year to look at our decommissioning costs and actually increase -- actually at that time, it was probably less about the unit cost but more about how long it would take to and how many days it would take to decommission various facilities. So actually, our decommissioning costs were increased -- the provisions were increased last year. And I would say that, whilst they had some sight of lower unit costs, going forward, they probably don't fully reflect the market as we see it today. So I would hope that, in the fullness of time, you will see those decommissioning costs probably, if market conditions persist to the time that decommissioning actually occurs, to be perhaps lower than we've currently provided. -------------------------------------------------------------------------------- Angus McCoss, Tullow Oil plc - Exploration Director [52] -------------------------------------------------------------------------------- It's Angus here. On the exploration discoveries recently in Senegal and Mauritania, they're very much in line with our strategy and tactics in those areas. If you recall, recently there was a discovery, FAN-1 in turbidites in deepwater, Senegal. That's very, very similar to our Fregate-1 discovery in Mauritania; same play, same idea, more or less same result. Then last year, we talked about our tactic to adapt the business environment to shift to shelf edge. We have a string of pearls along the shelf edge in Mauritania. We have yet to drill them, but our peer companies have been drilling on one of those; SNE-1 at Senegal came in, so it proves the concept. We subscribe to that concept as well. It helps derisk our inventory, so it's looking good. And then the other discovery recently was the Tortue-1 deepwater gas discovery. That's one of our off-limits types of plays, but it occurred in part of the basin that we predicted would be gas prone. And we have focused our acreage to the north of that, which we have perceived to be oil prone and has, indeed, been proven to be oil prone through the oil that we found in Fregate. So we're very much in play, on target with these neighboring results and very much in line with what we expect. And we're sitting on some really hot properties with respect to those. -------------------------------------------------------------------------------- Anish Kapadia, Tudor Pickering Holt - Analyst [53] -------------------------------------------------------------------------------- Thanks. You didn't mention Guinea; is that still in your plans? Is that potentially being drilled next year? -------------------------------------------------------------------------------- Angus McCoss, Tullow Oil plc - Exploration Director [54] -------------------------------------------------------------------------------- That's right. In Guinea, it's a sort of Jubilee class prospect. We have that prospect lined up; it's a solid option that we're considering. We've got some operational things just to clear up there, Ebola being one of them. But the prospect's certainly good to go; it's a strong prospect. -------------------------------------------------------------------------------- Anish Kapadia, Tudor Pickering Holt - Analyst [55] -------------------------------------------------------------------------------- Thank you. -------------------------------------------------------------------------------- Operator [56] -------------------------------------------------------------------------------- Thomas Adolff, Credit Suisse. -------------------------------------------------------------------------------- Thomas Adolff, Credit Suisse - Analyst [57] -------------------------------------------------------------------------------- I've got two questions, please. One on the portfolio again, and the second one on TEN. Firstly on the portfolio, once TEN is on stream by the middle of next year, what sort of portfolio shaping moves do you think is necessary to really hit the sweet spot of value creation and risk for the Company? Secondly, in terms of TEN and you have a good track record bringing projects online on time, e.g., Jubilee, how should I think about the pace of ramp up to plateau? Presumably, this will be faster than Jubilee because you have the wells drilled and you have the subsea equipment in place by first oil. Thank you. -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [58] -------------------------------------------------------------------------------- I'll take the second one first and then -- the TEN ramp up, I think we've guided we'll be in plateau early 2017. And so nothing has changed on that. The pace at which we ramp up will be very much dependent upon the progress of the well completions. If you imagine, we've got a line of sight out to the well completions over the next 16 months through to third quarter 2016. I'd say the earlier we start up the field, probably the longer the ramp up because, if we do manage to start up early in the window, we won't have as many completions available to us. If we start up at the end of the window, then we'll have more. So it's kind of dependent upon that interaction between what's the actual timing of first oil, versus how many completions you have available. But ultimately, we're guiding early 2017 to be up at plateau. -------------------------------------------------------------------------------- Ian Springett, Tullow Oil plc - CFO [59] -------------------------------------------------------------------------------- And I think on the portfolio it's kind of a broad question. What I'd say is, one or two thoughts. Certainly, I think our view generally is that where we're operator but we'd like to be in that sort of 30%, 35% capital level is a place where we like to be. So if you think of some of our [equity] percentages that's where we'd like to be. I think always we need to be in a place where our spend and our equity within a project makes sense and fits within our funding capabilities, etc. And I think also there is probably never that magic day when you sell something for its maximum value, but obviously somewhere between sanctioning a project and first production and established production on stream is kind of the right window, if you like. It really depends on the project. But I think, as Aidan said and I think we've all said, that TEN in itself is a major source of deleveraging, going forwards, but also a portfolio activity too and that's something that we, by definition, are looking at quite strongly. But obviously, it's something we can't particularly talk about until we actually do a deal. -------------------------------------------------------------------------------- Thomas Adolff, Credit Suisse - Analyst [60] -------------------------------------------------------------------------------- Just to go back on the portfolio question, perhaps to dig into a bit more detail, how do you feel about concentration risk? How do you feel about the share of value coming from producing stuff which, from an NAV accretion perspective as you roll forward, isn't really where you may generate a lot of value. And so in the context of that, how do you balance it? -------------------------------------------------------------------------------- Ian Springett, Tullow Oil plc - CFO [61] -------------------------------------------------------------------------------- I think that, certainly from a concentration risk, obviously we're aware of where our major assets are and we recognize that we do have concentration risk in Africa and in certain countries. At the same time, Africa is a place that we think there is good value proposition and somewhere where we're very happy to operate. In terms of the balance between exploration and development activities, then we are wishing to be seen, indeed think we are. We are neither an exploration company nor a development company; we're an exploration and production development company, both. We try to get the balance right between the two. There are times when it makes sense to spend a bit more on exploration and times it makes sense to spend a bit more on development. That is the function also of, obviously, both economic conditions and what you spend. But I think our mantra remains that the best place to find oil and create high margin cash flow is oil that you've discovered yourself. So it's an ongoing balance and something we look at each year in our business plan cycle. -------------------------------------------------------------------------------- Thomas Adolff, Credit Suisse - Analyst [62] -------------------------------------------------------------------------------- Okay. Thank you. -------------------------------------------------------------------------------- Aidan Heavey, Tullow Oil plc - CEO [63] -------------------------------------------------------------------------------- Part of looking at the portfolio, there's always been a mature field versus young fields which have a lot of upside, and we're very fortunate as most of the fields that we have we found ourselves. They are still at the early stage of adding value. Jubilee, TEN, East Africa, all of these areas are still at the early stages. Normally, companies would look at selling [less] mature fields. There is a natural cycle, but I think from the point of view -- go back to the fact that this is a very unstable market and one of the areas that has stopped companies doing deals in the future has been their view of value of assets versus the market's view at a particular time. And sometimes, you have to take decisions which are better for the overall gearing of the company and the balance of the company. Also, as a Board of the Company, we have to look at where our spread of risks. So these are natural things that companies will do all the time; it's not necessarily value driven at any one point. -------------------------------------------------------------------------------- Thomas Adolff, Credit Suisse - Analyst [64] -------------------------------------------------------------------------------- Perfect. Thank you very much. -------------------------------------------------------------------------------- Operator [65] -------------------------------------------------------------------------------- Gerry Hennigan, Goodbody. -------------------------------------------------------------------------------- Gerry Hennigan, Goodbody Stockbrokers - Analyst [66] -------------------------------------------------------------------------------- A question for Paul, if I can? Paul, if you can just give us some sort of idea in terms of the ability of the Ghanaians to process gas onshore, given that there were some teething problems earlier in the cycle? And I ask the question in the context of obviously follow-on developments with TEN and the greater Jubilee area. And also, this may be a difficult one for you to answer, but what's your best estimate in terms of when oil may flow from Kenya and Uganda? -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [67] -------------------------------------------------------------------------------- On the first one, I think as I said earlier, one of our big concerns in the first half was the sustainability of the gas plant onshore. And what the team Ghana Gas has shown is they were taking around 80 million a day and they were taking it very steadily, and that was really, as you saw from the first half's delivery from Jubilee above what we expected. A part of that was because we were managing to stably export gas onshore. So I think what that's demonstrated is that we can rely on onshore gas processing. And certainly the VRA at the moment, the power station, we're very close to start to thinking about ramping up from 80 million to 100 million a day. So I think as we look forward, gas will always be a part of any year. So as we look at Jubilee full field and the expansion of the FPSO, one of the factors is the capacity of that onshore gas plant and any need to expand the gas plant. But that will be easier than some of the teething problems we had just getting the gas plant there in the first place. Any expansion of it I think will be very much secondary in terms of difficulty. And with respect to the East Africa first oil, I think what I can say it's probably going to be about 3 to 3.5 years after we sanction the project. -------------------------------------------------------------------------------- Gerry Hennigan, Goodbody Stockbrokers - Analyst [68] -------------------------------------------------------------------------------- You'd say it was around about a 2020 timeframe at least? -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [69] -------------------------------------------------------------------------------- It's going to be around then, yes. -------------------------------------------------------------------------------- Gerry Hennigan, Goodbody Stockbrokers - Analyst [70] -------------------------------------------------------------------------------- Okay. Thanks very much. -------------------------------------------------------------------------------- Operator [71] -------------------------------------------------------------------------------- [Peter Ofus, Ironshield Capital]. -------------------------------------------------------------------------------- Peter Ofus, Ironshield Capital - Analyst [72] -------------------------------------------------------------------------------- You said before that most of your cost savings came really from internal costs. Just following up on this, how much flexibility do you have in your current, either drilling or FPSO contracts or in the contracts with your other contractors, in terms of either the rate for negotiation or [just tendering] the scope. And I appreciate this might not be in the very short term, but is there any flexibility and how do you think about the timeframe? Thank you. -------------------------------------------------------------------------------- Paul McDade, Tullow Oil plc - COO [73] -------------------------------------------------------------------------------- I think all of those -- the one that's easy to pin down, as Ina's highlighted, the $500 million of our own cost, because we actually took swift action and we've put that in place and we can now easily forecast what our cost base will be in terms of Tullow internal costs over the next two, three years, which gives us the confidence to say that we will deliver the $500 million. With respect to the other external costs, such as our operation in the maintenance contracts, or service contracts with the main contractors as they service the FPSO and Jubilee or our rigs, basically that's an ongoing piece of work. So in some of the rigs onshore we've sat down with contractors and said, we'll either change out the supplier or we'll sit down and renegotiate the contract. And generally, when you have that conversation -- because these are just service contracts. Generally, they're not fixed term contracts or fixed volume contracts. They're just a contract agree that we will take a service at this price, which means that we don't need to take any service; what we can do is switch over to someone else. So in that sense, that's an ongoing piece but obviously, one part of it's cost; the other part of it's service. So one of your key factors is having a good strong positive relationship with your contractors. And I think that's something that we've gone about in an orderly manner. I don't really think it's that helpful just firing out a letter to all your contractors saying we want you reduce by 20% because one, you'll damage relationship and you might not get what you're looking for. So we've been going through that, but there are material savings, which is why we feel that in somewhere like -- we benchmarked Jubilee about 1.5 years ago and it was top quartile in its delivery in many areas for the operating performance and cost. So we were doing pretty well already, but we are seeing those costs are coming down, which is why we're projecting a full year of $9 a barrel, which is reasonably significant. So there's opportunities out there and we're working them all. -------------------------------------------------------------------------------- Peter Ofus, Ironshield Capital - Analyst [74] -------------------------------------------------------------------------------- Thank you. And just following up on this very quickly -- -------------------------------------------------------------------------------- Unidentified Company Representative [75] -------------------------------------------------------------------------------- Thank you very much. If you have any further questions, please feel free to get in touch with the Investor Relations department. Thank you.

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